220 NW Second Avenue
Portland, Oregon 97209
www.nwnatural.com
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2004 Annual Report
Ahead of
the curve
Corporate Profile
NW Natural is a 146-year-old
natural gas local distribution company
headquartered in Portland, Oregon.
The Company has added customers
at a rate of 3 percent or more per year
for 18 consecutive years.
NW Natural serves about 600,000
customers in Oregon and southwest
Washington, including the Portland-
Vancouver metropolitan area, the
Willamette Valley, the northern Oregon
coast and the Columbia River Gorge.
More than 200,000 customers have
been added to NW Natural’s distribu-
tion system in the past 10 years.
In keeping with its steady growth,
the Company has increased annual
dividends paid to shareholders every
year for 49 consecutive years.
NW Natural purchases natural gas
for its core market from a variety of
suppliers in the western United States
and Canada. The Company also
operates an underground gas storage
facility in Columbia County, Oregon,
and contracts for additional gas storage
outside its service area. NW Natural
operates two liquefied natural gas
plants in its service area. The Company
also provides interstate storage services
to other energy companies in the
Northwest interstate market, using
capacity that has been developed in
advance of its core customers’ needs.
Service Territory
Earnings
Financial facts ($000):
Net operating revenues
Net income
Earnings aplicable to common stock
Financial ratios (%):
Return on average common equity
Capital structure at year-end
Long-term debt
Preferred and preference stock
Common stock equity
Common stock
Shareholder data:
Common shareholders
Average shares outstanding (000)
Per share data ($):
Basic earnings
Diluted earnings
Dividends paid on common stock
Book value at year-end
Market value at year-end
Operating highlights
Gas sales and transportation deliveries
(000 therms)
Degree days (25-year average, 4,202)
Customers at year-end
Number of utility employees
Dividends paid on common stock
Payment date (per share)
February 15
May 15
August 15
November 15
Total dividends paid
2004
2003
Percent
increase
(decrease)
7
10
11
1
(3)
5
6
6
2
6
10
3
(3)
3
–
308,360
50,572
50,572
288,066
45,983
45,689
9.4
46.0
–
54.0
9.3
49.7
–
50.3
9,359
27,016
9,695
25,741
1.87
1.86
1.30
20.64
33.74
1.77
1.76
1.27
19.52
30.75
1,131,866 1,099,752
3,952
578,150
1,291
3,853
596,635
1,288
2004
2003
$ 0.325 $ 0.315
$ 0.325 $ 0.315
$ 0.325 $ 0.315
$ 0.325 $ 0.325
________ ________
$ 1.300 $ 1.270
________ ________
________ ________
Astoria
Mist
WASHINGTON
Vancouver
Portland
Molalla
The Dalles
Salem
Lincoln
City
Newport
Albany
Eugene
Coos Bay
OREGON
Legend
Williams Gas Pipeline
NW Natural gas
transmission line
Kelso Beaver
(KB) Pipeline
Coos County Pipeline
Service territory
LNG plant
District offices
Mist underground
storage
$1.30
$1.29
$1.28
$1.27
$1.26
$1.25
$1.24
$1.23
$1.22
$1.21
$1.20
DIVIDENDS PAID
PER SHARE
IN DOLLARS
DILUTED EARNINGS
PER SHARE
IN DOLLARS
$2.00
$1.75
$1.50
$1.25
$1.00
$0.75
$0.50
$0.25
On the cover: A NW Natural truck strikes out
for new territory — the southern Oregon coast.
Coos County residents welcomed natural gas
service to their communities in 2004.
Annual dividends paid per share
in 2004 increased for the 49th
consecutive year, a growth record
matched by few companies.
Diluted earnings per share were
$1.86 per share in 2004, up 6
percent over 2003.
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Corporate Information
Notice of Annual Meeting
The 2005 Annual Meeting will be held at
2 p.m., Thursday, May 26, in the Colonel
Lindbergh Room of the Embassy Suites
Hotel, 319 S.W. Pine Street, Portland,
Oregon. A meeting notice and proxy
statement will be sent to all shareholders
in mid-April.
Stock Transfer Agent and Registrar
For the Common Stock:
American Stock Transfer & Trust Company
59 Maiden Lane
New York, New York 10038
Telephone: (888) 777-0321
Internet: www.amstock.com
E-mail: info@amstock.com
Trustee, Conversion and Interest
Paying Agent
For Convertible Debentures:
The Bank of New York
Corporate Debt Operations, Floor 7-E
101 Barclay Street
New York, New York 10286
(800) 548-5075
Trustee and Bond Paying Agent
For all bond issues:
DB Services Tennessee Inc.
Security Holder Relations
P.O. Box 305050
Nashville, Tennessee 37230
(800) 735-7777
Dividend Reinvestment Plan
Common shareholders of record may
reinvest all or part of their dividends in
additional shares under the Company’s
plan. Cash purchases also may be made at
the current market price under this plan,
and no brokerage fees will be charged. A
prospectus will be sent to any registered
shareholder on request.
Dividend Payment Dates
February 15, 2005
May 13, 2005
August 15, 2005
November 15, 2005
Common Stock Prices
The Company’s common stock is listed
and trades on the New York Stock
Exchange (NYSE) under the symbol NWN.
The quarterly high and low trading range
during 2003 and 2004 was:
2004
Quarter
1
2
3
4
High
$ 33.00
31.65
32.37
34.13
Low
$ 29.95
27.46
28.84
30.77
2003
Quarter
1
2
3
4
High
$ 28.47
28.88
30.11
31.30
Low
$ 24.05
24.77
27.02
28.51
Certifications
The Chief Executive Officer certified to the
NYSE on June 7, 2004 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 has
filed with the Securities and Exchange
Commission, as exhibits 31.1 and 31.2 to
its Annual Report on Form 10-K for the
year ended Dec. 31, 2004, the certificates
of the Chief Executive Officer and the
Chief Financial Officer of the Company
certifying the quality of the Company’s
public disclosure.
Request for Publications
The following publications may be
obtained without charge by contacting
the Corporate Secretary:
Annual Report
Form 10-K
Form 10-Q
Corporate Governance Standards
Director Independence Standards
Code of Ethics
Board Committee Charters
These publications, as well as other filings
made with the Securities and Exchange
Commission, also are available on NW
Natural’s web site at www.nwnatural.com.
Quarterly Financial Information (unaudited)
Dollars
(thousands except per share amounts)
March 31
———————— Quarter ended ————————
June 30
Sept. 30
Dec. 31
Total
2004
Operating revenues
Net operating revenues
Net income (loss)
Basic earnings (loss) per share
Diluted earnings (loss) per share
2003
Operating revenues
Net operating revenues
Net income (loss)
Basic earnings (loss) per share
Diluted earnings (loss) per share
$ 254,450 $ 106,659 $
112,034
32,612
1.26
1.24
52,629
(716)
(0.03)
(0.03)
81,441 $ 262,054 $ 704,604
308,360
39,483
50,572
(8,285)
1.87*
(0.30)
1.86*
(0.30)
104,214
26,961
0.98
0.97
$ 206,539 $ 117,489 $
98,588
26,404
1.03
1.01
58,549
4,462
0.17
0.17
69,481 $ 217,747 $ 611,256
288,066
91,464
39,465
45,983
21,663
(6,546)
1.77*
0.84
(0.25)
1.76*
0.83
(0.25)
*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
the Company’s business.
Shareholder Information
James R. Boehlke
Investor Relations
(503) 721-2451
(800) 422-4012,
Ext. 2451
jrb@nwnatural.com
Carol M. Frary
Shareholder Services
(503) 220-2590
(800) 422-4012,
Ext. 3412
cmf@nwnatural.com
220 N.W. Second Avenue
Portland, Oregon 97209
(503) 226-4211
(800) 422-4012
www.nwnatural.com
Contact the NW Natural Board
Concerns may be directed to the
non-management directors as follows:
■ Call 1-800-541-9967, or
■ Write to NW Natural Board of
Directors, c/o Corporate Secretary, or
■ Email Directors@nwnatural.com
Forward-looking Statements
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 Securities and Exchange
Commission on Forms 10-K and 10-Q.
Ahead of
the curve
The right source of energy affects so
many lives in so many ways. By providing
the best in natural gas service, NW Natural
enhances the lives of everyone from chefs,
to swimmers, to children playing in the
park. In 2004, even horses stood to benefit.
Because we manage our business ahead
of the curve, we put our customers a step
ahead as well.
New Technology
p10
“ The microturbine in our Swim
Pavilion not only operates faultlessly,
but its performance is beyond our
expectations. It’s a working example
we use to teach students about the
potential for energy conservation
and efficiency.”
– Dr. Richard Bettega
Associate Vice President for Facilities,
Lewis & Clark College
Coos Bay Opening
p8
“ The cost of propane has been
ridiculous, heinous and prohibitive.
Fuel is my biggest expense in the
winter. Propane costs me hundreds
of dollars a month. I’ve been
saying for over a year, ‘I can’t
wait until NW Natural gets here.’”
– Elizabeth Kinzie
Owner, Elizabeth’s
South Mist
Pipeline
p14
“ NW Natural’s crews
were wonderful and
very efficient. They
cleared 16 trees and
moved the logs to our back
pasture where we’ll use them to
develop a cross-country course
for event competition. We could
not have done this without
their help.”
– Vicky Carr
Owner and President, Sherwood
Forest Equestrian Center, Inc.
Energy Efficiency
p12
“ NW Natural’s employees are great:
professional, helpful and always
ready to serve with knowledge and
good humor. With their help, we’ve
turned a pizza oven into a model for
energy conservation and sustainable
business practices.”
– David Yudkin
Owner, Hot Lips Pizza
Letter to Shareholders
2
Interview with the Senior Vice President 5
18
Management’s Discussion & Analysis
Management’s Report on
Internal Control
Report of Independent Registered
Public Accounting Firm
Financial Statements
Notes to Financial Statements
Eleven-Year Financial Review
Board of Directors
Corporate Officers
Corporate Information
32
33
34
39
54
62
64
65
Customer Growth
p16
“We’ve worked with
NW Natural on all
our River District
projects—nine buildings in
seven years! Gas cooktops and
fireplaces are the type of valued
features that draw customers to
our condominium developments.”
– Sue Miller
Vice President and Project Specialist,
Hoyt Street Properties
Letter to Shareholders
Earning
the right to grow
Mark Dodson, President and CEO, at the site of the Sherwood, Oregon, intertie of the South Mist Pipeline Extension.
Completed five weeks ahead of schedule, it was the largest capital project in company history and is now included in
Oregon and Washington rates.
T o Our Shareholders:
In 2004, the years of planning and
hard work paid off.
NW Natural saw the culmination of
several landmark construction projects
and key regulatory changes. Each
required years of planning and analy-
sis. Each demanded solid execution.
Each added to our earnings and cash
flows in 2004 and will continue to in-
crease our value in the years ahead.
NW Natural has dedicated itself
to getting ahead of the curve and has
succeeded in many ways. The evidence
of that can be seen not just in the
Company’s 2004 performance but
also in the strong platform for growth
it has created for 2005 and beyond.
Highlights of the year
In 2004, NW Natural:
■ Earned $1.86 a diluted share, com-
pared to $1.76 in 2003, a solid 5.7
percent increase;
2
■ Completed the South Mist Pipeline
extension — and began recovering its
costs in rates;
■ Successfully completed a general
rate case in Washington;
■ Began serving customers in Coos
County, Oregon;
■ Offset most of the negative impacts
of warm weather and conservation
through the new Weather Adjusted
Rate Mechanism and the Conservation
Tariff;
■ Reached an agreement in Oregon
to recover and earn on investments
needed to comply with federal pipeline
integrity rules;
■ Negotiated a new five-year labor
agreement;
■ For the 18th year in a row,
achieved an annual customer
growth rate of more than 3 percent;
and
■ Increased annual dividends paid
to shareholders for the 49th
consecutive year.
Milestone projects completed
In 2004, we proved that great
planning brings results—especially
when it’s followed by great execution.
We demonstrated this with the
completion of two long-term initiatives:
a 40-year dream to bring natural
gas over the Oregon Coast Range
to Coos County, and the more-than-
six-year pursuit of a 61-mile extension
of the South Mist Pipeline. Both
projects open new doors for customer
growth and bring returns on our
capital investments.
We completed the South Mist
Pipeline Extension weeks early, and
its costs were rolled into rates in both
Oregon and Washington. That we
achieved this milestone without a
significant hitch is a testament to
our project management abilities.
Farther south, NW Natural created
a backbone distribution system for
four cities in Coos County. When the
County needed to replace its contractor
building the transmission line connect-
ing to our system, we stepped up to
help, providing project management
support to oversee the county pipe-
line’s completion. The Company began
recovering the cost of the Coos Bay
distribution system in November.
Regulatory strategies prove
their value
While NW Natural was planning
system expansions, it also was prepar-
ing to strengthen and stabilize its
revenues. Regulatory changes that took
effect in the previous two years showed
their value in 2004.
The Conservation Tariff, approved by
the Public Utility Commission of Oregon
in 2002, earned the Company national
recognition last year. The Weather
Adjusted Rate Mechanism (WARM),
which took effect in Oregon in 2003,
added 20 cents per share by helping to
compensate for weather in 2004 that
was 8 percent warmer than average.
Support by Oregon regulators
for these strategies has helped NW
Natural overcome two of the greatest
challenges facing utilities today—
uncertainty from weather and lower
per capita consumption.
Also in 2004, Oregon regulators
approved our request to include the
costs of complying with federal pipe-
line integrity regulations in our rates.
The decision allows us both to recover
and earn on pipeline integrity invest-
ments that will be made in the
coming years.
With these rate mechanisms in
place, NW Natural is in an excellent
position to focus its efforts on gaining
more customers, more profitably.
More customers, greater
profitability
NW Natural grew its customer
base by more than 3 percent in 2004,
double the average of local distribution
companies nationally. Even more
significantly, the Company continued
to increase the value added by each
new customer. Profitability of new resi-
dential customer acquisitions increased
from 14 percent in 2003 to 17 percent
in 2004, and customer growth added
approximately $7 million to margin.
Our drive for lower costs and
enhanced customer profitability was
boosted further when regulators in
Oregon and Washington gave us
greater flexibility in responding to gas
service requests for new development.
We call it the Open Pathway program.
Now, builders and developers must
provide a pathway—an open trench or
conduit—for service lines and mains.
We expect this program to cut in half
the cost of conventional service
connections, providing savings that
TOTAL CUSTOMERS
IN THOUSANDS
PROFITABILITY OF NEW
RESIDENTIAL CUSTOMER
ACQUISITIONS
IN % ROE
600
550
500
450
400
350
300
20%
15%
10%
5%
will allow us to reach even more
customers, more profitably.
Last year, NW Natural adopted a
new software package, Prospector Pro,
which added consistency and disci-
pline to our evaluation of requests for
new gas service. In addition, we started
using a computerized Assumed Return
on Equity (AROE) Study to identify
new neighborhoods to target for
growth. AROE can help the Company
reduce investment risk while proactive-
ly seeking new customers.
It is one thing to add large numbers
of new customers; it is another to
deliver great service.
Customer satisfaction continues to
be a top priority for NW Natural. We
were pleased to learn that we ranked
ninth out of 55 gas utilities nationally
in J.D. Power’s 2004 Gas Utility Resi-
dential Customer Satisfaction Study.
The Company ranked first in the West
and second in the nation on billing
and payment.
Employees get it done
The year 2004 started out with ice
storms and record-breaking demand
for natural gas, creating a showcase
for NW Natural’s employees.
Only about 60 of more than 580,000
customers experienced outages, and
those for only a few hours. Employees
GAS SALES AND
TRANSPORTATION
DELIVERIES
IN MILLIONS OF THERMS
1,350
1,200
1,050
900
750
600
450
300
150
94 95 96 97 98 99 00 01 02
03 04
NW Natural added 18,485 new
customers in 2004, expanding our
customer base by 3.2 percent.
This marks the 18th consecutive
year of customer growth in excess
of 3 percent, compared to the
national average of 1.5 percent.
00
01
02
03
04
NW Natural has improved its
return on equity from new
residential customers in the past
three years by targeting the most
profitable customers and
managing main extension costs.
94 95 96 97 98 99 00 01 02
03
04
RESIDENTIAL, COMMERCIAL AND
INDUSTRIAL FIRM SALES
INDUSTRIAL INTERRUPTIBLE SALES
TRANSPORTATION
Gas sales and transportation
deliveries were 1.1 billion therms
in 2004.
3
investments in pipeline integrity. Our
customer growth remains strong and is
increasingly profitable. And our inter-
state storage business, which has newly
added capacity, remains a growth
opportunity we expect to add signifi-
cantly to our bottom line in the future.
As importantly, with weather
normalization and the Conservation
Tariff, the foundation we’ve created is
largely protected from warmer-than-
normal weather and declining
consumption due to conservation.
We enter 2005 as purposeful as ever.
We know who we are. We know where
we’re going. We know what you expect
from us, and we know how to deliver.
This year we will keep looking
ahead, managing our costs, excelling
at business basics and adding
customers profitably. In short, we
will be unwavering in our focus on
the core business.
But that doesn’t mean we won’t
look out at the horizon as well. We
will continue to search for new growth
opportunities. In the same way we
pursued underground storage, then
leveraged the Mist storage field to
create an interstate storage business,
we will keep looking for ways to build
on our core strengths.
We’re ready for the challenges, and
the opportunities. After 146 years of
excellence, we’re ahead of the curve —
and we intend to stay there.
Sincerely,
Mark S. Dodson
President and Chief Executive Officer
March 15, 2005
adjusted valves, climbed roofs to
clear vents and helped stranded
motorists. Some employees didn’t
make it home for three days, staying
near the Portland office to make sure
the phones got answered.
Although the weather let up within
a week, our employees never did.
In every part of the Company, our
employees stepped forward to get the
tough things done. A great example is
the year-long effort to comply with
the Sarbanes-Oxley Act. Our finance
and accounting departments, along
with a host of others across the
Company, worked tirelessly to comply
with the act. Our outside auditor,
PricewaterhouseCoopers LLP, agreed
with management’s assessment that
in fact we did.
In a year when we were once again
named one of Oregon’s 100 Best Places
to work by Oregon Business Magazine,
we also reached agreement on a five-
year contract, called the Joint Accord,
with members of the Office and
Professional Employees International
Union, Local 11. It is a balanced
agreement that advances the interests
of the Company and its employees.
The challenges ahead
High gas prices are of great concern,
both to us and to our customers.
Locally, NW Natural is doing what it
can to offset high prices.
In 2004, as part of a disciplined
gas purchasing strategy, we used
our Mist underground storage to
maximum advantage, buying supplies
when prices were most favorable. As
a result, today our weighted average
cost of gas is the lowest in Oregon
and Washington.
Our Conservation Tariff has aligned
shareholder and customer interests
around energy efficiency, and we are
actively working with the Energy Trust
of Oregon to help customers use
natural gas as efficiently as possible.
In 2005, we will be working to renew
this innovative tariff. We have commis-
sioned a study of the tariff that will
serve as a basis for a filing this year
to continue the mechanism.
As a local distribution company,
4
we are price takers, not price makers
when it comes to wholesale natural
gas prices. Our challenge is to demon-
strate to customers that they receive
superior value from our products and
services. And we’re doing that in a
number of ways. We’re strengthening
our energy efficiency communications,
unveiling an improved web site that
offers useful tools such as a bill analyz-
er and reorganizing our consumer call
centers for faster, easier solutions and a
better customer experience.
We enter 2005 as
purposeful as ever.
We know who
we are. We know
where we’re going.
We know what you
expect from us,
and we know
how to deliver.
At the national level, we see some
hopeful signs of progress in addressing
the supply imbalance that exists today.
These include the increasing number
of liquefied natural gas import proposals
moving through the permitting process
and new incentives passed by Congress
to build an Alaskan pipeline.
Clearly, the country needs a compre-
hensive energy strategy. NW Natural
will work closely this year with the
American Gas Association to advance
national energy policies aimed at
reducing gas price volatility.
Around the next curve
While we are proud of what the
years of planning and hard work meant
to our performance in 2004, we are
even more excited about what they
mean for 2005 and beyond.
We have built a strong foundation
on which to grow our Company. The
South Mist Pipeline Extension and the
Coos Bay distribution system are in
rates and contributing to our earnings.
We can now recover and earn on our
Focusing
on mutual gains
Interview with
Gregg Kantor,
Senior Vice President
1. What is NW Natural’s regulatory strategy, and how
has the Company been pursuing it?
A major focus has been reducing business risks from
factors outside the Company’s control. To that end, we’ve
introduced a number of innovative regulatory mechanisms,
each built on our commitment to meet the needs of both
customers and shareholders.
For example, when natural gas prices increased significant-
ly in 2000 and 2001, we stepped forward to help customers
use our product more efficiently. But as usage declined so
did our revenues.
It made no sense that doing what was right for customers
should hurt the company. So we developed a mechanism we
called the Conservation Tariff. In 2002, the Public Utility
Commission of Oregon (OPUC) approved the Conservation
Tariff, which partially decouples our margins from how
much gas we sell. In the end, it aligns the interests of
shareholders with those of customers.
Weather is a challenge we’ve faced for a long time. In
2003, we developed our own weather normalization
mechanism, called the Weather Adjusted Rate Mechanism
(WARM). With the backing of customer groups, we secured
approval from the OPUC. WARM helps protect customers
against high gas bills during unusually cold winters and
protects shareholders from revenue losses during unusually
warm winters.
Both the Conservation Tariff and WARM demonstrate
what can be accomplished when solutions create a win for
customers and shareholders.
2. How have pipeline safety issues impacted your
regulatory efforts?
NW Natural has taken a proactive approach to pipeline
safety. We completed removal of all cast-iron pipe in our
system several years ago and are now replacing bare-steel
pipe. The OPUC has supported these efforts by allowing
the recovery of a substantial portion of the costs associated
with the cast-iron pipe and bare-steel work.
The new federal pipeline safety mandates increased
significantly the work to be done on transmission lines.
The cost of complying with these new requirements is a
major concern to every gas utility. However, we have
secured OPUC approval for the next four years to roll
yearly pipeline integrity costs, including return, into rates
each October.
3. What are the Company’s newest regulatory
initiatives?
In late 2004, the Washington and Oregon commissions
approved our Open Pathways tariff. This mechanism holds
Gregg Kantor, Senior Vice President of Public and Regulatory
Affairs, at the state capitol in Salem, leads the team that
works with regulators in Oregon and Washington.
the customer responsible for providing a pathway for gas
lines to new buildings or developments. The customer is
required to make a trench or conduit available for gas
services or mains or compensate the Company for its
excavation time. This reflects requirements already in place
for electric service and represents a major breakthrough for
us. We expect it will cut in half the cost of installing service
installations where joint trenching isn’t being used.
In January 2005, the OPUC approved a combined
heat and power tariff. This tariff allows NW Natural to
sell natural gas at a discounted rate to fuel microturbines,
fuel cells and other small-scale electrical generating
equipment. We hope this incentive will stimulate interest
from both manufacturers and customers in these energy-
saving technologies.
4. How would you describe your relations with Oregon
and Washington regulators and consumer advocates?
Our relationships are quite positive. We are fortunate to
have regulators and consumer advocates who, while tough
and passionate about their duties, are also knowledgeable,
fair and open-minded. They understand utilities must attract
investment capital if they are to maintain safe, reliable
service, and they are open to pursuing ideas that benefit
customers while keeping utilities strong.
5
Undergraduates Ben Coppel, Nicole Frostad, Stephanie
Stradley and Matt Steel enjoy a warm fall day at the
University of Oregon. Most students were just as
comfortable in January 2004 during the severe cold
snap. NW Natural’s newest transmission line allowed
the Company to serve its largest customers such as
the university, despite record-breaking demand.
6
Ahead of
the curve
Maybe “innovative” isn’t the first word that comes to mind
when you think of a natural gas utility.
But think again.
Like most gas utilities, NW Natural is focused on providing
safe, reliable, low-cost natural gas service to its customers.
It’s how we do it that stands out.
We’re not afraid to try new approaches to meet customers’
needs. There’s the new mechanism we developed to help
customers keep their bills down when weather is colder than
normal... the new energy systems we’ve developed to increase
efficient use…even the month-early completion of a pipeline
expansion, which made the critical difference in assuring reliable
service to customers like the University of Oregon during the bitter
winter storm of January 2004.
We’re a natural gas utility — but we’re also bold enough to
innovate and bold enough to lead. That’s what puts us ahead
of the curve.
7
Opening
new markets
Some dreams refuse to die. For 39 years, NW Natural
held fast to its vision of serving Coos Bay, a Southern
Oregon coast community for which the Company held
a franchise.
In 2004, that dream came true.
There were plenty of ups and downs in building
public support, securing funding and coordinating
construction of NW Natural’s distribution system with
the completion of the county’s transmission line. It took
a commitment of dollars from the Oregon Legislature
and a vote of Coos County residents to bring a
transmission line across the Oregon Coast Range.
But despite the obstacles, in 2004 NW Natural
installed its new Coos County distribution system,
comprising more than 250,000 feet of pipeline.
Building the backbone
NW Natural started building its local distribution
system in Coos County in August 2003. At the same
time, the county began building the transmission line to
connect Coos County customers to the interstate pipeline.
NW Natural outpaced the county’s progress, and the
local distribution system was ready to go by summer.
Before the transmission line was completed, NW Natural
began serving customers with trucked-in compressed
natural gas.
By November, 12 customers identified as having
the most pressing need for natural gas were receiving
supplies trucked from Portland in CNG tankers.
NW Natural began to recoup through rates its Coos
County investment of nearly $12 million.
Finally, the connection
On Jan. 14, 2005, the county’s transmission line
was ready for use. Coos County contractors had tested
the line, and soon natural gas was flowing from the
interstate pipeline to Coos County.
NW Natural Customer Consultant Linda
Kennedy and Commercial Service Technician
Dan Hutchens are key participants in the
Company’s efforts to attract and serve
more customers in the Coos Bay area.
“It’s exciting and fun,” said Hutchens.
“Coos County has had one of the highest
unemployment rates in the state. I think
once people see things starting to happen
and new businesses coming in, they’ll
understand why the county commissioners
have been wanting to do this.” At right,
restaurant owner Elizabeth Kinzie looks
forward to cooking with natural gas.
8
Several weeks after gas was flowing, NW Natural
had more than 400 homes and businesses signed up for
gas service.
The Company set a goal of serving 1,000 customers
in the cities of Coos Bay, Myrtle Point, Coquille and
North Bend by the end of 2005.
Under the bay
One of the milestones in building the Coos Bay
distribution system was crossing under Coos Bay
to bring gas to the North Spit industrial area. The
promise of natural gas already helped sway the
decision of Southport Forest Products, which plans
to build an expanded plant on the spit. In addition,
Energy Products Development, LLC announced plans
to build a liquefied natural gas plant on the spit
specifically to take advantage of new gas lines to
that area.
9
Leading
with innovation
New technologies are providing new ways for
customers to use energy wisely and for NW Natural
to grow.
Combined heat and power
NW Natural is a regional leader in promoting
distributed generation and combined heat and power
(CHP) projects. Distributed generation means the small-
scale generation of electricity at the location of its use
rather than at a centralized power plant. CHP systems
go a step farther by capturing waste heat from the
generating process and using it to heat space or water.
CHP is one of today’s most efficient and cost-effective
ways to generate energy.
NW Natural is a central player in a consortium of
organizations and businesses promoting distributed
generation and CHP. The Company’s newest project, to
be completed in 2005, is a five-microturbine system at
an Oregon Health Sciences University building.
NW Natural anticipates long-range business
benefits from promoting distributed generation and
CHP. First, CHP offers NW Natural new ways to serve
industrial customers. Second, CHP reduces the use
of inefficient, centralized electric generation. This,
in turn, reduces the demand for natural gas to
generate electricity.
In 2004, the Public Utility Commission of Oregon
approved a tariff proposed by NW Natural that will
provide rate incentives for industrial customers using
gas-powered distributed generation. The Company
foresees an increase in the demand for onsite generation
10
as electric rates go up and generating equipment costs
come down.
Prospecting for profitability
To make sure customer growth benefits the
Company’s bottom line, NW Natural uses innovative
tools to target its marketing and infrastructure
investments. Two programs, Prospector Pro and
AROE (Assumed Return on Equity), are NW Natural’s
newest electronic tools for ensuring profitable growth.
Prospector Pro, adopted in August 2004, allows
NW Natural’s marketing representatives to calculate
more accurately the cost of hooking up a new customer.
With Prospector Pro, a marketing representative can
estimate how much gas the new customer will use and
then calculate costs and benefits. The program adds
accuracy, consistency and discipline to
customer acquisition efforts.
While Prospector Pro responds to service requests,
NW Natural uses AROE for proactive marketing. Using
tax assessor data, an employee can estimate a home’s
gas usage. AROE then overlays data from NW Natural’s
propensity study to learn which homeowners are most
likely to switch to natural gas.
Now, NW Natural can focus direct mailings on
neighborhoods with high percentages of likely,
profitable customers. AROE also guides the selection
of existing neighborhoods for new main construction.
We’ll call you back
In November, NW Natural became the first utility
in our region to offer customers the option of receiving
a call back, rather than waiting on hold to talk with
a service representative. The launch of Virtual Hold
Technology software won rave reviews from
customers who were freed from waiting
on their telephones but could still
count on talking soon with a NW
Natural employee. During
November and December, just
under half our customers chose
the callback option.
Swim team member Theresa Likarish glides
through her practice in the pool at Lewis & Clark
College’s Swim Pavilion, now heated by a
natural gas-fired microturbine. In 2004, Chris
Galati, NW Natural’s Director of Conservation
and Technology, coordinated placement of the
30 kW microturbine in the Portland college’s
newest building, where it generates electricity
for the campus. Waste heat from the
microturbine warms the water in the pool.
11
Promoting
wise energy use
The Wall Street Journal subsequently featured an article
on the mechanism and the unusual consumer-corporate
partnership behind it.
Cavanagh later joined NW Natural in advocating
the tariff to the Washington Utilities and Transportation
Commission. At the same time, the Company described
to Washington regulators the Weather Adjusted
Rate Mechanism (WARM), another innovative
regulatory mechanism, which took effect in Oregon
in October 2003.
NW Natural introduced WARM as a way to help
protect customers from extremely high bills when
In 2004, investor-owned utilities around the nation
turned to NW Natural for a potential solution to a
chronic problem: How can we encourage customers
to use energy more efficiently without reducing
Company revenues?
NW Natural’s Conservation Tariff, launched in 2002,
recognizes that customers are using less natural gas
as appliances become more efficient and as gas prices
increase. The tariff provides a mechanism for protecting
Company earnings as natural gas use declines. In 2004,
it added $3.5 million to earnings, translating to 7 cents
a share.
By protecting earnings, the Conservation Tariff frees
NW Natural to promote more aggressive energy
efficiency programs. In 2004, NW Natural worked
with the Energy Trust of Oregon to deliver high-
efficiency programs to reduce natural gas use by
more than a million therms.
One of NW Natural’s Conservation Tariff’s most vocal
supporters is Ralph Cavanagh of the Natural Resources
Defense Council. In the summer of 2004, Cavanagh
and NW Natural President and CEO Mark
Dodson addressed a national conference
of state regulators to discuss the tariff’s
benefits for consumers and utilities.
Steve Bicker, (left) Energy Efficiency
Services Program Manager, and
Onita King, Rates & Regulatory
Manager, help NW Natural
satisfy both shareholders and
customers through regulatory
mechanisms that encourage
wise energy use. Hot Lips
Pizza, known for its sustain-
able business practices,
enjoys lower energy bills
by reusing waste heat from
its gas-fired pizza ovens to
heat its water. At right, customer
Stewart Clark samples the results.
winter weather is colder than expected, and to help
protect shareholders from reduced Company revenues
when winter weather is warmer than normal. Unlike
many parts of the country, utility weather normalization
is not common in the Pacific Northwest.
Consumer advocates supported WARM because they
understand how it helps protect consumers from high
winter bills. They also like the fact that the Company’s
unique proposal trues up bills immediately, thus giving
customers relief on their next bills. Most utilities don’t
apply weather adjustments to customer bills until the
following heating season.
WARM played an important role in the
Company’s financial results for the year,
and especially for the second quarter
of 2004, which was 31 percent
warmer than
average. For
the year,
WARM
contributed
$9 million of
margin, equivalent to 20 cents a share.
13
Building for
the future
It was another milestone year for Mist, NW Natural’s
premium underground gas storage facility.
In the 1970s, when NW Natural began preparing
the Mist storage field, management could not have
envisioned all the benefits the Company’s investment
would yield. Nor could they know how underground
storage would give them more control over peak-
demand gas supplies and future gas costs.
By 2004, the decision to invest at Mist has never
looked better. Last fall, the Company completed the
biggest capital construction project in its history: a
61-mile extension of the South Mist pipeline, expanding
Mist’s takeaway capacity and bolstering the Company’s
service to its fast-growing customer base.
Underground storage supplements NW Natural’s gas
supplies in high-demand periods. It also allows the
Company to reduce its need for year-round interstate
pipeline capacity, and provides a way for NW Natural
to purchase and store gas when prices are lowest.
NW Natural also sells gas storage services on the
interstate market. In this way, the Company has
diversified its revenue streams while leveraging its
core assets and expertise.
SMPE finale
After six years of planning, permitting and construc-
tion, the South Mist Pipeline Extension (SMPE) officially
went on line on Sept. 22, 2004. The Company rolled
SMPE into rates on Oct. 1. Built for about $110 million,
the 24-inch-diameter SMPE doubles deliverability from
the Mist underground storage field to the Portland
metropolitan area and provides another connection to
the interstate pipeline.
Construction was a major challenge, as the pipeline
crossed sensitive environmental areas, rich farmland
and populous suburbs. Yet the team completed the
project five weeks ahead of schedule after contractors
14
successfully managed the longest large-diameter
underground bore in Oregon history. The bore passed
through more than a mile of solid rock, but it was
finished ahead of schedule and on budget.
Timing is everything
The SMPE’s first 11.7-mile segment began operating
Nov. 6, 2003. On Jan. 5, 2004, extremely cold tempera-
tures sent gas demand soaring, and NW Natural set a
new one-day sendout record of 8.9 million therms.
The new pipeline was critical to the Company’s ability
to avoid outages and reliably serve its customers.
The SMPE helps NW Natural serve some of Oregon’s
fastest-growing communities. Its completion puts
NW Natural ahead of demand, allowing it to absorb
new residential, commercial and industrial customers
in both suburban and rural areas near Portland.
Jewels in the making
The year included improvements to the Mist storage
facilities as well. In 2004, NW Natural completed the
expansion of its Sapphire phase. This $9.1 million
project expanded capacity and deliverability of the
Mist facilities. Sapphire’s immediate purpose is to
make new storage capacity available for the interstate
market. As NW Natural’s core market grows, the
Company expects to reallocate Sapphire’s resources
to serve its core distribution customers.
Interstate customer growth
As NW Natural continues to develop storage
infrastructure, it also expands its interstate business.
The Company currently has 10 interstate storage
customers across the Western United States and
Canada, with customers on both firm and interruptible
service contracts. Customers include local distribution
companies, energy marketers and power generators.
Among the residents Senior Project
Engineer Roy Rogers wanted to keep
happy during SMPE construction were
some four-legged ones. NW Natural
conducted extensive research and
worked with equestrian facilities like
Sherwood Forest in Wilsonville, Oregon,
to assure that neither the construction nor
the new pipeline would disturb the horses.
Rogers and the construction team also
restored horse pastures and paths to
their previous condition – or better.
Profiting from
smart growth
Jamison Park draws visitors of all ages to the heart
of Portland’s new River District, a bustling
community of upscale as well as affordable multi-
family housing, cafes, shops, boutiques and
galleries, nearly all served by NW Natural. Brenda
Hartzog, Residential New Construction Consultant,
and Grant Yoshihara, Director of Utility Services,
help bring natural gas service to the homes and
businesses in this thriving neighborhood.
16
NW Natural is benefiting from strengthened relation-
ships with architects, engineers and developers. The
Company reaches out to these groups through seminars
and newsletters to educate them about economical and
space-saving natural gas technology. Finally, the
Company’s efforts to target idle services are returning
some commercial buildings back to gas service.
Open pathways reduce construction costs
For years, builders and homeowners in the Northwest
have been required to provide a trench to bring
electricity to new buildings. This
has not been the case with natural
gas. That changed in 2004, when
Oregon and Washington regu-
lators agreed to require customers
to provide an open trench or
conduit for natural gas service
lines and mains to new buildings.
This means NW Natural will
lower its costs and realize higher margins from all new
construction. While sharing trenches with electric and
telecommunication providers already is common
practice in many parts of the service territory, each year
crews are required to dig an estimated 7,000 trenches to
install gas services. NW Natural’s contribution to the
cost of residential service installation is expected to fall
from an average $726 to $339.
As an added incentive, NW Natural now offers a
guaranteed installation date when a contractor notifies
the Company in advance that a pathway will be ready
for our pipeline.
Natural gas is still the fuel of choice in the Northwest,
and NW Natural has the customer growth to prove it.
In 2004, the Company’s customer base grew by more
than 3 percent for the 18th consecutive year. At the
same time, the Company continued to improve the
profitability of its customer additions.
The growing multifamily sector
Because of Oregon’s unique land use planning
system, Portland is growing up, not just out. With
suburban development contained by a conservative
urban growth boundary, high-density multifamily
construction is the hottest trend in Portland’s
housing market.
To help attract empty nesters and young professionals
to townhouses and condominiums, developers are
investing in natural gas space and water heating as
well as cooktops and hearths. In 2004, NW Natural
significantly exceeded its goals for
new multifamily services.
Affordable housing
developers prefer gas, too
High-end developers aren’t
the only ones choosing gas.
Developers of affordable housing
have realized that high-
efficiency natural
gas appliances can reduce tenants’ fuel
bills. New natural gas technologies such
as compact on-demand water heaters
save space as well as energy.
In 2004, the Portland Develop-
ment Commission (PDC) updated
its “Green Building” guidelines.
Affordable projects receiving PDC
funds are encouraged to use
high-efficiency combo systems
and natural gas furnaces.
Commercial conversions
present new opportunities
Although new commercial development has been
slow to improve, NW Natural has seen an increase
in commercial conversions. With the limited
supply of buildable land in the Portland
area, developers are renovating existing
buildings rather than constructing new
ones. These renovations often include
a switch to natural gas.
17
Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following is management’s assessment of Northwest Natu-
ral Gas Company’s financial condition including the principal fac-
tors that affect results of operations. The discussion refers to the
consolidated activities of the Company for the three years ended
Dec. 31, 2004. Unless otherwise indicated, references in this dis-
cussion to “Notes” are to the notes to the consolidated financial
statements in this report.
The consolidated financial statements include the regulated par-
ent company, Northwest Natural Gas Company (NW Natural), and
its non-regulated wholly-owned subsidiaries:
■ NNG Financial Corporation (Financial Corporation), and its
wholly-owned subsidiaries
■ Northwest Energy Corporation (Northwest Energy), and its
wholly-owned subsidiary
Together these businesses are referred to herein as the “Com-
pany.” In this report, the term “utility” is used to describe the Com-
pany’s regulated gas distribution business and the term “non-util-
ity” is used to describe its interstate gas storage business and other
non-regulated activities (see 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. The
Company believes this per share information is useful because it
enables readers to better understand the impact of these factors on
earnings. All references in this report to earnings per share are on
the basis of diluted shares (see Note 1).
EXECUTIVE SUMMARY
The Company’s strategy in 2004 was to strengthen its financial
position and remain focused on profitably growing its regulated
gas distribution business and interstate gas storage business.
Highlights of 2004 include:
■ overall earnings growth of 11 percent over 2003 despite weather
conditions that were 3 percent warmer;
■ the addition of 18,485 customers, for a growth rate in excess of
3 percent for the 18th consecutive year;
■ the issuance of $40 million in common stock through a public
offering to help fund major construction projects and maintain a
balanced capital structure;
■ the upgrade of the Company’s long-term debt rating to A+ by
the Standard & Poor’s Rating Services;
■ the completion ahead of schedule of the Company’s largest
construction project to date, the 61-mile South Mist Pipeline Ex-
tension (SMPE), which received timely regulatory approval for
recovering its costs through customer rates in both Oregon and
Washington;
■ regulatory approval to track future pipeline integrity manage-
ment costs into rates in Oregon;
■ a new 5-year labor agreement, also known as the Joint Accord;
■ the settlement and early implementation of the Washington
general rate case;
■ expansion of the Company’s gas distribution system into Coos
County, Oregon, an area targeted for natural gas service for over
three decades; and
■ the development of additional gas storage capacity at Mist for
interstate storage services, replacing capacity that had been re-
called to meet core utility customer requirements.
Issues, Challenges and Performance Measures
There are a number of factors that affect the Company’s opera-
tions and financial performance. The most significant issues and
challenges the Company expects to face in 2005 include high gas
commodity prices, unpredictable weather conditions, the impact
of regulatory actions or policy changes, managing gas supplies and
storage capacity, maintaining a competitive advantage over alter-
18
N W N AT U R A L
nate fuels, managing environmental risks and exposures, an un-
certain economic recovery and higher interest rates. For a detailed
listing of other risks facing the Company, see “Forward-Looking
Statements” and “Quantitative and Qualitative Disclosures About
Market Risk,” below.
In order to deal with these and other issues affecting the busi-
ness, the Company’s strategic plan includes strategies for:
■ improving NW Natural’s ability to add customers both profit-
ably and at a rapid pace;
■ maintaining NW Natural’s reputation for exemplary service;
■ reducing business risk;
■ managing all costs, including capital expenditures;
■ setting high performance standards for all employees; and
■ judiciously growing beyond the Company’s local distribution
business where such growth would complement core assets
and competencies.
In addition to return on equity (ROE) and common equity ratio
as key indicators of the Company’s operating performance and fi-
nancial condition, other key performance measures the Company
uses in monitoring progress against its goals are utility earnings
per share, customer satisfaction ratings, new customer additions,
operations and maintenance expense per customer, construction
cost per meter installed, and non-revenue producing capital expen-
ditures per customer.
$2.00
$1.25
$1.50
$1.75
DILUTED EARNINGS
PER SHARE
IN DOLLARS
EARNINGS AND DIVIDENDS
Earnings applicable to common stock were $50.6 million, or
$1.86 a diluted share, for the year ended Dec. 31, 2004, compared
to $45.7 million, or $1.76 a share, and $41.5 million, or $1.62 a
share, for the years ended Dec. 31, 2003 and 2002, respectively. Re-
turns on average common equity for these three years were 9.4
percent, 9.3 percent and 8.7 percent, respectively. Primary factors
affecting earnings, and the re-
sulting positive (negative) im-
pact include:
2004 compared to 2003:
■ increased the contribution
to net operating revenues
(margin) from residential
and commercial customers
primarily resulting from
the Oregon and Washington
general rate increases,
including rate increases
for the SMPE investment
and a full year effect of
the weather normalization
mechanism – $26 million;
■ increased margin contri-
bution from industrial
customers resulting from
rate redesigns in the 2003
Oregon general rate case and a recovering economy –
$4.8 million;
■ decreased margin from other utility operating revenues due to
changes in and amortizations under the Company’s regulatory
deferral mechanisms – ($7.8 million);
■ increased franchise tax expense due to higher gross revenues –
($2.2 million);
■ increased payroll and related payroll tax, pension and health
care costs primarily due to wage and salary increases and certain
benefit cost increases – ($4.6 million);
■ internal development costs and external audit fees relating to
the implementation of Section 404 of the Sarbanes-Oxley Act of
Diluted earnings were $1.86
per share in 2004, up 6 percent
over 2003.
94 95 96 97 98 99 00 01 02 03
$0.25
$0.50
$1.00
$0.75
04
16%
14%
12%
10%
TOTAL SHAREHOLDER
RETURNS
ANNUALIZED AS A PERCENT
2002, including compliance documentation and testing require-
ments – ($1.5 million);
■ increases in depreciation and property taxes due to added
utility plant – ($3.8 million);
■ decreased margin from interstate gas storage services due to
less volatility in natural gas price differentials – ($2.6 million);
■ reduced income before tax from non-utility subsidiary invest-
ments, including a $0.5 million charge for an impending sale of
solar electric generating investments – ($0.3 million); and
■ increased income taxes – ($3.2 million).
2003 compared to 2002:
■ earnings for 2002 were reduced by special charges totaling
$13.9 million before tax, or $8.4 million after tax, representing
the Company’s transaction
costs incurred in its effort
to acquire Portland General
Electric Company (PGE)
from its parent, Enron;
■ increased margin contribu-
tion from residential and
commercial customers
primarily resulting from rate
increases – $9.9 million;
■ increased gains in market
value of equity-based life
insurance investments –
$2.0 million;
■ reductions in interest
charges on deferred regula-
tory account balances result-
ing from lower balances
due to a $30 million cus-
tomer refund in 2002 from
accumulated gas cost
savings – $1.4 million;
■ increased income before
tax from the interstate gas storage segment – $1.1 million;
■ increased payroll and related payroll tax, pension, health care
and other benefit costs – ($8.1 million);
■ increases in other operations and maintenance costs –
($2.4 million);
■ decreased margin contribution from industrial customers due
to weak economic conditions – ($3.0 million);
■ increases in depreciation expense and property taxes relating
to added utility plant – ($3.1 million);
■ increases in other employee benefit costs – ($0.8 million); and
■ reduced income before tax from non-utility subsidiary invest-
ments – ($0.5 million).
Dividends paid on common stock were $1.30 a share in 2004,
compared to $1.27 a share in 2003 and $1.26 a share in 2002. The
2004 increase in dividends paid marks the 49th consecutive year
of dividend increases.
The Company’s total return —
dividends plus stock appreciation —
was 14.5 percent in 2004, 14.3
percent over the past five years,
and 10.9 percent over ten years.
Five Years
1999-2004
Ten Years
1994-2004
One Year
2004
8%
6%
APPLICATION OF CRITICAL ACCOUNTING POLICIES
AND ESTIMATES
In preparing the Company’s financial statements using gener-
ally accepted accounting principles in the United States of America
(GAAP), management exercises judgment in the selection and ap-
plication of accounting principles, including making estimates and
assumptions that affect reported amounts of assets, liabilities, rev-
enues, expenses and related disclosures in the financial statements.
Management considers its critical accounting policies to be those
which are most important to the representation of the Company’s
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 dif-
ferent amounts if the Company reported under different conditions
or using different assumptions.
The Company’s most critical estimates or judgments involve
regulatory cost recovery, unbilled revenues, derivative instruments,
pension assumptions, income taxes and environmental contingen-
cies. Management has discussed the estimates and judgments used
in the application of critical accounting policies with the Audit
Committee of the Board. The Company’s critical accounting poli-
cies and estimates are described below.
Within the context of the Company’s critical accounting policies
and estimates, management is not currently aware of any reason-
ably likely events or circumstances that would result in materially
different amounts being reported.
Regulatory Accounting
NW Natural is regulated by the Public Utility Commission of
Oregon (OPUC) and the Washington Utilities and Transportation
Commission (WUTC), which establish the Company’s utility rates
and rules governing utility services provided to customers, and to
a certain extent set forth the accounting treatment for certain regu-
latory transactions. In general, NW Natural uses the same account-
ing principles as other 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 ac-
counting treatment for regulated companies to show the effects of
regulation. For example, NW Natural accounts for the cost of gas
using a deferral and cost recovery mechanism called the Purchased
Gas Adjustment (PGA), 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 the Company to de-
fer for recovery or refund in future periods. SFAS No. 71 requires
the Company to account for these types of deferred expenses (or
deferred revenues) as regulatory assets (or regulatory liabilities) on
the balance sheet. When NW Natural is allowed to recover these
expenses from or refund them to customers, it recognizes the ex-
pense or revenue on the income statement at the same time it re-
alizes the adjustment to amounts included in utility rates and
charged to customers.
The conditions a company must satisfy to adopt the accounting
policies and practices of SFAS No. 71 applicable to regulated com-
panies 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.
NW Natural continues to apply SFAS No. 71 in accounting for
its regulated utility operations. Future regulatory changes or changes
in the competitive environment could result in the Company dis-
continuing the application of SFAS No. 71 for some or all of its reg-
ulated business. This would require the write-off of those regula-
tory assets and liabilities that would no longer be probable of
recovery from or refund to customers. Based on current regulatory
and competitive conditions, NW Natural believes that it is reason-
able to expect continued application of SFAS No. 71 for its regulated
activities, and that all of its regulatory assets and liabilities at Dec.
31, 2004 and 2003 are recoverable or refundable through future
customer rates.
N W N AT U R A L
19
Management’s Discussion and Analysis
Revenue Recognition
Utility revenues, derived primarily from the sale and transporta-
tion of natural gas, are recognized when the 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 (unbilled revenues).
Unbilled revenues are primarily based on the Company’s percent-
age estimate of its unbilled gas each month, which is dependent
upon a number of factors that require management’s judgment.
These factors include total gas receipts and deliveries, customer
meter reading dates, customer usage patterns and weather. Un-
billed revenue estimates are reversed the following month when
actual billings occur. Estimated unbilled revenues at Dec. 31, 2004
and 2003 were $64.4 million and $59.1 million, respectively. The
increase in unbilled revenues at year-end 2004 was primarily due
to higher gas prices included in customer rates, partially offset by
lower unbilled volumes reflecting warmer weather and decreases
in customer usage due to higher prices. If the estimated percentage
of unbilled gas at Dec. 31, 2004 were adjusted up (or down) by 1
percent, then the Company’s unbilled revenues, net operating rev-
enues and net income would have increased (or decreased) by an
estimated $1.0 million, $0.5 million and $0.3 million, respectively.
In November 2003, NW Natural implemented a weather normal-
ization mechanism in Oregon that helps stabilize net operating rev-
enues by adjusting current customer billings based on temperature
variances from average weather (see “Results of Operations – Reg-
ulatory Matters – Rate Mechanisms,” below). Weather normaliza-
tion is also included in unbilled revenues at the end of each account-
ing period using management’s judgments as discussed above.
Non-utility revenues, derived primarily from interstate storage
services, are recognized upon delivery of the service to customers.
Revenues from optimization of excess storage and transportation
capacity are recognized over the life of the contract for guaranteed
amounts under the contract, or are recognized as they are earned
for amounts above the guaranteed value based on estimates pro-
vided by the independent energy marketing company.
Accounting for Derivative Instruments and
Hedging Activities
In providing gas distribution services, NW Natural enters into
forward contracts to buy and sell natural gas. These contracts qual-
ify as normal purchases and normal sales under SFAS No. 133, “Ac-
counting for Derivative Instruments and Hedging Activities,” be-
cause they provide for a purchase or sale, and subsequent delivery,
of natural gas in quantities that are probable of delivery over a rea-
sonable period of time in the normal course of business (see Note
1, “Derivatives Policy”). Accordingly, these contracts are accounted
for at the time of settlement and are not reflected on the Company’s
balance sheet or income statement prior to settlement.
The Company has an established Derivatives Policy that sets
forth the guidelines for using selected financial derivative products
to support prudent risk management strategies within designated
parameters (see Note 1). The policy specifically prohibits the use
of derivatives for trading or speculative purposes. Hedging activi-
ties consist of natural gas commodity price and foreign currency
exchange rate hedges which are accounted for as cash flow hedges.
These contracts that qualify as derivative instruments are recorded
on the balance sheet at fair value. Generally, most of these con-
tracts are subject to regulatory deferral mechanisms, and as such
any change in the fair value of these contracts is recorded as regu-
latory assets or regulatory liabilities pursuant to SFAS No. 71 (see
Note 1, “Derivatives Policy”). The Company’s estimate of fair value
is determined from period to period based on prices available from
external sources and internal modeling based on index prices that
20
N W N AT U R A L
are subject to market volatility. For estimated fair values at Dec. 31,
2004 and 2003, see Note 11.
The following table summarizes the realized gains and losses
from commodity price and currency hedge transactions in the years
ended Dec. 31, 2004, 2003 and 2002:
Thousands
2004
2003
2002
Gains (losses) on commodity price
swap contracts
Gains (losses) on commodity price
option contracts
Subtotal
Gains (losses) on swaps related to
interstate gas storage
Gains on foreign currency contracts
Total gains (losses)
$
44,888 $
29,660 $
(73,922)
(2,464)
__________
42,424
2,723
__________
32,383
(1,601)
__________
(75,523)
(186)
219
__________
42,457 $
$
__________
__________
–
4,129
__________
36,512 $
__________
__________
–
521
__________
(75,002)
__________
__________
Realized gains (losses) from commodity price and foreign cur-
rency hedge 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-mar-
ket valuations are not recognized in current income or other com-
prehensive 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
The Company has two qualified, non-contributory defined ben-
efit pension plans covering all regular employees with more than
one year of service. These plans are funded through a trust dedi-
cated to providing retiree pension benefits. The Company also has
several non-qualified supplemental pension plans for eligible ex-
ecutive officers and certain key employees. These non-qualified
plans are unfunded.
Net periodic pension cost (NPPC) and accumulated benefit ob-
ligations (ABO) are determined in accordance with SFAS No. 87,
“Employers’ Accounting for Pensions,” using a number of key as-
sumptions including the discount rate, the rate of compensation
increases, retirement ages, mortality rates and the expected long-
term return on plan assets (see “Financial Condition – Pension Cost
(Income) and Funding Status,” below, and Note 7). These key as-
sumptions have a significant impact on the amounts reported.
NPPC consists of service costs, interest costs, the amortization of
actuarial gains and losses, 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
NPPC volatility.
A number of factors are considered in developing pension
assumptions, including an evaluation of relevant discount rates,
expected long-term returns on plan assets, plan asset allocations,
expected changes in wages and retirement benefits, analyses of
current market conditions and input from actuaries and other con-
sultants. For the Dec. 31, 2004 measurement date, the Company:
■ decreased the discount rate assumption from 6.25 percent to
6.00 percent;
■ maintained the rate of compensation increase in a range of
4.00-5.00 percent; and
■ maintained the expected long-term return on plan assets at
8.25 percent.
The change in discount rate was the primary factor contribut-
ing to the increase in the plans’ ABO from $205 million at Dec. 31,
2003 to $223 million at Dec. 31, 2004.
The Company believes its pension assumptions to be appropri-
ate based on plan design and an assessment of market conditions.
However, the following reflects the sensitivity of NPPC and ABO
to changes in certain actuarial assumptions:
Thousands
Change in
Assumption
Impact on
ABO at
Impact on
2004 NPPC Dec. 31, 2004
Discount rate
Expected long-term return on plan assets
(0.25%) $
(0.25%) $
608 $
403
5,255
N/A
The impact of a change in NPPC on operating results would be
less than the amounts shown above because about 60 percent of
NPPC is charged to operations and maintenance expense. The re-
maining 40 percent is capitalized as construction overhead and in-
cluded in utility plant, which is amortized to expense over the use-
ful life of the asset placed into service.
Accounting for Income Taxes
Income taxes are accounted for in accordance with SFAS No.
109, “Accounting for Income Taxes,” by recognizing deferred in-
come taxes for all temporary differences between the book and tax
basis of assets and liabilities at current income tax rates.
SFAS No. 109 also requires the recognition of additional deferred
income tax assets and liabilities for temporary differences where
regulators 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 ratemaking policies
of the OPUC and WUTC. Regulatory tax assets and liabilities are
recorded to the extent the Company believes they will be recover-
able from or refunded to customers in future rates. At Dec. 31, 2004
and 2003, the Company had regulatory assets representing differ-
ences between book and tax basis related to pre-1981 property of
$64.7 million and $63.4 million, respectively, and has recorded an
offsetting deferred tax liability for the same amounts (see Note 1).
NW Natural believes 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 por-
tion of these regulatory assets should they no longer be probable
of recovery in future rates.
Contingencies
Loss contingencies are recorded as liabilities when it is probable
that a liability has been incurred and the amount of the loss is rea-
sonably estimable in accordance with SFAS No. 5, “Accounting for
Contingencies.” Estimating probable losses requires an analysis of
uncertainties that often depend upon judgments about potential
actions by third parties. In the normal course of business, accruals
are recorded for loss contingencies based on an analysis of poten-
tial results, developed in consultation with outside counsel when
appropriate, including allowances for uncollectible accounts, envi-
ronmental claims and property damage and personal injury claims.
Where information is sufficient to estimate only a range of prob-
able liability, and no point within the range is more likely than any
other, the Company recognizes an accrued liability at the lower end
of the range. It is possible, however, that future results of opera-
tions could be materially affected by changes in assumptions or
estimates regarding these contingencies. With respect to environ-
mental claims and related litigation costs, receivables are recorded
for anticipated recoveries under insurance contracts based on
amounts the Company estimates are probable of recovery. If these
amounts are not recovered from insurance, the Company believes
that recovery is probable from future utility rates based on current
approval by the OPUC to defer these costs as a regulatory asset.
See Note 12.
RESULTS OF OPERATIONS
Regulatory Matters
NW Natural provides gas utility service in Oregon and Wash-
ington, with Oregon representing over 90 percent of its revenues.
Future earnings and cash flows from utility operations will be de-
termined largely by the pace of continued growth in the residential
and commercial markets and by NW Natural’s ability to remain
price competitive in the large industrial market, to control ex-
penses, and to obtain reasonable and timely regulatory ratemaking
treatment for its operating and maintenance costs and investments
made in utility plant.
General Rate Cases
NW Natural’s most recent general rate increase in Oregon,
which was effective Sept. 1, 2003, authorized rates designed to
produce a return on shareholders’ equity (ROE) of 10.2 percent.
The OPUC approved a revenue increase of $13.9 million per year,
of which $6.2 million went into effect on Sept. 1, 2003, and $2.7
million went into effect on a deferred basis on Nov. 12, 2003 as the
first 11.7 miles of the Company’s southern portion of SMPE went
into service. The remaining $3.8 million for the southern portion
of the SMPE went into effect on Oct. 1, 2004, upon the completion
and placement into service of the last segment of the SMPE proj-
ect. Recovery for the Company’s Coos County distribution system
project of $1.2 million went into effect on Nov. 1, 2004, on a de-
ferred basis. While not included in the rate case result, an addi-
tional annual rate recovery of $7.5 million associated with the
northern portion of SMPE became effective Oct. 1, 2004.
In November 2003, NW Natural filed a general rate case in
Washington that proposed a revenue increase of $7.9 million per
year from Washington operations through rate increases averag-
ing 15 percent. In June 2004, the WUTC approved a settlement
agreement entered into by the parties to NW Natural’s Washing-
ton general rate case, which became effective on July 1, 2004, au-
thorizing a revenue increase of $3.5 million per year, or 6.5 per-
cent. In addition, the settlement authorized NW Natural to include
the SMPE cost of service of approximately $0.7 million per year
in rates, subject to audit, concurrent with the annual Washington
PGA filing, which became effective on Nov. 1, 2004. See “Rate
Mechanisms,” below.
Notwithstanding authorized revenue levels approved by the
OPUC or the WUTC, actual revenues are dependent on weather,
economic conditions, customer growth, competition and other fac-
tors affecting gas usage in NW Natural’s service area.
In January 2005, the Company filed a rate case with the Federal
Energy Regulatory Commission (FERC) proposing an update of
maximum rates for the Company’s interstate storage services op-
eration and new service offerings. The requested new rates are de-
signed to reflect the costs related to the further development of the
Mist gas storage facilities and costs associated with the SMPE proj-
ect. This filing was made to satisfy FERC’s requirement that there
be a cost and revenue review in three years following its original
storage service rate authorization.
Rate Mechanisms
WEATHER NORMALIZATION. In November 2003, NW Natural im-
plemented a weather normalization mechanism in Oregon that
helps stabilize net operating revenues, or margin, by adjusting cur-
rent customer billings based on temperature variances from aver-
age weather. The weather normalization mechanism approved by
the OPUC is applied to Oregon residential and commercial custom-
ers’ bills between Nov. 15 and May 15 of each heating season. The
mechanism adjusts the margin component of customers’ rates to
reflect “normal” weather using the 25-year average temperature
for each day of the billing period. The mechanism is intended to
stabilize fixed costs and to reduce fluctuations in customers’ bills
due to colder- or warmer-than-average weather. In October 2004,
the mechanism was modified to limit the upward or downward
adjustments to individual bills to certain specified ranges, with any
excess amounts being deferred (see “Residential and Commercial
Sales,” below).
N W N AT U R A L
21
Management’s Discussion and Analysis
PURCHASED GAS ADJUSTMENT. Rate changes are applied each
year under the PGA mechanisms in NW Natural’s tariffs in Oregon
and Washington to reflect changes in the costs of natural gas com-
modity purchased under contracts with gas producers (see “Com-
parison of Gas Operations – Cost of Gas Sold,” below), the appli-
cation of temporary rate adjustments to amortize balances in
regulatory asset or liability accounts and the removal of temporary
rate adjustments effective the previous year. Pursuant to the PGA
tariffs, in September 2004, the OPUC approved rate increases ef-
fective Oct. 1, 2004 averaging 20.1 percent for Oregon residential
sales customers, and in October 2004, the WUTC approved rate in-
creases effective Nov. 1, 2004 averaging 19.5 percent for Washing-
ton residential sales customers. These rate increases include de-
ferred revenue from the costs related to the SMPE project, which
was completed and placed into service on Sept. 22, 2004. The
Oregon increase of 20.1 percent consisted of recovery of gas costs
(13.9 percent), temporary rate adjustments (2.5 percent, including
deferrals for SMPE) and the recovery of SMPE costs of service (3.7
percent). The Washington increase of 19.5 percent consisted of the
recovery of gas costs (12.0 percent), temporary rate adjustments
(6.3 percent), and the recovery of SMPE costs (1.2 percent). The
inclusion of SMPE costs in Oregon and Washington rates resulted
in additional revenue increases totaling $14.7 million per year. Dur-
ing the fourth quarter of 2004, the staff of the OPUC initiated a re-
view of gas purchasing strategies for all three local gas distribution
companies serving Oregon. The schedule, scope and potential find-
ings, including the matter of whether the review will lead to formal
proceedings before the OPUC, remain uncertain.
In 2003, the OPUC approved a PGA rate increase averaging 3.5
percent for Oregon sales customers and the WUTC approved a PGA
rate increase averaging 16.8 percent for Washington sales custom-
ers, both effective on Oct. 1, 2003. In 2002, the OPUC approved PGA
rate decreases averaging 14 percent for Oregon sales customers and
the WUTC approved PGA rate decreases averaging 25 percent for
Washington sales customers, both effective on Oct. 1, 2002.
The OPUC has formalized a process that tests for excessive earn-
ings in connection with gas utilities’ annual filings under their PGA
mechanisms. The OPUC has confirmed NW Natural’s ability to
pass through 100 percent of its prudently incurred gas costs into
rates. Under this requirement, NW Natural is authorized to retain
all of its earnings up to a threshold level equal to its authorized
ROE plus 300 basis points. One-third of any earnings above that
level will be refunded to customers. The excess earnings threshold
is subject to adjustment up or down each year depending on move-
ments in interest rates. No amounts were identified in this process
for refund to customers with respect to 2003 or 2002 earnings re-
sults. NW Natural does not expect that amounts will be identified
for refund with respect to its earnings in 2004, which will be re-
viewed by the OPUC in the second quarter of 2005.
CONSERVATION TARIFF. Effective Oct. 1, 2002, the OPUC autho-
rized NW Natural to implement a “conservation tariff,” a mecha-
nism designed to recover lost margin due to changes in residential
and commercial customers’ consumption patterns. The tariff is a
partial decoupling mechanism that breaks the link between the
Company’s earnings and the quantity of energy consumed by its
customers, so the Company does not have an incentive to discour-
age customers’ conservation efforts.
The conservation tariff includes two components. The first, a
price elasticity factor, adjusts for increases or decreases in con-
sumption attributable to annual changes in commodity costs or
periodic changes in the Company’s general rates. The second is a
conservation adjustment calculated on a monthly basis to account
for deviations between actual and expected volumes. Additional
22
N W N AT U R A L
revenues or credits to customers produced by the conservation ad-
justment are booked to a deferral account that is reconciled as part
of the Company’s annual PGA. Baseline consumption is based on
customer consumption patterns as determined in the 2003 Oregon
general rate case, adjusted for consumption resulting from new
customers. The partial decoupling mechanism will expire at the
end of September 2005 unless the OPUC approves an extension
based on the results of an independent study to measure the mech-
anism’s effectiveness. Work on the independent review, which in-
volves interested parties, is in process and is expected to be com-
pleted by the end of March 2005. The study is expected to provide
the basis for the Company’s filing to renew the tariff.
PIPELINE INTEGRITY COST RECOVERY. In July 2004, the OPUC ap-
proved applications by NW Natural relating to the accounting treat-
ment and full recovery for the Company’s cost of its pipeline integ-
rity management program (IMP) as mandated by the Pipeline
Safety Improvement Act of 2002 (Pipeline Safety Act) and related
rules adopted by the U.S. Department of Transportation’s Office of
Pipeline Safety (see “Financial Condition – Cash Flows – Investing
Activities,” below). Under the applications as approved, NW Nat-
ural classifies its IMP costs as either capital expenditures or regu-
latory assets, accumulates the costs over each 12-month period
ending June 30, and recovers the costs, subject to audit, through
rate changes effective on October 1 of each year commencing Oct.
1, 2004. The approved accounting and rate treatment for these
costs extends through Sept. 30, 2008, and may be reviewed for po-
tential extension after that date. NW Natural will begin including
IMP costs in rates in 2005.
OPEN PATHWAY TARIFF. The open pathway tariff, approved by the
OPUC on Dec. 7, 2004, requires developers to provide the Company
with a trench for installation of mains and services in new devel-
opments. If a trench is not provided, the tariff requires the devel-
oper to pay NW Natural’s costs of trenching. In the past, provision
of a trench or reimbursement was not required. Implementation of
the tariff began in early 2005.
OPUC Investigation
In August 2004, the OPUC approved a stipulation among NW
Natural, the OPUC staff and two parties in the 2003 Oregon general
rate case, providing for the settlement of issues raised in an inves-
tigation initiated by the OPUC in 2003. These issues relate to trans-
actions or interests in certain properties involving NW Natural in
the vicinity of its headquarters building in downtown Portland, and
the use of some of these properties for employee parking. The pri-
mary effect of the stipulation was to reverse cost recovery as of
Sept. 1, 2003, for certain properties that should not have been in-
cluded in rate base in the 2003 Oregon general rate case, and for
certain employee parking costs. Pursuant to the stipulation, NW
Natural commenced paying refunds in the amount of $1.3 million
to Oregon customers on Oct. 1, 2004, in connection with the an-
nual Oregon PGA filing effective on that date. Approximately $0.3
million of that amount was charged to a reserve in 2003 and the
first quarter of 2004; approximately $0.9 million was recognized as
a reduction in other revenues in the second quarter of 2004; and
the balance of $0.1 million was recognized as a reduction in other
revenues in the third quarter of 2004. Effective Oct. 1, 2004, Oregon
revenues were reduced by about $0.3 million per year to eliminate
these costs from future rates. NW Natural agreed in the stipulation
to undergo an audit in 2005 funded by the Company, which is ex-
pected to focus on ratemaking issues relating to the inclusion of
assets in rate base and NW Natural’s transactions with any affili-
ated interests. The OPUC staff informed the Company that the re-
quired audit will be performed during the third quarter of 2005.
Comparison of Gas Distribution Operations
The following table summarizes the composition of gas utility
volumes and revenues for the three years ended Dec. 31:
Thousands, except
customers and degree days
2004
2003
2002
Utility volumes – therms:
Residential and
commercial sales
Industrial sales and
transportation
Total utility volumes
sold and delivered
574,925 51%
581,890 53%
590,629 52%
535,455 48%
517,862 47%
__________ _____ __________ _____ __________ _____
556,941 49%
1,131,866 100%
1,126,084 100%
1,099,752 100%
__________ _____ __________ _____ __________ _____
__________ _____ __________ _____ __________ _____
Utility operating revenues – dollars:
Residential and
commercial sales
Industrial sales and
transportation
Other revenues
Total utility
3,185
$ 585,100 83% $ 519,323 86% $ 543,508 86%
84,922 13%
75,201 13%
1%
1%
7,460
__________ _____ __________ _____ __________ _____
112,660 16%
1%
4,018
operating revenues $ 700,945 100% $ 601,984 100% $ 632,448 100%
_____
_____
_____
_____
_____
_____
399,176
__________
$ 301,769
__________
__________
Cost of gas sold
Utility net operating
revenues (margin)
Total number of
customers (end of year) 596,635
Actual degree days
3,853
Percent colder
(warmer) than normal
(25-year average degree
days is used as normal)
(8%)
323,128
__________
353,034
__________
$ 278,856
__________
__________
$ 279,414
__________
__________
578,150
3,952
560,067
4,232
(7%)
(1%)
NW Natural continued to grow its customer base, with a net in-
crease of 18,485 customers during 2004. The growth rate for both
2004 and 2003 was 3.2 percent, compared to 3.5 percent in 2002.
In the three years ended Dec. 31, 2004, more than 55,000 custom-
ers were added to the system, representing an average annual
growth rate of 3.4 percent.
Residential and Commercial Sales
The following table summarizes the utility volumes and utility
operating revenues in the residential and commercial markets. The
primary factors that impact the results of operations in these mar-
kets are seasonal weather patterns, competitive factors in the energy
industry and economic conditions in the Company’s service areas.
Thousands, except customer data
2004
2003
2002
343,534
226,257
12,099
__________
581,890
__________
__________
357,091
240,155
(6,617)
__________
590,629
__________
__________
Utility volumes – therms:
356,199
Residential sales
226,490
Commercial sales
(7,764)
Change in unbilled sales
__________
Total weather-sensitive utility volumes 574,925
__________
__________
Utility operating revenues – dollars:
Residential sales
Commercial sales
Change in unbilled sales
Total weather-sensitive utility
revenues
Total number of residential and
commercial customers (end of year)
595,700
$ 381,526 $ 328,464 $ 354,735
201,475
176,385
199,725
(12,702)
14,474
3,849
__________
__________
__________
$ 585,100 $ 519,323 $ 543,508
__________
__________
__________
__________
__________
__________
577,396
559,489
2004 compared to 2003:
■ volumes sold were 1 percent lower, reflecting the effect of 3
percent warmer weather that was partially offset by the impact
of 3 percent customer growth; and
■ operating revenues were 13 percent higher, primarily due to
higher rates effective Oct. 1, 2003 and Oct. 1, 2004 (see “Regula-
tory Matters – Rate Mechanisms,” above).
2003 compared to 2002:
■ volumes sold were 1 percent lower, reflecting the effects of 7
percent warmer weather that was partially offset by the impact
of 3 percent customer growth and the price elasticity effect of
lower rates effective Oct. 1, 2002; and
■ operating revenues were 4 percent lower in 2003 than in 2002.
Excluding the impact of gas cost refunds totaling $30.4 million
during 2002, revenues were $54.6 million, or 10 percent, lower
in 2003 than in 2002, primarily due to lower rates effective
Oct. 1, 2002.
Typically, 80 percent or more of annual utility operating reve-
nues are derived from gas sales to weather-sensitive residential and
commercial customers. Although variations in temperatures be-
tween periods will affect volumes of gas sold to these customers,
the effect on margin and net income was significantly reduced with
the implementation of the weather normalization mechanism in
Oregon beginning in November 2003 (see “Regulatory Matters –
Rate Mechanisms,” above). This mechanism applies to meter read-
ings of participating Oregon customers taken between Nov. 15 and
May 15. Approximately 10 percent of NW Natural’s residential and
commercial customers are in Washington, where the mechanism
is not in effect, and about 8 percent of the eligible Oregon custom-
ers elected not to be covered by the mechanism, so the mechanism
does not fully insulate the Company from utility earnings volatility
due to weather. The mechanism contributed a net $9.0 million of
margin, equivalent to 20 cents a share of earnings, in the twelve
month period ended Dec. 31, 2004, making up a significant portion
of the margin that otherwise would have been lost from warmer-
than-average weather. In 2003, the mechanism contributed $1.9
million of margin, equivalent to 5 cents a share of earnings, in the
two-months after becoming effective in November 2003.
Total utility operating revenues include accruals for gas deliv-
ered but not yet billed to customers (unbilled revenues) based on
estimates of gas deliveries from that month’s meter reading dates
to month end. Amounts reported as unbilled revenues reflect the
increase or decrease in the balance of accrued unbilled revenues
compared to the prior year-end. Weather conditions, rate changes
and customer billing dates affect the balance of accrued unbilled
revenue at the end of each month. At Dec. 31, 2004, accrued un-
billed revenue was $64.4 million, compared to $59.1 million at Dec.
31, 2003.
Industrial Sales and Transportation
The following table summarizes the delivered volumes and util-
ity operating revenues in the industrial and electric generation
markets:
Thousands, except customers
2004
2003
2002
Utility volumes – therms:
Industrial firm sales
Industrial interruptible sales
Electric generation sales and
transportation
Transportation
Total utility volumes
Utility operating revenues – dollars:
Industrial firm sales
Industrial interruptible sales
Electric generation sales and
transportation
Transportation
Total utility revenues
Total number of industrial sales and
transportation customers (end of year)
63,149
104,278
55,314
46,327
63,215
22,841
–
389,514
__________
556,941
__________
__________
1,667
414,554
__________
517,862
__________
__________
3,400
445,999
__________
535,455
__________
__________
$
44,625 $
55,380
33,578 $
23,655
42,965
11,346
–
12,655
__________
$ 112,660 $
__________
__________
6
17,962
__________
75,201 $
__________
__________
4,591
26,020
__________
84,922
__________
__________
935
754
578
Total volumes delivered to industrial and electric generation
customers were 39 million therms, or 7 percent, higher in 2004
than in 2003, and utility operating revenues were up $37 million,
or 50 percent. The higher volumes and revenues partially reflect
an improving economy, but results primarily reflect a continued
shift from transportation to sales volumes and the reclassification
of a relatively large number of commercial customers to the indus-
trial customer category over the past 24 months resulting from new
N W N AT U R A L
23
Management’s Discussion and Analysis
rate design changes in Oregon. Over the past two years, the num-
ber of industrial customers increased 30 percent from 2002 to 2003,
and 24 percent from 2003 to 2004. Industrial rates in Oregon were
redesigned as part of the general rate case in 2003, transferring $4.8
million of annual revenue requirement from industrial rates to res-
idential and commercial rates in order to better reflect relative costs
of service and to improve the competitiveness of the Company’s
rates in the industrial market.
Total volumes delivered to industrial and electric generation cus-
tomers were 18 million therms, or 3 percent, lower in 2003 than in
2002, and utility operating revenues were down $10 million, or 11
percent. Results from the industrial market in 2003 reflect weaker
economic conditions during the year, and most of the incremental
revenue decline was due to a shift from higher margin firm sched-
ules to lower margin interruptible schedules and industrial rate de-
creases effective in September 2003.
The decline in volumes and operating revenues from the elec-
tric generation market primarily reflect the winding down of a
temporary market that emerged in response to the 2001-2002 en-
ergy crisis. The volumes and operating revenues in 2002 were re-
lated to two customers served under contracts that went into effect
in the second half of 2001 and expired at the end of the second
quarter of 2002. Most of the revenues from these contracts were
derived from fixed charges. A third electric generation customer
used 3.0 million therms in 2002 under a contract with low volu-
metric charges.
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 (see Note 1). Other revenues increased net operating
revenues by $3.2 million in 2004, compared to $7.5 million in 2003
and $4.0 million in 2002. The following table summarizes other
revenues by primary category for the three years ended Dec. 31,
2004, 2003 and 2002:
Thousands
2004
2003
2002
Revenue adjustments:
Current deferrals:
Decoupling
SMPE
OPUC investigation
Coos Bay
Other
Current amortizations:
Interstate gas storage credits
Decoupling
SMPE
Conservation programs
Year 2000 technology costs
Other
Net revenue adjustments
Miscellaneous revenues:
Customer fees
Other
Total miscellaneous revenues
Total other revenues
$
681 $
1,475
(690)
244
35
3,466 $
643
–
–
82
1,720
–
–
–
–
5,324
(2,952)
(601)
(2,835)
(1,293)
298
__________
(314)
__________
3,057
(783)
–
(2,408)
(949)
558
__________
3,666
__________
1,212
–
–
(2,074)
(1,539)
–
__________
(681)
__________
3,245
254
__________
3,499
__________
3,185 $
$
__________
__________
3,327
467
__________
3,794
__________
7,460 $
__________
__________
3,115
1,584
__________
4,699
__________
4,018
__________
__________
Other revenues in 2004 were $4.3 million lower than in 2003
primarily due to the change in decoupling deferrals under the de-
coupling mechanism (down $2.8 million) (see “Regulatory Mat-
ters – Rate Mechanisms,” above), the amortization of decoupling
deferrals from prior periods (up $2.2 million) and an increase in
other miscellaneous amortizations (up $1.6 million), partially off-
set by higher interstate storage credits from revenue sharing from
the Company’s interstate gas storage services (up $2.3 million).
Other revenues in 2003 included positive contributions due to
the change in decoupling deferrals (up $1.7 million), the amortiza-
24
N W N AT U R A L
tion of income shared with customers from interstate gas storage
services (up $1.8 million), and customer late payment and collec-
tion fees and miscellaneous revenues, partially offset by amortiza-
tions from regulatory accounts covering conservation programs and
Year 2000 technology costs.
Cost of Gas Sold
Natural gas commodity prices have fluctuated significantly in
recent years. The effects of higher gas commodity prices and price
volatility on core utility customers are mitigated through the use
of underground storage facilities, gas commodity-price financial
hedge contracts, and short-term sales of gas commodity and trans-
portation capacity to on-system or off-system customers in periods
when core utility customers do not require the full firm pipeline
capacity and gas supplies.
The Company regularly renews or replaces its expiring long-
term and medium-term contracts with new agreements with a va-
riety of existing and new suppliers. No single contract amounts to
more than 200,000 therms per day or 10 percent of the Company’s
average daily contract volumes. Firm year-round supply contracts
have terms ranging from one to ten years. All of the contracts use
price formulas tied to monthly index prices, primarily at the NOVA
Inventory Transfer trading point in Alberta. NW Natural hedges a
majority of its contracts each year using financial instruments as
part of its gas purchase strategy.
The total cost of gas sold was $399.2 million in 2004, an in-
crease of $76.1 million or 24 percent compared to 2003 and, 2003
was $29.9 million or 8 percent lower than 2002. The cost per therm
of gas sold was 14 percent higher in 2004 than in 2003 and 9 per-
cent lower in 2003 than in 2002. The cost per therm of gas sold in-
cludes current gas purchases, gas drawn from storage inventory,
gains or losses from commodity hedges, margin from off-system
gas sales, demand cost balancing adjustments (demand equaliza-
tion), regulatory deferrals and company use. Results for 2002 in-
cluded an adjustment that reduced cost of gas by $29.5 million, a
result of a refund to customers. Excluding this adjustment, cost per
therm of gas sold was 16 percent lower in 2003 than in 2002, re-
flecting decreases in gas commodity prices effective in late 2002.
Results for 2002 also included adjustments reducing cost of gas
relating to amounts of deferred expenses for the recovery of pipe-
line demand charges under the PGA mechanism. These adjust-
ments contributed 7 cents a share to earnings in 2002, of which 6
cents a share applied to periods prior to 2002. The rate methodol-
ogy represented in the adjustments continues to be applied in the
Company’s accounting for pipeline demand charges.
NW Natural’s recorded amount of unaccounted-for gas was 0.51
percent of gas sendout in 2004, compared to 0.55 percent in 2003
and 0.75 percent in 2002. Unaccounted-for gas is the difference be-
tween the amount of gas the Company receives from all sources,
including pipeline deliveries and withdrawals from storage, and
the amount of gas it delivers to customers or other delivery points.
Unaccounted-for gas may be caused in part by physical gas leak-
age, but it also may be due to cumulative inaccuracies in gas me-
tering, estimates of unbilled gas or other causes. A normal amount
of unaccounted-for gas is considered to be 0.50 percent of total gas
sendout during a period, but the amounts may vary within a range
around this estimate. During 2004, the lower estimated amount of
unaccounted-for gas had the effect of increasing cost of gas and
decreasing margin by $0.4 million as compared to 2003. During
2003, the lower estimated amount of unaccounted-for gas had the
effect of reducing cost of gas and increasing margin by $1.2 million
as compared to 2002. The estimated percentages of unaccounted-
for gas in 2004 and 2003 were lower than 2002, partially due to
improvements in gas measurement and estimating.
NW Natural uses a natural gas commodity-price hedge program
under the terms of its Derivatives Policy to help manage its vari-
able price gas commodity contracts (see “Application of Critical
Accounting Policies and Estimates – Accounting for Derivative In-
struments and Hedging Activities,” above). NW Natural recorded
net hedging gains of $42.4 million from this program during 2004,
compared to net hedging gains of $32.4 million in 2003 and net
hedging losses of $75.5 million in 2002. Hedging gains and losses
relating to gas commodity purchases are included in cost of gas
and factored into NW Natural’s annual PGA rate changes, and
therefore have no material impact on net income.
Under NW Natural’s PGA tariff in Oregon, net income is affected
within defined limits by changes in purchased gas costs. NW Nat-
ural is allowed to collect an amount for purchased gas costs based
on estimates that are included in current utility rates. If the actual
purchased gas costs are higher than the amounts included in rates,
NW Natural is not allowed to charge its customers currently for
those higher gas costs but is allowed to defer the costs and collect
them in the future. Similarly, when the actual purchased gas costs
are lower than the amount included in rates, the savings are not
immediately passed on to customers but are deferred and refunded
in future periods. NW Natural absorbs 33 percent of the higher cost
of gas sold, or retains 33 percent of the lower cost, in either case
as compared to the projected costs built into rates. The remaining
67 percent of the higher or lower gas costs is recorded as deferred
regulatory assets or liabilities for recovery from or refund to cus-
tomers in future rates. In 2004 and 2003, NW Natural’s gas costs
were slightly lower than the gas costs embedded in rates, with the
effect that NW Natural’s share of the lower costs increased margin
by $0.6 million and $0.3 million, equivalent to 1 cent a share and
less than 1 cent a share of earnings, respectively. In 2002, NW Nat-
ural’s gas costs were much lower than the projected costs built into
rates and the Company’s share of the savings realized from gas
purchases contributed $10.8 million of margin, equivalent to 26
cents a share of earnings.
NW Natural uses gas supplies and transportation capacity that
are not required for core utility residential, commercial and indus-
trial firm customers to make off-system sales. Under the PGA tariff
in Oregon, NW Natural retains 33 percent of the margins realized
from its off-system gas sales and records the remaining 67 percent
as a deferred regulatory asset or liability for recovery from or re-
fund to customers in future rates. NW Natural’s share of margin
from off-system gas sales in 2004 resulted in a loss of $0.3 million,
equivalent to less than 1 cent a share. NW Natural’s share of mar-
gin from off-system gas sales in 2003 was $4.9 million, equivalent
to 11 cents a share of earnings. Results for 2003 reflected a higher
volume of off-system gas sales because of warmer weather in the
first quarter and higher gas prices. NW Natural was able to use gas
supplies that were available under contract for the winter season,
but not required for delivery to core utility market customers, to
make these off-system sales. NW Natural’s purchase price for this
gas had been fixed through commodity swap and call option con-
tracts entered into earlier at levels substantially below the market
prices in 2003. NW Natural’s share of margin from off-system sales
in 2002 was $0.9 million or 2 cents a share.
Business Segments Other than Local Gas Distribution
Interstate Gas Storage
NW Natural earned net income from its non-utility interstate gas
storage business segment in 2004, after regulatory sharing and in-
come taxes, of $2.9 million or 11 cents a share, compared to $4.3
million or 17 cents a share in 2003 and $3.6 million or 14 cents a
share in 2002 (see Note 2). Earnings from this business segment
were lower in 2004 primarily due to a lower contribution from a
contract with an independent energy marketing company that op-
timizes the value of NW Natural’s assets by engaging in trading ac-
tivities using temporarily unused portions of its upstream pipeline
transportation capacity and gas storage capacity. The lower contri-
bution was primarily due to a change in market conditions in which
gas price differentials were less volatile in 2004 compared to 2003.
In Oregon, NW Natural retains 80 percent of the pre-tax income
from the interstate storage services and optimization of storage and
pipeline transportation capacity when the costs of such capacity
have not been included in core utility rates, and 33 percent of the
pre-tax income from such optimization when the capacity 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 NW Natural’s core utility customers.
NW Natural has a similar sharing mechanism in Washington for
revenue derived from third party optimization services.
Subsidiaries
Financial Corporation
Financial Corporation’s operating results in 2004 were net in-
come of $0.2 million, compared to $0.7 million in 2003 and $1.2
million in 2002. The decrease in net income in 2004 compared to
2003 was primarily due to a $0.5 million write-down of its limited
partnership interests in three solar electric generation projects. The
write-down related to an agreement to sell these projects on Jan.
31, 2005. The decrease in net income in 2003 compared to 2002
was due to lower income from investments in limited partnerships
in wind and solar electric generation projects in California.
The Company’s investment in Financial Corporation was $5.7
million at Dec. 31, 2004, compared to $5.5 million at Dec. 31, 2003.
Northwest Energy
Northwest Energy was formed in 2001 to serve as the holding
company for NW Natural and PGE if the acquisition of PGE had
been completed. Northwest Energy recorded nominal expenses for
corporate development activities in 2004. Upon the termination of
the proposed acquisition effort in 2002, Northwest Energy recorded
a loss totaling $8.4 million (after tax) for the transaction costs in-
curred in connection with this effort. These charges were equiva-
lent to 33 cents a share. Northwest Energy was inactive during both
2004 and 2003.
Operating Expenses
Operations and Maintenance
Operations and maintenance expenses increased $5.7 million,
or 6 percent, in 2004 compared to 2003, and increased $11.3 mil-
lion, or 13 percent, in 2003 compared to 2002. The following sum-
marizes the major factors that contributed to changes in operations
and maintenance expense:
2004 compared to 2003
■ payroll and payroll-related expenses, including pension and
health care costs, increased by $3.5 million due to salary and
wage increases averaging 3 to 4 percent; and a change in the
pension discount rate assumption and rising health care premi-
ums (see Note 7);
■ expenses for compliance activities relating to the Sarbanes-
Oxley Act of 2002 increased by $1.5 million;
■ uncollectible accounts expense increased by $1.3 million due
to increases in gross revenues stemming from higher rates;
■ gas technology research costs increased by $0.3 million;
■ workers compensation expense decreased by $0.4 million; and
■ energy efficiency rebate costs decreased by $0.8 million.
2003 compared to 2002
■ payroll and payroll-related expenses including pension and
health care costs, increased by $8.9 million due to salary, wage
and bonus increases, increased vacation accruals and increased
pension costs due to a change in the pension discount rate as-
sumption and pension fund losses in 2001 and 2002 (see Note 7);
N W N AT U R A L
25
Management’s Discussion and Analysis
■ business risk insurance and workers compensation insurance
premiums increased by $1.2 million;
■ professional service fees and contract labor increased by
$1.2 million;
■ workers compensation claims expense increased by $0.5 mil-
lion primarily due to a single claim incurred in 2003;
■ other operating costs increased $0.4 million; and
■ uncollectible accounts expense decreased by $0.9 million due
to improvements in collection rates and lower net write-offs of
accounts receivable.
Most of the cost increases NW Natural experienced in 2004 and
2003 were included in the rate increases approved in the Compa-
ny’s general rate cases in Oregon and Washington (see “Regulatory
Matters – General Rate Cases,” above).
Taxes Other Than Income Taxes
Taxes other than income taxes, which are principally comprised
of property, franchise and payroll taxes, increased $3.7 million, or
11 percent, in 2004 compared to 2003, and increased $1.0 million,
or 3 percent, in 2003 compared to 2002. The following table sum-
marizes the changes in taxes other than income taxes:
Thousands
Franchise taxes
Payroll taxes
Property taxes
Other taxes
Total increase
–––– Increase (Decrease) ––––
2003
2004
$
2,215 $
1,078
732
(342)
__________
3,683 $
__________
__________
(92)
232
930
(21)
__________
1,049
__________
__________
$
The increase in franchise taxes in 2004 is primarily related to the
increase in total utility operating revenues resulting from higher
gas rates (see “Comparison of Gas Distribution Operations,” above);
the increase in payroll taxes is primarily related to the increase in
payroll expense (see “Operations and Maintenance,” above); and
the increase in property taxes is primarily related to increased util-
ity plant in service (see Note 9).
Depreciation and Amortization
The following table summarizes the increases in total plant and
property and total depreciation and amortization for the three years
ended Dec. 31, 2004:
Thousands
2004
2003
2002
Plant and property:
Utility plant:
Depreciable
Non-depreciable, including
construction work in progress
Non-utility property:
Depreciable
Non-depreciable, including
construction work in progress
Total plant and property
Depreciation and amortization:
Utility plant
Non-utility property
Total depreciation and
amortization expense
Weighted average depreciation
rate – utility
Weighted average depreciation
rate – non-utility
$ 1,771,890 $ 1,595,759 $ 1,498,903
23,082
__________
1,794,972
__________
61,830
__________
1,657,589
__________
41,062
__________
1,539,965
__________
29,628
22,353
20,832
–
1,042
4,335
__________
__________
__________
23,395
33,963
20,832
__________
__________
__________
$ 1,828,935 $ 1,680,984 $ 1,560,797
__________
__________
__________
__________
__________
__________
$
56,899 $
472
__________
53,798 $
451
__________
51,693
397
__________
$
__________
__________
57,371 $
__________
__________
54,249 $
52,090
__________
__________
3.4%
2.3%
3.5%
2.3%
3.5%
1.9%
The Company’s total depreciation and amortization expense in-
creased by $3.1 million, or 6 percent, in 2004 and by $2.2 million,
or 4 percent, in 2003. The increased expense for both years is pri-
marily due to additional investments in utility property that were
made to meet continuing customer growth, including the Compa-
ny’s investment in the SMPE that was put into service in Novem-
ber 2003 and September 2004 (see “Financial Condition – Cash
26
N W N AT U R A L
Flows – Investing Activities,” below).
Other Income (Expense)
Other income (expense) improved by $0.7 million in 2004. The
increase was primarily due to reductions in interest charges on de-
ferred regulatory account balances ($1.1 million) reflecting lower
net credit balances outstanding in these accounts. This increase
was partially offset by a decrease in gains from Company-owned
life insurance ($0.6 million) due to decreases in the market value
of equity-based life insurance investments.
Other income (expense) improved by $17.0 million in 2003, pri-
marily due to the $13.9 million pre-tax charge in 2002 for costs in-
curred in the effort to acquire PGE. Excluding this charge, other
income (expense) increased by $3.1 million in 2003. The increase
was primarily due to reductions in interest charges on deferred
regulatory account balances ($1.4 million) reflecting lower net
credit balances outstanding in these accounts, and an increase in
gains from Company-owned life insurance ($2.0 million) due to
increases in the market value of equity-based life insurance invest-
ments, partially offset by a decrease in earnings from equity invest-
ments ($0.5 million) due to lower income from partnership invest-
ments held by Financial Corporation.
Interest Charges – Net of Amounts Capitalized
Interest charges–net of amounts capitalized in 2004 was $0.7
million, or 2 percent, higher than in 2003. The increase in 2004
was primarily due to higher balances of debt outstanding during
the period. The increase was partially offset by lower average in-
terest rates and higher amounts of Allowance for Funds Used Dur-
ing Construction (AFUDC) due to higher average balances of con-
struction work in progress (CWIP). AFUDC represents the cost of
funds used for CWIP (see Note 1). In 2004, AFUDC reduced inter-
est expense by $1.0 million compared to reductions of $0.9 million
in 2003 and $0.6 million in 2002. The average interest rate compo-
nent of AFUDC, comprised of short-term and long-term borrowing
rates, as appropriate, was 3.0 percent in 2004, 2.3 percent in 2003
and 2.8 percent in 2002.
Interest charges–net of amounts capitalized in 2003 was $1.0
million, or 3 percent, higher than in 2002, also due to higher bal-
ances of debt outstanding and to the inclusion of dividends paid
in the second half of 2003 totaling $0.2 million on the Company’s
redeemable preferred stock, due to their classification as interest
expense upon the adoption of SFAS No. 150, “Accounting for Cer-
tain Financial Instruments with Characteristics of both Liabilities
and Equity.”
Income Taxes
The effective corporate income tax rates were 34.4 percent, 33.7
percent and 34.9 percent for the years ended Dec. 31, 2004, 2003
and 2002, respectively. The higher rate in 2004 reflects the effect
of decreased tax benefits from a non-taxable gain on Company- and
trust-owned life insurance ($0.6 million), decreased tax benefits
attributed to tax adjustments recorded in the prior year ($0.3 mil-
lion), decreased tax benefits resulting from a taxable gain on the
surrender of certain Company-owned life insurance ($0.1 million)
and the expiration of a federal low-income housing tax credit ($0.1
million), partially offset by the effect of increased tax benefits from
an adjustment of the Company’s deferred income tax balances
($0.5 million). Excluding the impact of these tax benefits taken into
account during 2004, the effective tax rate for 2004 would have
been 35.0 percent. The lower tax rate for 2003 reflects increased
tax benefits from a non-taxable gain on Company- and trust-owned
life insurance. Excluding these benefits, the effective tax rate for
2003 would have been 35.0 percent. The tax rate for 2002 includes
the effect of the tax benefits from the $13.9 million charge for PGE
transaction costs. Excluding this charge, the effective tax rate for
2002 would have been 35.6 percent.
Redeemable Preferred and Preference Stock
Dividend Requirements
Redeemable preferred and preference stock dividend require-
ments decreased $0.3 million in 2004 compared to 2003 due to
the redemption in November 2003 of all outstanding shares of
the Company’s $7.125 Series of Redeemable Preferred Stock with
an aggregate stated value of $7.5 million at the applicable early
redemption price of 102.375 percent. No shares of redeemable
preferred or preference stock were outstanding at any time dur-
ing 2004.
Redeemable preferred and preference stock dividend require-
ments decreased $2.0 million in 2003 compared to 2002 due to the
redemption in December 2002 of all of the outstanding shares ($25
million aggregate stated value) of the Company’s $6.95 Series of
Redeemable Preference Stock pursuant to the mandatory redemp-
tion provisions applicable to that Series.
FINANCIAL CONDITION
Capital Structure
The Company’s goal is to maintain a target capital structure
comprised 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 meet long-term debt redemption requirements and
short-term commercial paper maturities (see “Liquidity and Capi-
tal Resources,” below, and Notes 3 and 5). The Company’s con-
solidated capital structure at Dec. 31 was as follows:
2004
Year ended December 31,
2003
Common stock equity
Long-term debt
Short-term debt, including current maturities
of long-term debt
Total
48.7%
41.3%
46.4%
45.8%
10.0%
__________
100.0%
__________
__________
7.8%
__________
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 Dec. 31, 2004, the Company had $5.2 million in cash and
cash equivalents compared to $4.7 million at Dec. 31, 2003. Short-
term liquidity is provided by cash from operations and from the
sale of commercial paper notes, which are supported b y commit-
ted bank lines of credit. The Company has available through Sept.
30, 2005 committed lines of credit totaling $150 million with four
commercial banks (see “Lines of Credit,” below, and Note 6).
Short-term debt balances typically are reduced toward the end of
the winter heating season as a significant amount of the Company’s
current assets, including accounts receivable and natural gas in-
ventories, are converted into cash.
Capital expenditures primarily relate to utility construction re-
sulting from customer growth and system improvements (see “Cash
Flows – Investing Activities,” below). Certain contractual commit-
ments under capital leases, operating leases and gas supply pur-
chase 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, in February 2004 the Company
filed a universal shelf registration with the Securities and Exchange
Commission (SEC) providing for the issuance and sale of up to
$200 million of securities, which may consist of secured debt (First
Mortgage Bonds), unsecured debt, preferred stock or common
stock. Concurrent with this shelf filing, the Company deregistered
the $60 million of Medium-Term Notes (MTNs) remaining on its
previous shelf registration. The $200 million universal shelf regis-
tration statement became effective in February 2004. In April 2004,
the Company issued $40 million of common stock under the shelf
registration, leaving $160 million available for the issuance of debt
or equity securities (see “Financing Activities,” below).
Neither NW Natural’s Mortgage and Deed of Trust nor the in-
dentures under which other long-term debt is 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 counter-parties under
NW Natural’s Derivatives Policy which require the affected party to
provide substitute collateral such as cash, guaranty or letter 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 the
ability to issue long-term debt and equity securities, the Company
believes it has sufficient liquidity to satisfy its anticipated cash re-
quirements, including the contractual obligations and investing and
financing activities discussed below.
Dividend Policy
NW Natural has paid quarterly dividends on its common stock
in each year since the stock first was issued to the public in 1951.
Annual common dividend payments have increased each year
since 1956. The amount and timing of dividends payable on the
Company’s common stock are within the sole discretion of the
Company’s Board of Directors. It is the intention of the Board of
Directors to continue to pay cash dividends on the Company’s com-
mon stock on a quarterly basis. However, future dividends will be
dependent upon NW Natural’s earnings, its financial condition and
other factors.
Off-Balance Sheet Arrangements
The Company has no material off-balance sheet financing ar-
rangements.
Contractual Obligations
The following table shows the Company’s contractual obligations
by maturity and type of obligation. NW Natural also has obligations
with respect to its pension and post-retirement medical benefit
plans (see Note 7).
Thousands
Contractual Obligations
Commercial paper
Long–term debt
Interest on long–term debt
Capital leases
Operating leases
Gas purchase contracts1
Gas pipeline commitments
Other purchase commitments
Total
---------------------------------------------------- Payments Due in Years Ending Dec. 31, ----------------------------------------------------
2009
2008
2006
2005
2007
$ 102,500
15,000
33,213
230
4,491
277,371
62,988
12,162
__________
$ 507,955
__________
__________
$
–
8,000
32,561
189
4,136
184,572
57,800
147
__________
$ 287,405
__________
__________
$
–
29,500
31,085
97
3,967
167,093
58,981
–
__________
$ 290,723
__________
__________
$
–
5,000
30,268
29
3,836
150,898
57,234
–
__________
$ 247,265
__________
__________
$
–
–
30,052
–
3,834
62,155
50,702
–
__________
$ 146,743
__________
__________
Thereafter
$
–
441,527
373,744
–
38,908
112,684
271,796
–
__________
$ 1,238,659
__________
__________
Total
$ 102,500
499,027
530,923
545
59,172
954,773
559,501
12,309
__________
$ 2,718,750
__________
__________
1All gas purchase contracts use price formulas tied to monthly index prices. Commitment amounts are based on index prices at Dec. 31, 2004.
N W N AT U R A L
27
Management’s Discussion and Analysis
Other purchase commitments primarily consist of remaining
balances under existing purchase orders and remaining payments
due to a general contractor for the construction of the remaining
portion of the SMPE project. 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 exer-
cised, would accelerate the maturities by $10 million in 2005 and
by $20 million in each of 2007, 2008 and 2009. The interest coupon
rate on the long-term debt issues with put options range between
6.52 percent and 7.05 percent.
On March 12, 2004, NW Natural employees who are members
of the OPEIU, Local No. 11, approved a new labor agreement (Joint
Accord) covering wages, benefits and working conditions that will
expire on May 31, 2009. In accordance with the terms of the Joint
Accord, beginning Jan. 1, 2005, the Company will commence mak-
ing contributions to a multi-employer trust that will provide addi-
tional retirement benefits to its bargaining unit employees.
Commercial Paper
The Company’s primary source of short-term funds is from the
sale of commercial paper notes payable. In addition to issuing com-
mercial paper to meet seasonal working capital requirements, in-
cluding the financing of gas purchases and accounts receivable,
short-term debt is also used temporarily to fund capital require-
ments. Commercial paper is periodically refinanced through the
sale of long-term debt or equity securities. NW Natural’s outstand-
ing commercial paper, which is sold under an agency agreement
with a commercial bank, is supported by committed bank lines of
credit (see “Lines of Credit,” below). NW Natural had $102.5 mil-
lion in commercial paper notes outstanding at Dec. 31, 2004, com-
pared to $85.2 million outstanding at Dec. 31, 2003.
Lines of Credit
Effective Oct. 1, 2004, NW Natural entered into lines of credit
with Bank of America, N.A., JP Morgan Chase Bank, U.S. Bank
National Association, and Wells Fargo Bank, totaling $150 million
in aggregate. Half of the credit facility with each bank, or $75 mil-
lion, is committed and available through Sept. 30, 2005, and the
other $75 million is committed and available through Sept. 30, 2007.
Bank of America, N.A., JP Morgan Chase Bank, and U.S. Bank Na-
tional Association have each committed $20 million for each of
their 2005 and 2007 lines of credit, and Wells Fargo Bank has com-
mitted $15 million for each of its 2005 and 2007 lines of credit.
Under the terms of these lines of credit, NW Natural pays com-
mitment fees but is not required to maintain compensating bank
balances. The interest rates on any outstanding borrowings under
these lines of credit are based on current market rates. There were
no outstanding balances on these lines of credit at Dec. 31, 2004
or 2003.
NW Natural’s lines of credit require that credit ratings be main-
tained in effect at all times and that notice be given of any change
in its senior unsecured debt ratings. A change in NW Natural’s
credit rating is not an event of default, nor is the maintenance of a
specific minimum level of credit rating a condition to drawing upon
the lines of credit. However, interest rates on any loans outstand-
ing under NW Natural’s bank lines are tied to credit ratings, which
would increase or decrease the cost of debt outstanding under
these lines of credit, if any, when ratings are changed.
The lines of credit require the Company to maintain an indebt-
edness to total capitalization ratio of 65 percent or less and to
maintain a consolidated net worth at least equal to 80 percent of
its net worth at Sept. 30, 2004, plus 50 percent of the Company’s
28
N W N AT U R A L
net income for each subsequent fiscal quarter. NW Natural was in
compliance with the covenants as of Dec. 31, 2004, with an indebt-
edness to total capitalization ratio of 52 percent and a net worth
of $568.5 million compared to a required $452.1 million. The Com-
pany was also in compliance with these covenants under previous
line of credit agreements in effect as of Dec. 31, 2003. Failure to
comply with either of these covenants would entitle the banks to
terminate their lending commitments and to accelerate the matu-
rity of all amounts outstanding.
Credit Ratings
The table below summarizes NW Natural’s credit ratings from
three rating agencies, Standard and Poor’s Rating Services (S&P),
Moody’s Investor Service (Moody’s) and Fitch Ratings (Fitch).
Rating Agency
Moody’s
Fitch
S&P
Commercial Paper (short-term debt)
Senior Secured (long-term debt)
Senior Unsecured (long-term debt)
Ratings Outlook
A-1
A+
A
Stable
P-1
A2
A3
Stable
F1
A
A-
Stable
In December 2004, NW Natural’s corporate credit rating was
upgraded by S&P to “A+” from “A”, which also assigned NW Nat-
ural a business profile score of “1” on a scale of “1” to “10”, where
“1” is the strongest score. Each of the rating agencies has assigned
NW Natural an investment grade rating. These credit ratings and
business profile scores 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 recommenda-
tion to buy, sell or hold the Company’s securities. Each rating
should be evaluated independently of any other rating.
Optional Redemptions of Long-Term Debt and
Redeemable Preferred Stock
In 2003, the Company exercised early redemption provisions
applicable to certain of its long-term debt, including all $4 million
of the 7.50% Series B MTNs due 2023, all $11 million of the 7.52%
Series B MTNs due 2023, and all $20 million of the 7.25% Series
B MTNs due 2023. These MTNs were redeemed in the third quar-
ter of 2003 at 103.75 percent, 103.76 percent and 103.65 percent of
their respective principal amounts. In the fourth quarter of 2003,
the Company also exercised early redemption provisions applicable
to all of the remaining shares of its $7.125 Series of Redeemable
Preferred Stock with an aggregate stated value of $7.5 million, at
a redemption price equivalent to 102.375 percent. The Company
redeemed the MTNs and the preferred stock with available cash or
with the proceeds from sales of commercial paper, and re-financed
this long-term debt and preferred stock through the sale of new
long-term debt in the fourth quarter of 2003. Early redemption pre-
miums are recognized as unamortized costs on debt redemptions
pursuant to SFAS No. 71 and are amortized to expense over the life
of the new debt.
Cash Flows
Operating Activities
Year-over-year changes in the Company’s operating cash flows
are primarily affected by net income and non-cash adjustments to
net income. In 2004, net income and non-cash adjustments to net
income increased by $18 million, but the cash flow increase was
offset by increases in working capital requirements within the util-
ity segment resulting from warmer weather, higher prices of natu-
ral gas, and the timing of customer collections, payments for natu-
ral gas purchases and deferred gas cost recoveries. In 2003, net
income and non-cash adjustments to net income decreased by $18
million primarily due to a $13.9 million non-cash write-down of
PGE acquisition costs.
The following table summarizes cash provided by operating ac-
tivities for the years ended Dec. 31, 2004, 2003 and 2002:
Thousands (year ended December 31)
2004
2003
2002
Net income
Non-cash adjustments to net income
Changes in operating assets and
4,228
liabilities (working capital sources)
__________
Cash provided by operating activities $ 107,739 $ 108,193 $ 124,323
__________
__________
(12,049)
__________
__________
__________
6,375
__________
__________
__________
50,572 $
69,216
45,983 $
55,835
43,792
76,303
$
The overall change in cash flow from operations was negligible
in 2004 compared to 2003, but decreased by $16 million in 2003
compared to 2002. The significant factors contributing to the cash
flow changes between years are as follows:
2004 compared to 2003
■ an increase in net income added $4.6 million to cash flow;
■ an increase in deferred tax expense added $23.0 million to
cash flow, reflecting higher tax benefits from accelerated bonus
depreciation on large capital additions that were placed into ser-
vice in 2004;
■ an increase in inventories reduced cash flow by $22.8 million,
primarily reflecting higher volumes and higher unit prices on
gas inventories in storage facilities (see “Results of Operations –
Comparison of Gas Operations,” above);
■ an increase in regulatory receivables for deferred gas costs
reduced cash flow by $10.2 million, reflecting different patterns
of activity between the two years with respect to purchased
gas cost savings and off-system gas sales under NW Natural’s
PGA tariff (see “Results of Operations – Comparison of Gas
Operations – Cost of Gas Sold,” above);
■ an increase in accounts receivable also reduced cash flows
by $8.1 million, reflecting the impact of higher rates compared
to the prior year (see “Results of Operations – Regulatory Mat-
ters,” above);
■ cash contributions to the Company’s non-bargaining unit de-
fined benefit pension plan lowered cash flows by $8.3 million,
compared to no contributions in 2003 or 2002 (see “Pension
Cost (Income) and Funding Status,” below);
■ a smaller increase in accrued unbilled revenue added $9.7
million to cash flow, reflecting higher gas prices, partially offset
by lower unbilled volumes because of warmer weather and
decreases in customer usage because of higher prices;
■ an increase in other long term liabilities added $8.2 million
to cash flow, reflecting an increase in accruals for environmental
and other claims, as well as increases in accruals for unfunded
liabilities for pension and post-retirement benefits;
■ an increase in income taxes receivable reduced cash flow by
$7.3 million; and
■ a decrease in prepayments and other current assets increased
cash flow by $3.5 million.
2003 compared to 2002
■ an increase in net income added $2.2 million to cash flow;
■ a non-cash adjustment to net income in 2002 for the loss
recorded for PGE costs resulted in a net decrease in 2003 of
$13.9 million;
■ a significant increase in accrued unbilled revenue reduced
cash flow by $28.7 million, reflecting a combination of higher
gas prices and colder weather in December 2003 compared to
December 2002;
■ a significant increase in accounts receivable reduced cash flow
by $22.9 million, primarily reflecting the higher gas prices and
the timing of customer account collections;
■ a decrease in deferred gas costs payable reduced cash flow by
$5.6 million, largely due to a significant refund to customers in
2002 of accumulated gas cost savings;
■ a decrease in accrued interest and taxes payable added $16.4
million to cash flow, primarily reflecting higher tax benefits from
accelerated bonus depreciation;
■ a decrease in inventories of gas, materials and supplies added
$15.9 million to cash flow, primarily due to lower volumes of
natural gas in storage, partially offset by higher gas commodity
prices;
■ a decrease in prepaid income taxes added $9.5 million to cash
flow; and
■ an increase in accounts payable added $7.9 million to cash flow.
The Company has lease and purchase commitments relating
to its operating activities that are financed with cash flows from
operations (see “Liquidity and Capital Resources,” above, and
Note 12).
The Job Creation and Worker Assistance Act of 2002 (the As-
sistance Act) combined with the Jobs and Growth Tax Relief Rec-
onciliation Act of 2003 (the Reconciliation Act), allowed for an ad-
ditional first-year tax depreciation deduction on the adjusted basis
of “qualified property.” The Assistance Act provided for an addi-
tional depreciation deduction equal to 30 percent of an asset’s ad-
justed basis. The Reconciliation Act increased this first-year addi-
tional depreciation deduction to 50 percent of an asset’s adjusted
basis. The additional first-year depreciation deduction is an accel-
eration of depreciation deductions that otherwise would have been
taken in the later years of an asset’s recovery period. The acceler-
ated depreciation provisions provided by both the Assistance Act
and the Reconciliation Act expired at Dec. 31, 2004. The Company
realized enhanced cash flow from reduced income taxes totaling
an estimated $55 million during the effective period, based on plant
investments made between Sept. 11, 2001 and Dec. 31, 2004.
Investing Activities
Cash requirements for investing activities in 2004 totaled $136
million, up from $128 million in the same period of 2003. Cash re-
quirements for the acquisition and construction of utility plant to-
taled $141 million, up from $125 million in 2003. The increase in
cash requirements for utility construction in 2004 was primarily
the result of higher capital expenditures relating to NW Natural’s
SMPE project to extend the pipeline from its Mist gas storage field
to serve growing portions of its service area ($22 million). The
SMPE was completed and placed into service in September 2004.
The total cost of the project was approximately $110 million, which
includes amounts reflected in investing activities over the past few
years. The cost of service associated with the SMPE project, net of
deferred tax benefits, was included in customer rates starting in
the fourth quarter of 2004.
Cash requirements for investing activities in 2003 totaled $128
million, up from $85 million in 2002. Cash requirements for the
acquisition and construction of utility plant totaled $125 million,
up from $80 million in 2002. The increase in cash requirements
for utility construction in 2003 was primarily the result of higher
capital expenditures relating to the SMPE project ($27 million),
higher system improvements and support ($12 million) and other
special projects to serve new customer load or new service areas
($9 million).
Investments in the Company’s pipeline integrity management
program (IMP) were $1.6 million in 2004, compared to $0.9 mil-
lion in 2003. IMP costs are estimated at approximately $50 million
to $100 million over a ten-year period (see discussion below). IMP
costs are classified as either capital expenditures or regulatory as-
sets. The costs are accumulated over each 12-month period ending
June 30, and the costs, subject to audit, are recovered through rate
changes effective on Oct. 1 of each year commencing Oct. 1, 2004.
The approved accounting and rate treatment for these costs extends
through Sept. 30, 2008, and it may be reviewed for potential exten-
sion after that date.
N W N AT U R A L
29
Management’s Discussion and Analysis
Investments in non-utility property totaled $10.6 million in
2004, compared to $2.6 million in 2003. The higher investments in
2004 compared to 2003 were primarily for certain improvements
to the Company’s gas pipeline system that were related to interstate
gas storage services.
In December 2004, the Company received proceeds from the sur-
render of certain life insurance policies and proceeds from the set-
tlement of life insurance benefits totaling $17.6 million.
During the five-year period 2005 through 2009, utility construc-
tion expenditures are estimated at between $500 million and $600
million. The level of capital expenditures over the next five years
reflects projected high customer growth and system improvement
projects resulting in part from requirements under the Pipeline
Safety Improvement Act of 2002 (Pipeline Safety Act) (see below).
A majority of the required funds is expected to be internally gener-
ated over the five-year period; the remainder will be funded through
a combination of long-term debt and equity securities with short-
term debt providing liquidity and bridge financing.
NW Natural’s utility and non-utility capital expenditures in 2005
are estimated to total $110 million, including $28 million for cus-
tomer growth, $21 million for system improvement and support,
$15 million for equipment, facilities and information technology,
$10 million for IMP costs, $6 million for the SMPE and related gas
storage projects, $9 million for utility and non-utility storage and
$21 million for construction overhead.
In December 2003, the U.S. Department of Transportation’s
Office of Pipeline Safety issued a rule that specifies the detailed re-
quirements for transmission pipeline IMPs as mandated by the
Pipeline Safety Act. The Pipeline Safety Act requires operators of
gas transmission pipelines to identify lines located in High Conse-
quence Areas (HCAs) and to develop IMPs to periodically inspect
the integrity of the pipelines and make repairs or replacements as
necessary to ensure the ongoing integrity of the pipelines. The leg-
islation requires NW Natural to inspect the 50 percent highest risk
pipelines located in its HCAs within the first five years, and to in-
spect the remaining covered pipelines within 10 years of the date
of the enactment. The Pipeline Safety Act also requires re-inspec-
tions of the covered pipelines every seven years from the date of
the previous inspection for the life of the pipelines.
Financing Activities
Cash provided by financing activities in 2004 totaled $29 mil-
lion, compared to $17 million in 2003. Factors contributing to the
$12 million increase were the net proceeds ($38.5 million) from a
common stock offering in April 2004 (see below), combined with
last year’s redemption of the $7.125 Series of Preferred Stock ($8.4
million), offset by last year’s increase in long-term debt balances
($35.0 million).
Cash provided by financing activities in 2003 totaled $17 mil-
lion, compared to cash used in financing activities in 2002 of $43
million. Factors contributing to the $60 million difference were an
increase in short-term debt in 2003 ($15.4 million) compared to a
decrease in 2002 ($38.5 million) and the redemption of the $6.95
Series of Preference Stock in 2002 ($25 million), partially offset by
a higher amount used for the retirement of long-term debt ($55 mil-
lion in 2003 compared to $40.5 million in 2002) and the redemp-
tion, including the annual sinking fund, of the $7.125 Series of
Preferred Stock in 2003 ($8.4 million).
NW Natural sold $90 million of its secured Medium-Term Notes,
Series B (MTNs) in each of 2003 and 2002 and used the proceeds
to redeem long-term debt ($55 million in 2003 and $40.5 million
in 2002), to provide cash for investments in utility plant and to re-
duce short-term borrowings.
In April 2004, the Company issued and sold 1,290,000 shares
of its common stock in an underwritten public offering, and used
30
N W N AT U R A L
the net proceeds of $38.5 million from the offering to reduce short-
term indebtedness by about $29 million and to fund, in part,
NW Natural’s utility construction program. The offering of com-
mon stock was made pursuant to NW Natural’s universal shelf
registration statement providing for the registration of $200 million
of securities, which became effective in February 2004. After the
common stock offering, approximately $160 million remains avail-
able under the shelf registration statement for the Company to is-
sue additional securities, which may include First Mortgage Bonds
and unsecured debt.
In 2000, NW Natural commenced a program to repurchase
up to 2 million shares, or up to $35 million in value, of its com-
mon stock through a repurchase program that has been extended
through May 2005. The purchases are made in the open market or
through privately negotiated transactions. No shares were repur-
chased in 2003 or in 2004. Since the program’s inception the Com-
pany has repurchased 355,400 shares of common stock at a total
cost of $8.2 million.
Pension Cost (Income) and Funding Status
Net periodic pension cost (NPPC) is determined in accordance
with SFAS No. 87, “Employers’ Accounting for Pensions” (see “Ap-
plication of Critical Accounting Policies – Accounting for Pensions,”
above). The annual pension cost or income is allocated between
operations and maintenance expense and construction overhead.
NPPC for the Company’s two qualified defined benefit plans to-
taled $6.6 million in 2004, an increase of $0.4 million over NPPC
for these plans of $6.2 million in 2003. The increased NPPC was
primarily due to the use of a lower discount rate (6.25 percent in
2004 compared to 6.75 percent in 2003) which had the effect of
increasing the two plans’ accumulated benefit obligations.
During 2004, the Company contributed $5.3 million to its Retire-
ment Plan for Non-Bargaining Unit Employees (NBU Plan) for plan
year 2004, of which $1.0 million represented the minimum re-
quired funding. The Company was not required to make any con-
tribution to its Retirement Plan for Bargaining Unit Employees (BU
Plan) for that year. The Company’s funding policy is to contribute
at least the minimum amount required by the Employee Retirement
Income Security Act of 1974, as amended. For accounting expense
recognition, the Company uses an asset valuation (market-related
valuation) method that spreads variances between expected re-
turns and actual investment returns over a three-year period, but
for funding purposes the Company spreads these differences over
a five-year period. In 2004, the Company made additional tax-de-
ductible contributions to improve the funded status of its qualified
pension plans. In 2005, no contributions are required to be made
to fund either the NBU Plan or the BU Plan, and the Company does
not anticipate making any additional voluntary contributions for
the 2004 plan year.
The fair market value of the two plans’ assets increased to
$186.8 million at Dec. 31, 2004, up from $168.3 million at Dec. 31,
2003. The increase included $22.5 million in investment gains and
employer contributions of $8.3 million, which were offset in part
by $11.2 million in withdrawals to pay benefits and $1.1 million in
eligible expenses of the two plans. The present value of benefit
obligations under the two plans increased from an estimated $192
million to $209 million during 2004, however, so the two plans re-
mained under-funded in aggregate by about $22 million at Dec.
31, 2004.
NPPC for the NBU Plan and the BU Plan was $6.2 million in
2003, compared to net periodic pension income of $0.1 million in
2002. The increased NPPC in 2003 was largely due to investment
losses in 2002, which are recognized over a three-year period, and
to the use of a lower discount rate (6.75 percent in 2003 compared
to 7.25 percent in 2002) which increased the plans’ accumulated
benefit obligations. During 2004, the Company made a cash con-
tribution of $2.9 million to the NBU Plan for the 2003 plan year, of
which $1.9 million represented the minimum required funding. No
contributions were required to be made to either the NBU Plan or
the BU Plan for the 2002 plan year.
At Dec. 31, 2003, the fair market value of the assets of the NBU
Plan and the BU Plan totaled $168.3 million, up from $143.2 mil-
lion at Dec. 31, 2002. The increased market value included $36 mil-
lion in investment gains, which was partially offset by $10 million
in withdrawals to pay benefits and $0.9 million in eligible expenses
of the plans. At Dec. 31, 2003, the present value of benefit obligations
under the two plans totaled $192 million and thus were under-
funded in aggregate by about $24 million.
Despite the increase in NPPC and the current under-funded sta-
tus of the NBU Plan, NW Natural believes it will be able to main-
tain well-funded qualified pension plans. NW Natural does not
expect its current or future cash contribution requirements to the
two plans to have a material adverse effect on its liquidity or finan-
cial condition (see Note 7).
Ratios of Earnings to Fixed Charges
For the years ended Dec. 31, 2004, 2003 and 2002, the Compa-
ny’s ratios of earnings to fixed charges, computed using the Secu-
rities and Exchange Commission method, were 3.02, 2.84 and 2.85,
respectively. For this purpose, earnings consist of net income be-
fore 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
Environmental Matters
The Company is subject to federal, state and local laws and reg-
ulations related to environmental matters. These evolving laws and
regulations may require expenditures over a long timeframe to con-
trol environmental impacts. The Company believes that appropri-
ate investigation or remediation is being undertaken at all the rel-
evant sites. Based on existing knowledge, the Company does not
expect that the ultimate resolution of these matters will have a ma-
terial adverse effect on its financial condition, results of operations
or cash flows (see Note 12).
In May 2003, the OPUC approved NW Natural’s request for de-
ferral of environmental costs associated with specific sites. The
authorization, which has been extended through April 2005, allows
NW Natural to defer and seek recovery of unreimbursed environ-
mental costs in a future general rate case. NW Natural has filed a
request with the OPUC to extend this authority through January
2006. On a cumulative basis through Dec. 31, 2004, the Company
paid out a total of $3.3 million relating to the sites since the effec-
tive date of the deferral authorization (see Note 12).
NW Natural will first seek to recover the costs of investigation
and remediation for which it may be responsible with respect to
environmental matters, if any, from insurance. If these costs are
not recovered from insurance, then NW Natural will seek recovery
through future rates subject to approval by the OPUC. At Dec. 31,
2004, NW Natural had an $8.5 million receivable representing an
estimate of the environmental costs it expects to incur and recover
from insurance (see Note 12).
QUANTITATIVE AND QUALITATIVE DISCLOSURES
ABOUT MARKET RISK
The Company is exposed to various forms of market risk includ-
ing commodity supply risk, weather risk, and interest rate risk. The
following describes the Company’s exposure to these risks.
Commodity Supply Risk
NW Natural enters into short-term, medium-term and long-term
natural gas supply contracts, along with associated short-, medium-
and long-term transportation capacity contracts. Historically, NW
Natural has taken physical delivery of at least the minimum quan-
tities specified in its natural gas supply contracts. These contracts
are primarily index-based and subject to annual re-pricing, a pro-
cess that is intended to reflect anticipated market price trends dur-
ing the next year. NW Natural’s PGA mechanism in Oregon and
Washington provides for the recovery from customers of actual
commodity costs, except that, for Oregon customers, NW Natural
absorbs 33 percent of the higher cost of gas sold, or retains 33 per-
cent of the lower cost, in either case as compared to the annual
PGA price built into customer rates.
To the degree that market risks exist due to potential adverse
changes in commodity prices, foreign exchange rates or counter-
party credit quality in relation to these financial and physical con-
tracts, the Company considers the risks to be:
Commodity Price Risk
The prices of natural gas commodity are subject to fluctuations
due to unpredictable factors including weather, pipeline transpor-
tation congestion and other factors that affect short-term supply
and demand. Commodity-price swap and call option contracts (fi-
nancial hedge contracts) are used to convert certain natural gas
supply contracts from floating prices to fixed prices. These finan-
cial hedge contracts are included in the Company’s annual PGA
filing, subject to a prudency review. At Dec. 31, 2004 and 2003, no-
tional amounts under these commodity swap and call option con-
tracts totaled $413.0 million and $304.1 million, respectively. At
Dec. 31, 2004, five of these financial hedge contracts extended be-
yond Dec. 31, 2005. If all of the commodity-price swap and call op-
tion contracts had been settled on Dec. 31, 2004, a regulatory gain
of $10.5 million would have been realized (see Note 11).
Foreign Currency Risk
The costs of natural gas commodity and certain pipeline ser-
vices 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 fluc-
tuations in exchange rates with respect to the purchases of natural
gas from Canadian suppliers. At Dec. 31, 2004 and 2003, notional
amounts under foreign currency forward contracts totaled $14.5
million and $6.4 million, respectively. As of Dec. 31, 2004, no for-
eign currency forward contracts extended beyond Dec. 31, 2005. If
all of the foreign currency forward contracts had been settled on
Dec. 31, 2004, a gain of $0.4 million would have been realized (see
Note 11).
Counterparty Credit Risk
Certain suppliers that sell gas to NW Natural have either rela-
tively low credit ratings or are not rated by major credit rating agen-
cies. To manage this supply risk, the Company purchases gas from
a number of different suppliers, with no single supplier accounting
for more than 20 percent of the Company’s total purchases for a
given monthly period. The Company also evaluates suppliers’ cred-
itworthiness and maintains 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 re-
place those volumes at prevailing market prices, which may be
higher or lower than the original transaction prices. These costs
would be subject to the PGA sharing mechanism discussed above.
Since most of the Company’s commodity supply contracts are priced
at the monthly market index price, and the Company has significant
storage flexibility, it is unlikely that a supplier default would have a
materially adverse impact on the Company’s financial condition.
N W N AT U R A L
31
Management’s Discussion and Analysis
With respect to the financial counterparties the Company uses
for entering into commodity price hedge contracts, NW Natural’s
Derivatives Policy requires each counterparty to be at least two rat-
ing grades above non-investment grade. Because counterparty rat-
ings are subject to change at any time, the Company could have
contracts outstanding with counterparties whose ratings are non-
investment grade. NW Natural’s counterparty credit exposure as
of Dec. 31, 2004 was as follows:
Thousands
Credit Exposure
Investment grade counterparties
Non-investment grade counterparties
Total
$
15,957
–
__________
15,957
__________
__________
$
Due to the volatility of natural gas commodity prices, the mar-
ket value and credit exposure of certain derivative contracts could
exceed the Company’s credit limits established in its Derivatives
Policy. If such credit limits were exceeded, the Company would
have the ability to require collateral from the counterparty and
would not enter into any further contracts with that counterparty
until it was within the limits. If a counterparty failed to perform
under its contract, NW Natural could sustain a loss which would
be included in the annual PGA adjustment, subject to a regulatory
prudency review. Under certain circumstances, a counterparty de-
fault could result in a material loss. However, based on the Com-
pany’s current regulatory mechanism, the absence of any signifi-
cant position with a single counterparty and the strength of the
counterparties’ current credit ratings, any such loss is not expected
to have a material impact on the Company’s financial condition.
Weather Risk
The Company is exposed to weather risk primarily from its reg-
ulated utility business. A large portion of the Company’s net oper-
ating revenues (margin) is volume driven, and current rates are
based on an assumption of normal weather. In 2003, the OPUC ap-
proved a weather normalization mechanism for residential and
commercial customers. This mechanism affects customer bills be-
tween Nov. 15 through May 15 of each winter heating season, in-
creasing or decreasing the margin component of customers’ rates
to reflect “normal” weather using the 25-year average temperature
for each day of the billing period. The mechanism is intended to
stabilize the recovery of the utility’s fixed costs and reduce fluc-
tuations 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 Dec. 31, 2004, about 8 percent of
the Company’s Oregon customers had opted out. In addition to the
Oregon customers opting out, the Company’s Washington custom-
ers are not covered by weather normalization. The combination of
Oregon and Washington customers not covered by weather nor-
malization mechanism is less than 20 percent of all residential and
commercial customers.
Interest Rate Risk
The Company is 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 managed through the issuance
of fixed-rate debt with varying maturities and, if permitted, the re-
duction of debt through optional redemption when interest rates
are favorable. At Dec. 31, 2004 and 2003, the Company had no vari-
able-rate long-term debt and no derivative financial instruments to
hedge interest rates. Holders of certain long-term debt have put op-
tions that, if exercised, would accelerate maturities by $10 million
in 2005 and by $20 million in each of 2007, 2008 and 2009.
Management’s Report on Internal Control over Financial Reporting
Management of the Company 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. The Company’s internal control over financial re-
porting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial state-
ments for external purposes in accordance with generally accepted accounting principles in the United States of America (GAAP). The
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 involving the assets
of the Company;
(ii) provide reasonable assurance that transactions are recorded as necessary to permit the preparation of financial statements in ac-
cordance with GAAP, 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
(iii) provide reasonable assurance regarding prevention or timely detection of the 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, projec-
tions 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 the Company’s internal control over financial reporting as of Dec. 31, 2004. In making this
assessment, management used the framework 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 the Company maintained effective internal control over
financial reporting as of Dec. 31, 2004.
Management’s assessment of the effectiveness of the Company’s internal control over financial reporting as of Dec. 31, 2004 has
been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which ap-
pears herein.
Mark S. Dodson
President and Chief Executive Officer
32
N W N AT U R A L
David H. Anderson
Senior Vice President and Chief Financial Officer
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Shareholders
of Northwest Natural Gas Company:
We have completed an integrated audit of Northwest Natural Gas Company’s 2004 consolidated financial statements and of its in-
ternal control over financial reporting as of December 31, 2004 and audits of its 2003 and 2002 consolidated financial statements in ac-
cordance with the standards of the Public Company Accounting Oversight Board (United States). Our opinions, based on our audits,
are presented below.
Consolidated financial statements
In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, of shareholders’
equity and comprehensive income, of cash flows and of capitalization present fairly, in all material respects, the financial position of
Northwest Natural Gas Company (doing business as NW Natural) and its subsidiaries (“the Company”) at December 31, 2004 and 2003,
and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2004 in conformity
with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the
Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted
our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States).
Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are
free of material misstatement. An audit of financial statements includes 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. We believe that our audits provide a reasonable basis for our opinion.
Internal control over financial reporting
Also, in our opinion, management’s assessment, included in Management’s Report on Internal Control Over Financial Reporting ap-
pearing on page 32 of the 2004 Annual Report to Shareholders, that the Company maintained effective internal control over financial
reporting as of December 31, 2004 based on criteria established in Internal Control – Integrated Framework issued by the Committee of
Sponsoring Organizations of the Treadway Commission (COSO), is fairly stated, in all material respects, based on those criteria. Fur-
thermore, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of De-
cember 31, 2004, based on criteria established in Internal Control – Integrated Framework issued by the COSO. The Company’s man-
agement is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of
internal control over financial reporting. Our responsibility is to express opinions on management’s assessment and on the effectiveness
of the Company’s internal control over financial reporting based on our audit. We conducted our audit of internal control over financial
reporting in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require
that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was
maintained in all material respects. An audit of internal control over financial reporting includes obtaining an understanding of internal
control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of
internal control, and performing such other procedures as we consider necessary in the circumstances. We believe that our audit pro-
vides a reasonable basis for our opinions.
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 account-
ing principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the main-
tenance 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 accor-
dance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accor-
dance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention
or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the fi-
nancial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projec-
tions 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.
Portland, Oregon
March 1, 2005
N W N AT U R A L
33
Consolidated Statements of Income
Thousands, except per share amounts (year ended December 31)
2004
2003
2002
Operating revenues:
Gross operating revenues
Cost of sales
Net operating revenues
Operating expenses:
Operations and maintenance
Taxes other than income taxes
Depreciation and amortization
Total operating expenses
Income from operations
Other income (expense)
Interest charges – net of amounts capitalized
Income before income taxes
Income tax expense
Net income
Redeemable preferred and preference stock dividend requirements
Earnings applicable to common stock
Average common shares outstanding:
Basic
Diluted
Earnings per share of common stock:
Basic
Diluted
See Notes to Consolidated Financial Statements.
$ 707,604
399,244
__________
308,360
$ 611,256
323,190
__________
288,066
$ 641,376
353,832
__________
287,544
102,155
38,808
57,371
__________
198,334
__________
110,026
2,828
35,751
__________
77,103
26,531
__________
50,572
–
__________
50,572
$
__________
__________
96,420
35,125
54,249
__________
185,794
__________
102,272
2,150
35,099
__________
69,323
23,340
__________
45,983
294
__________
45,689
$
__________
__________
85,120
34,076
52,090
__________
171,286
__________
116,258
(14,890)
34,132
__________
67,236
23,444
__________
43,792
2,280
__________
41,512
$
__________
__________
27,016
27,283
25,741
26,061
25,431
25,814
$
$
1.87
1.86
$
$
1.77
1.76
$
$
1.63
1.62
34
N W N AT U R A L
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
Other investments
2004
2003
$ 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
__________
60,618
__________
73,845
__________
Current assets:
Cash and cash equivalents
Accounts receivable, less allowance for uncollectible accounts of $2,434 in 2004 and $1,763 in 2003
Accrued unbilled revenue
Inventories of gas, materials and supplies
Income tax receivable
Prepayments and other current assets
Total current assets
Regulatory assets:
Income tax asset
Deferred gas costs receivable
Unamortized costs on debt redemptions
Other
Total regulatory assets
Other assets:
Fair value of non-trading derivatives
Other
Total other assets
Total assets
Capitalization and liabilities:
Capitalization
Common stock
Premium on common stock
Earnings invested in the business
Unearned stock compensation
Accumulated other comprehensive income (loss)
Total 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
Regulatory liabilities:
Accrued asset removal costs
Customer advances
Deferred gas costs payable
Unrealized gain on non-trading derivatives
Total regulatory liabilities
Other liabilities:
Deferred income taxes
Deferred investment tax credits
Fair value of non-trading derivatives
Other
Total other liabilities
Commitments and contingencies (see Note 12)
Total capitalization and liabilities
See Notes to Consolidated Financial Statements.
5,248
60,675
64,401
66,477
15,970
24,346
__________
237,117
__________
4,706
48,499
59,109
50,859
8,986
23, 675
__________
195,834
__________
64,734
9,551
7,332
3,321
__________
84,938
__________
63,449
–
7,803
6,020
__________
77,272
__________
16,399
14,718
__________
31,117
__________
$ 1,732,195
__________
__________
23,885
10,130
__________
34,015
__________
$ 1,585,379
__________
__________
$
87,231
300,034
183,932
(862)
(1,818)
__________
568,517
484,027
__________
1,052,544
__________
$
82,137
255,871
170,053
(729)
(1,016)
__________
506,316
500,319
__________
1,006,635
__________
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
__________
153,258
1,529
–
10,912
__________
165,699
__________
135,638
1,564
5,627
23,885
__________
166,714
__________
210,715
6,025
5,487
24,440
__________
246,667
__________
–
__________
$ 1,732,195
__________
__________
171,797
6,945
–
18,867
__________
197,609
__________
–
__________
$ 1,585,379
__________
__________
N W N AT U R A L
35
Consolidated Statements of Shareholders’ Equity and Comprehensive Income
Thousands
Balance at Dec. 31, 2001
Net Income
Common
Stock
and
Premium
$ 320,586
–
Earnings
Invested
in the
Business
Unearned
Stock
Compensation
Accumulated
Other
Comprehensive
Income (Loss)
Total
Shareholders’ Comprehensive
Income
Equity
$ 147,950
43,792
$
(372)
–
$
(375)
–
$ 467,789
43,792
$ 43,792
Minimum pension liability
adjustment – net of tax
Change in unrealized loss
from price risk management
activities – net of tax
Purchases of restricted stock
Restricted stock amortizations
Cash dividends paid:
Redeemable preferred and
–
–
–
–
preference stock
Common stock
Issuance of common stock
Conversion of debentures
Common stock expense
Balance at Dec. 31, 2002
–
–
6,533
1,932
–
_________
329,051
Net Income
Minimum pension liability
adjustment – net of tax
Purchases of restricted stock
Restricted stock amortizations
Cash dividends paid:
Redeemable preferred stock
Common stock
–
–
–
–
–
–
Tax benefits from employee
stock option plan
Issuance of common stock
Conversion of debentures
Common stock expense
Balance at Dec. 31, 2003
401
7,930
626
–
_________
338,008
–
–
–
–
(2,579)
(32,024)
–
–
(3)
_________
157,136
45,983
–
–
–
(392)
(32,655)
–
–
–
(19)
_________
170,053
–
(2,936)
(2,936)
(2,936)
–
(891)
552
227
–
–
227
(891)
552
227
–
–
–
–
–
_________
(711)
–
–
–
–
–
_________
(3,084)
(2,579)
(32,024)
6,533
1,932
(3)
_________
482,392
_________
$ 41,083
_________
_________
–
–
(328)
310
–
–
–
45,983
$ 45,983
2,068
2,068
–
–
2,068
(328)
310
–
–
(392)
(32,655)
–
–
–
–
_________
(729)
–
–
–
–
_________
(1,016)
401
7,930
626
(19)
_________
506,316
_________
$ 48,051
_________
_________
–
50,572
–
(55)
–
–
(51)
–
–
(35,105)
–
–
(431)
298
–
872
47,148
1,292
–
_________
$ 387,265
_________
_________
–
–
–
(1,537)
_________
$ 183,932
_________
_________
–
–
–
–
_________
$
(862)
_________
_________
–
–
–
–
_________
$ (1,818)
_________
_________
–
50,572
$ 50,572
(802)
–
–
(802)
(537)
298
(35,105)
872
47,148
1,292
(1,537)
_________
$ 568,517
_________
_________
(802)
_________
$ 49,770
_________
_________
Net Income
Minimum pension liability
adjustment – net of tax
Purchases of restricted stock
Restricted stock amortizations
Cash dividends paid:
Common stock
Tax benefits from employee
stock option plan
Issuance of common stock
Conversion of debentures
Common stock expense
Balance at Dec. 31, 2004
See Notes to Consolidated Financial Statements.
36
N W N AT U R A L
Consolidated Statements of Cash Flows
Thousands (year ended December 31)
2004
2003
2002
Operating activities:
Net income
Adjustments to reconcile net income to cash provided by operations:
Depreciation and amortization
Loss for PGE acquisition costs
Minimum pension liability adjustment
Deferred income taxes and investment tax credits
Undistributed earnings from equity investments
Allowance for funds used during construction
Deferred gas costs – net
Contribution to Company-sponsored pension plan
Other
Changes in operating assets and liabilities:
Accounts receivable – net of allowance for uncollectible accounts
Accrued unbilled revenue
Inventories of gas, materials and supplies
Income tax receivable
Prepayments and other current assets
Accounts payable
Accrued interest and taxes
Other current and accrued liabilities
Cash provided by operating activities
Investing activities:
Acquisition and construction of utility plant assets
Investment in non-utility property
PGE acquisition costs
Proceeds from (investment in) life insurance – net
Other investments
Cash used in investing activities
Financing activities:
Common stock issued
Restricted stock purchased
Restricted stock amortization
Redeemable preferred and preference stock retired
Long-term debt issued
Long-term debt retired
Change in short-term debt
Cash dividend payments:
Redeemable preferred and preference stock
Common stock
Common stock expense
Cash provided by (used in) financing activities
Increase (decrease) in cash and cash equivalents
Cash and cash equivalents – beginning of year
Cash and cash equivalents – end of year
Supplemental disclosure of cash flow information:
Cash paid during the period for:
Interest and preferred dividends
Income taxes
Supplemental disclosure of non-cash financing activities:
Conversion to common stock:
7-1/4 % Series of Convertible Debentures
See Notes to Consolidated Financial Statements.
$
50,572
$
45,983
$
43,792
57,371
–
(802)
36,713
(181)
(1,690)
(15,178)
(8,261)
1,244
54,249
–
2,068
13,712
(474)
(1,734)
(5,008)
–
(6,978)
52,090
13,873
(2,936)
10,944
(988)
(550)
546
–
3,324
(12,176)
(5,292)
(15,618)
(6,984)
7,457
16,449
1,536
2,579
__________
107,739
__________
(4,027)
(15,040)
7,171
266
3,989
11,593
879
1,544
__________
108,193
__________
18,886
13,680
(8,693)
(9,252)
(307)
3,738
(15,473)
1,649
__________
124,323
__________
(141,485)
(10,568)
–
17,575
(1,291)
__________
(135,769)
__________
(124,660)
(2,563)
–
(1,387)
560
__________
(128,050)
__________
(79,530)
(2,629)
(4,316)
(496)
2,348
__________
(84,623)
__________
48,153
(537)
298
–
–
–
17,300
8,349
(328)
310
(8,428)
90,000
(55,000)
15,398
6,872
(891)
552
(25,750)
90,000
(40,500)
(38,489)
–
(35,105)
(1,537)
__________
28,572
__________
(392)
(32,655)
(19)
__________
17,235
__________
(2,579)
(32,024)
(3)
__________
(42,812)
__________
542
4,706
__________
5,248
$
__________
__________
(2,622)
7,328
__________
4,706
$
__________
__________
(3,112)
10,440
__________
7,328
$
__________
__________
$
$
36,061
2,500
$
$
35,210
13,940
$
$
34,640
33,474
$
1,292
$
626
$
1,932
N W N AT U R A L
37
Consolidated Statements of Capitalization
Thousands, except share amounts (December 31)
2004
2003
$
87,231
300,034
183,932
(862)
(1,818)
__________
568,517
5,000
5,000
5,000
8,000
20,000
9,500
5,000
10,000
25,000
10,000
40,000
10,000
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
$
82,137
255,871
170,053
(729)
(1,016)
__________
506,316
54%
50%
5,000
5,000
5,000
8,000
20,000
9,500
5,000
10,000
25,000
10,000
40,000
10,000
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
4,527
__________
499,027
15,000
__________
484,027
__________
5,819
__________
500,319
–
__________
46%
50%
500,319
_____ __________ _____
$ 1,052,544
__________
__________
100% $ 1,006,635 100%
_____ __________ _____
_____ __________ _____
Common stock equity:
Common stock – par value $3-1/6 per share, authorized
60,000,000 shares: outstanding – 2004, 27,546,720 shares;
2003, 25,938,002 shares
Premium on common stock
Earnings invested in the business
Unearned compensation
Accumulated other comprehensive income (loss)
Total common stock equity
Long-term debt:
Medium-Term Notes
First Mortgage Bonds:
6.340% Series B due 2005
6.380% Series B due 2005
6.450% Series B due 2005
6.050% Series B due 2006
6.310% Series B due 2007
6.800% Series B due 2007
6.500% Series B due 2008
4.110% Series B due 2010
7.450% Series B due 2010
6.665% Series B due 2011
7.130% Series B due 2012
8.260% Series B due 2014
7.000% Series B due 2017
6.600% Series B due 2018
8.310% Series B due 2019
7.630% Series B due 2019
9.050% Series A due 2021
5.620% Series B due 2023
7.720% Series B due 2025
6.520% Series B due 2025
7.050% Series B due 2026
7.000% Series B due 2027
6.650% Series B due 2027
6.650% Series B due 2028
7.740% Series B due 2030
7.850% Series B due 2030
5.820% Series B due 2032
5.660% Series B due 2033
Convertible Debentures
7-1/4% Series due 2012
Less long-term debt due within one year
Total long-term debt
Total capitalization
See Notes to Consolidated Financial Statements.
38
N W N AT U R A L
Notes to Consolidated Financial Statements
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:
Organization and Principles of Consolidation
The consolidated financial statements include the accounts of
the regulated parent company, Northwest Natural Gas Company
(NW Natural), and its non-regulated wholly-owned subsidiaries:
■ NNG Financial Corporation (Financial Corporation), and its
wholly-owned subsidiaries
■ Northwest Energy Corporation (Northwest Energy), and its
wholly-owned subsidiary
Together these businesses are referred to herein as the “Com-
pany.” In this report, the term “utility” is used to describe the reg-
ulated gas distribution business of the Company and the term
“non-utility” is used to describe the interstate gas storage business
and other non-regulated activities (see Note 2). Intercompany ac-
counts and transactions have been eliminated.
Investments in corporate joint ventures and partnerships in
which the Company’s ownership interest is 50 percent or less and
over which the Company does not exercise control are accounted
for by the equity method or the cost method (see Note 9).
Certain amounts from prior years have been reclassified to con-
form, for comparison purposes, with the current financial state-
ment presentation. These reclassifications had no impact on prior
year consolidated results of operations.
Use of Estimates
The preparation of financial statements in conformity with
generally accepted accounting principles in the United States of
America requires management to make estimates and assumptions
that affect reported amounts in the consolidated financial state-
ments 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
The Company’s principal business is the distribution of natural
gas, which is regulated by the Public Utility Commission of Oregon
(OPUC) and the Washington Utilities and Transportation Commis-
sion (WUTC). Accounting records and practices conform to the re-
quirements and uniform system of accounts prescribed by these
regulatory authorities in accordance with Statement of Financial
Accounting Standards (SFAS) No. 71, “Accounting for the Effects of
Certain Types of Regulation.” NW Natural’s utility business seg-
ment is authorized by the OPUC and the WUTC to earn a reason-
able return on invested capital.
In applying SFAS No. 71, NW Natural capitalizes certain costs
and revenues as regulatory assets and liabilities pursuant to orders
of the OPUC or WUTC in general rate or expense deferral proceed-
ings, to provide for recovery of revenues or expenses from, or re-
funds to, utility customers in future periods, including a return or
a carrying charge. At Dec. 31, 2004 and 2003, the amounts deferred
as regulatory assets and liabilities were net liabilities of $80.8 mil-
lion and $89.4 million, respectively. The net amounts recognized
at Dec. 31, 2004 and 2003 include $153.2 million and $135.6 mil-
lion, respectively, of accumulated removal costs, which have been
included in regulatory liabilities, in accordance with SFAS No. 143,
“Accounting for Asset Removal Obligations.” See “New Accounting
Standards – Adopted Standards,” below.
NW Natural believes that continued application of SFAS No. 71
for its regulated activities is appropriate and consistent with the
current regulatory environment, and that all of its regulated assets
and liabilities at Dec. 31, 2004 and 2003 are recoverable or refund-
able through future utility rates. NW Natural also believes that it
will continue to be able to earn a reasonable rate of return or a car-
rying charge on its regulated assets, net of regulatory liabilities.
If NW Natural should determine that all or a portion of these regu-
latory assets or liabilities no longer meet the criteria for continued
application of SFAS No. 71, then it would be required to write off
the net unrecoverable balances against earnings.
New Accounting Standards
Adopted Standards
ASSET RETIREMENT OBLIGATIONS. Effective Jan. 1, 2003, the Com-
pany adopted SFAS No. 143, “Accounting for Asset Retirement
Obligations.” SFAS No. 143 requires the recognition of an Asset
Retirement Obligation (ARO) for legal obligations associated with
the retirement of tangible long-lived assets, including the recording
of fair value of the liability, if reasonably estimable, for an ARO in
the period in which it is incurred. The ARO liability is recorded and
the cost is capitalized as part of the carrying amount of the related
long-lived asset. Over time, the liability is accreted to its present
value each period and the capitalized cost is depreciated over the
useful life of the related asset. The Company did not have any ma-
terial legal obligations associated with the retirement of its tangible
long-lived assets, except for certain assets with indefinite system
lives for which the Company cannot estimate the ARO because the
settlement date is indeterminable. The Company’s adoption of
SFAS No. 143 resulted in a balance sheet reclassification of asset
removal cost obligations from accumulated depreciation and amor-
tization to regulatory liabilities. The adoption of SFAS No. 143 and
the reclassification of asset removal cost obligations had no mate-
rial impact on the Company’s financial condition, results of opera-
tions or cash flows (see “Plant and Property,” below, for a discus-
sion of the Company’s policy on asset removal costs).
FINANCIAL INSTRUMENTS WITH EQUITY AND DEBT CHARACTERIS-
TICS. Effective July 1, 2003, the Company adopted SFAS No. 150,
“Accounting for Certain Financial Instruments with Characteristics
of both Liabilities and Equity.” SFAS No. 150 establishes standards
for how an issuer classifies and measures in its financial statements
certain financial instruments with characteristics of both liabilities
and equity. SFAS No. 150 requires an issuer to classify a financial
instrument as a liability if that financial instrument embodies an
obligation of the issuer. The adoption of SFAS No. 150 resulted in
the Company’s reclassifying dividends of $0.2 million after July 1,
2003 on its redeemable preferred stock as interest expense. The
Company redeemed its remaining shares of preferred stock out-
standing during the fourth quarter of 2003. The adoption of SFAS
No. 150 did not have a material impact on the Company’s financial
condition, results of operations or cash flows.
VARIABLE INTEREST ENTITIES. In December 2003, the Financial
Accounting Standards Board (FASB) revised FASB Interpretation
No. (FIN) 46, “Consolidation of Variable Interest Entities” (FIN
46R), to clarify the application of Accounting Research Bulletin No.
51, “Consolidated Financial Statements.” FIN 46R provides addi-
tional guidance for the identification and consolidation of variable
interest entities (VIEs), and for financial reporting by enterprises
involved with VIEs. The Company adopted the original provisions
of FIN 46 during 2003, and adopted the additional guidance of FIN
46R in 2004. The Company has certain equity investments that are
variable interests and some of these entities are potentially VIEs.
N W N AT U R A L
39
Notes to Consolidated Financial Statements
However, because the Company is not the primary beneficiary, it
is not required to consolidate the VIEs. The Company’s variable
interests primarily consist of limited liability interests with invest-
ments in alternative energy projects, low income housing and other
real estate. These investments were entered into between the years
1988 and 2000 and have been accounted for under the equity
method or cost method. The Company’s maximum exposure to
loss for these investments is $6.2 million at December 31, 2004, an
amount that represents the Company’s current investment balance
minus its minimum net realizable value. The Company’s invest-
ment risk is thus limited because all such investments are non-re-
course to the Company. The adoption of FIN 46R had no material
impact on the Company’s financial condition, results of operations
or cash flows.
MEDICARE PRESCRIPTION DRUG, IMPROVEMENT AND MODERNIZA-
TION ACT. In May 2004, the FASB issued Staff Position (FSP) No.
FAS 106-2, “Accounting and Disclosure Requirements Related to
the Medicare Prescription Drug, Improvement and Modernization
Act of 2003,” (the Act). FSP No. FAS 106-2 provides specific guid-
ance on accounting for the effects of the Act for employers that
sponsor postretirement health care plans that provide prescription
drug benefits. FSP No. FAS 106-2 also requires certain disclosures
regarding the effects of a federal subsidy provided by the Act.
Effective July 1, 2004, the Company adopted FSP No. 106-2 with
no material impact on the Company’s cash flows, accumulated
postretirement benefit obligations or net periodic postretirement
benefit costs. Based on current guidance and existing plan design,
the Company, with input from its actuary, determined that the pre-
scription drug benefit provided by the Company’s postretirement
benefit plan did not qualify it for a federal subsidy. While the Com-
pany provides certain prescription drug benefits to retirees, it was
determined that the Company’s contributions would be less than
40 percent of the plan’s expected claims cost, and therefore is not
eligible for the subsidy in 2006, the first year the subsidy is avail-
able. The Company will continue to reevaluate its plan contribu-
tions and claims experience to determine whether the plan quali-
fies for the federal subsidy in future years.
OTHER THAN TEMPORARY IMPAIRMENTS. In March 2004, the
Emerging Issues Task Force (EITF) ratified EITF No. 03-1, “The
Meaning of Other-Than-Temporary Impairment and Its Application
to Certain Investments” (EITF No. 03-1). EITF No. 03-1 provides
guidance for evaluating whether an investment is impaired, whether
the impairment is other than temporary, and the measurement of
such impairment. The guidance also includes accounting consid-
erations subsequent to the recognition of an other-than-temporary
impairment and requires certain disclosures in annual financial
statements about unrealized losses that have not been recognized
as other-than-temporary impairments. The adoption of EITF 03-1,
which was effective for reporting periods beginning after June 15,
2004, had no material impact on the Company’s financial condi-
tion, results of operations or cash flows.
40
N W N AT U R A L
INCOME TAXES. In December 2004, the FASB issued staff posi-
tions (FSP) FSP SFAS No. 109-1, to provide guidance on the appli-
cation of SFAS No. 109, “Accounting for Income Taxes,” to the pro-
visions within the American Jobs Creation Act of 2004 (the Jobs
Act) that provides a tax deduction on qualified production activi-
ties. The Jobs Act became effective on Oct. 23, 2004 and provides
for a tax deduction of up to nine percent (when fully phased-in) of
the lesser of (a) “qualified production activities income,” as defined
in the Jobs Act, or (b) taxable income (after the deduction for the
utilization of any net operating loss carryforwards). The Company
has determined that application of the provisions within the Jobs
Act will not have a material impact on the Company’s financial
condition, results of operations or cash flows.
Recent Accounting Pronouncements
INVENTORY COSTS. In November 2004, the FASB issued SFAS No.
151, “Inventory Costs, an amendment of ARB No. 43, Chapter 4.”
SFAS No. 151 amends the guidance on inventory pricing to require
that abnormal amounts of idle facility expense, freight, handling
costs and wasted material be charged to current period expense
rather than capitalized as inventory costs. SFAS No. 151 also re-
quires that allocation of fixed production overheads to the costs of
conversion be based on the normal capacity of the production fa-
cilities. SFAS No. 151 is effective for inventory costs incurred dur-
ing fiscal years beginning after June 15, 2005. The Company is
evaluating the impact this new standard may have on its financial
statements, but it is expected that its implementation will not have
a material impact upon the Company’s financial condition, results
of operations or cash flows.
SHARE BASED PAYMENTS. In December 2004, the FASB issued
SFAS No. 123 (revised 2004), “Share Based Payment” (SFAS No.
123R), that requires companies to expense the fair value of em-
ployee stock options and similar awards. Under SFAS No. 123R,
share based payment awards will be measured at fair value on the
date of grant based on the estimated number of awards expected
to vest. The estimated fair value will be recognized as compensa-
tion expense over the period an employee is required to provide
service in exchange for the award, usually referred to as the vest-
ing period. The expense would be adjusted for actual forfeitures
that occur before vesting, but would not be adjusted for awards
that expire or terminate after vesting. The Company is evaluating
different option-pricing models to determine the most appropriate
measure of fair value for its share based payment awards under
the new standard. Disclosures of estimated fair value and compen-
sation expense using the Black-Scholes option pricing model, and
its corresponding impact on the financial statements, is provided
in Note 4. The Company also is evaluating the effect of the adop-
tion and implementation of SFAS No. 123R, which is not expected
to have a material impact on the Company’s financial condition,
results of operations or cash flows. SFAS No. 123R is effective for
interim or annual reporting periods beginning after June 15, 2005.
The Company expects to adopt the provisions of SFAS No. 123R in
the first quarter of 2005.
NON-MONETARY TRANSACTIONS. Also in December 2004, the
FASB issued SFAS No. 153, “Exchanges of Nonmonetary Assets, an
amendment of Accounting Principles Board (APB) Opinion No. 29,
Accounting for Nonmonetary Transactions.” SFAS No. 153 redefines
the types of nonmonetary exchanges that require fair value mea-
surement. SFAS No. 153 is effective for nonmonetary transactions
entered into on or after July 1, 2005. The Company is evaluating the
impact of this statement, but adoption of this new accounting stan-
dard in 2005 is not expected to have a material impact on the Com-
pany’s financial condition, results of operations or cash flows.
Plant and Property
Plant and property is stated at cost, including labor, materials
and overhead (see Note 9). The cost of utility plant and interstate
storage includes an allowance for funds used during construction
in construction overhead to represent the net cost of borrowed
funds used for construction purposes (see “Allowance for Funds
Used During Construction,” below).
NW Natural’s 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 regula-
tory authorities. The weighted average depreciation rate was ap-
proximately 3.4 percent for the year ended Dec. 31, 2004 and 3.5
percent for each of the years 2003 and 2002. The depreciation rate
reflects the approximate economic life of the utility property.
Effective Jan. 1, 2003, the Company adopted SFAS No. 143, “Ac-
counting for Asset Retirement Obligations.” Among other things,
SFAS No. 143 requires that future asset retirement costs (removal
costs) that meet the requirements of SFAS No. 71, as amended and
supplemented, be classified as a regulatory liability. In accordance
with long-standing industry practice, the Company accrues for fu-
ture removal costs on many long-lived assets through a charge to
depreciation expense allowed in rates. Prior to the adoption of SFAS
No. 143, the resulting regulatory liabilities were recognized as ac-
cruals to accumulated depreciation. At the time when removal
costs were incurred, accumulated depreciation was charged with
the costs of removal and the book cost of the asset being retired.
At Dec. 31, 2004 and 2003, the Company recognized accrued asset
removal costs of $153.2 million and $135.6 million, respectively,
through depreciation expense from accumulated depreciation and
amortization. The Company’s estimate of accumulated removal
costs was based on rates using its most recent depreciation study.
The Company will continue to accrue future asset removal costs
through depreciation expense, with a corresponding credit to regu-
latory liabilities – accrued asset removal costs. When the Company
retires depreciable utility plant and equipment, it charges the as-
sociated original costs to accumulated depreciation and amortiza-
tion, and any related removal costs incurred are charged to regula-
tory liabilities – accrued asset removal costs. 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 an allowance for funds
used during construction (AFUDC). AFUDC represents the cost of
funds borrowed during construction and is calculated using actual
commercial paper interest rates. If commercial paper 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 inter-
est charges, and a return on equity funds, shown as other income,
is used to compute AFUDC. While cash is not realized currently
from AFUDC, it is realized in future years through increased reve-
nues from rate recovery resulting from higher rate base and higher
depreciation expense. NW Natural’s composite AFUDC rates were
3.0 percent in 2004, 4.5 percent in 2003 and 2.8 percent in 2002.
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.
Revenue Recognition
Utility revenues, derived primarily from the sale and transpor-
tation of natural 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 (unbilled reve-
nues). Unbilled revenues are dependent upon a number of factors
that require management judgment, including total gas receipts
and deliveries, customer use and weather. Unbilled revenues are
reversed the following month when actual billings occur. The Com-
pany’s accrued unbilled revenues at Dec. 31, 2004 and 2003 were
$64.4 million and $59.1 million, respectively.
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 are
recognized over the life of the contract for guaranteed amounts un-
der the contract, or are recognized as they are earned for amounts
above the guaranteed value based on estimates provided by the in-
dependent energy marketing company (see Note 2).
Accounts Receivable and Allowance for
Uncollectible Accounts
Accounts receivable consist primarily of amounts due to NW
Natural for gas sales and transportation services to residential,
commercial and industrial customers, plus amounts due for inter-
state gas storage services and other miscellaneous receivables.
With respect to these trade receivables, the Company establishes
an allowance for uncollectible accounts (allowance) based on the
aging of receivables, its 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 allow-
ance when amounts are identified as unlikely to be recovered. In-
active accounts are written-off against the allowance after 120 days
past due or when deemed to be uncollectible. Differences between
the Company’s estimated allowance and actual write-offs will oc-
cur based on changes in general economic conditions, customer
credit issues and the level of natural gas prices, but these differ-
ences are not currently expected to have a material impact on the
Company’s financial condition or results of operation.
Inventories
Inventories, consisting primarily of natural gas in storage, are
stated at the moving average cost. Regulatory treatment of gas in-
ventories provides full recovery in rates for the value of gas inven-
tory at the moving average cost. All other inventories are stated at
the lower of average cost or net realizable value.
Derivatives Policy
NW Natural’s Derivatives Policy sets forth the guidelines for us-
ing selected financial derivative products to support prudent risk
management strategies within designated parameters. The Deriva-
tives Policy allows for the use of derivatives to manage natural gas
commodity prices related to natural gas purchases, foreign cur-
rency prices related to gas purchase commitments from Canada,
oil or propane commodity prices related to gas sales and transpor-
tation services under rate schedules pegged to other commodities,
and interest rates related to long-term debt maturing in less than
five years or expected to be issued in future periods. NW Natural’s
objective for using derivatives is to decrease the volatility of earn-
ings and cash flows associated with changes in commodity prices,
foreign currency prices and interest rates. The use of derivatives is
permitted only after the commodity price, exchange rate, and in-
terest rate 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
(see Note 11). The Derivatives Policy is intended to prevent specu-
lative risk. NW Natural does not enter into derivative instruments
for trading purposes and believes that any increase in market risk
created by holding derivatives should be offset by the exposures
they modify.
N W N AT U R A L
41
Notes to Consolidated Financial Statements
In accounting for derivative activities, the Company applies
SFAS No. 133, “Accounting for Derivative Instruments and Hedg-
ing Activities,” as amended by SFAS No. 138, “Accounting for Cer-
tain Derivative Instruments and Certain Hedging Activities,” and
SFAS No. 149, “Amendment of Statement 133 on Derivative Instru-
ments and Hedging Activities,” (collectively referred to as SFAS No.
133). SFAS No. 133 requires that the Company recognize deriva-
tives as either assets or liabilities on the balance sheet and measure
those instruments at fair value. SFAS No. 133 also 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
purchase and normal sale, other than a financial instrument or de-
rivative instrument for which physical delivery is probable. Many
of the Company’s gas supply and transportation contracts are de-
rivative instruments as defined under SFAS No. 133, but qualify
for the normal purchase and normal sale exception.
NW Natural designates its derivatives as fair value or cash flow
hedges based upon the criteria established by SFAS No. 133. For
fair value hedges, the gain or loss is recognized in earnings in the
period of change. For cash flow hedges, the effective portion of the
gain or loss is initially reported in accumulated other comprehen-
sive income (OCI), unless the derivative is subject to deferral under
NW Natural’s regulated tariffs with the OPUC or the WUTC. The
ineffective portion of the gain or loss in a cash flow hedge is rec-
ognized in current earnings, but only to the extent that the amount
is not covered under NW Natural’s regulatory deferral mechanisms.
Effectiveness is measured by comparing changes in cash flows of
the hedged item to gains or losses on derivative instruments.
NW Natural’s primary hedging activities, consisting of natural
gas commodity price and foreign currency exchange rate hedges,
are principally accounted for as cash flow hedges under SFAS No.
133 and are subject to regulatory deferral under SFAS No. 71. Un-
realized gains and losses from mark-to-market valuations of these
contracts are not recognized in current income but are reported as
derivative assets or liabilities and offset by a corresponding deferred
account balance included under “regulatory liabilities” or “regula-
tory assets.” Due to their regulatory deferral treatment, effective
portions of changes in the fair value of these derivatives are not re-
corded in OCI but are recognized as a regulatory asset or liability.
Income Taxes
The Company accounts for income taxes in accordance with
SFAS No. 109, “Accounting for Income Taxes.” Under SFAS No. 109,
the Company recognizes deferred income taxes for all temporary
differences between the financial statement and tax basis of assets
and liabilities at current income tax rates. Deferred tax liabilities
and assets reflect the expected future tax consequences, based on
enacted tax law, of temporary differences between the tax basis of
assets and liabilities and their financial reporting amounts (see
Note 8).
SFAS No. 109 also requires recognition of the additional deferred
income tax assets and liabilities for temporary differences where
regulators prohibit deferred income tax treatment for ratemaking
purposes. Consistent with rate and accounting orders of regulatory
authorities, deferred income taxes are not currently collected for
those temporary income tax differences where the prescribed reg-
ulatory accounting methods do not provide for current recovery in
rates. NW Natural has recorded a regulatory tax asset for amounts
pending recovery from customers in future rates, equivalent to
$64.7 million and $63.4 million at Dec. 31, 2004 and 2003, respec-
tively. These amounts are primarily based on differences between
the book and tax bases of net utility plant in service.
42
N W N AT U R A L
Investment tax credits on utility plant additions and leveraged
leases, which reduce income taxes payable, are deferred for finan-
cial statement purposes and are amortized over the life of the re-
lated plant or lease. Investment and energy tax credits generated
by non-regulated subsidiaries are amortized over a period of one
to five years.
Other Income (Expense)
Other income (expense) consists of interest income, gain on sale
of assets, investment income of Financial Corporation, the costs
incurred in connection with the Company’s effort to acquire Port-
land General Electric Company (PGE) from Enron Corp. and other
miscellaneous income from merchandise sales, rents, leases and
other items.
Earnings Per Share
Basic earnings per share are computed based on the weighted
average number of common shares outstanding each year. Diluted
earnings per share reflect the potential effects of the conversion of
convertible debentures and the exercise of stock options. Diluted
earnings per share are calculated as follows:
Thousands, except per share amounts
2004
2003
2002
Net income
Redeemable preferred and preference
stock dividend requirements
Earnings applicable to common
stock – basic
Debenture interest less taxes
Earnings applicable to common
stock – diluted
Average common shares
outstanding – basic
Stock options
Convertible debentures
Average common shares
outstanding – diluted
Earnings per share of common
stock – basic
Earnings per share of common
stock – diluted
$
50,572 $
45,983 $
43,792
–
__________
294
__________
2,280
__________
50,572
200
__________
45,689
257
__________
41,512
285
__________
$
__________
__________
50,772 $
__________
__________
45,946 $
41,797
__________
__________
27,016
40
227
__________
25,741
28
292
__________
25,431
59
324
__________
27,283
__________
__________
26,061
__________
__________
25,814
__________
__________
$
__________
__________
1.87 $
__________
__________
1.77 $
1.63
__________
__________
$
__________
__________
1.86 $
__________
__________
1.76 $
1.62
__________
__________
For the years ended Dec. 31, 2004, 2003 and 2002, 201,800
shares, 77,500 shares and 84,000 shares, respectively, representing
the number of stock options the exercise prices for which were
greater than the average market prices for the Company’s common
stock for such years, were excluded from the calculation of diluted
earnings per share because the effect was antidilutive.
Stock-Based Compensation
The Company applies APB Opinion No. 25, “Accounting for
Stock Issued to Employees,” to account for its stock-based com-
pensation plans. Accordingly, the Company does not recognize
compensation expense for the fair value of its stock option grants.
Instead, the Company has elected to continue using the intrinsic
value method of accounting for stock options rather than adopting
the fair value method of accounting. However, the Company does
recognize compensation expense for the fair value of stock awards
granted under its Long-Term Incentive Plan and the Non-Employee
Directors Stock Compensation Plan in the period when the shares
are earned (see “New Accounting Standards – Recent Accounting
Pronouncements – Share Based Payments,” above, and Note 4).
2. CONSOLIDATED SUBSIDIARY OPERATIONS AND
SEGMENT INFORMATION:
At Dec. 31, 2004, the Company had two direct, wholly-owned
subsidiaries, Financial Corporation and Northwest Energy. North-
west Energy was formed in 2001 to serve as the holding company
for NW Natural and PGE if the acquisition of PGE had been com-
pleted. Since the acquisition of PGE was terminated, Northwest
Energy has remained a non-active subsidiary of the Company.
The Company’s core business segment, Local Gas Distribution
(LDC), involves the distribution and sale of natural gas. The Local
Gas Distribution segment is also referred to as the “utility”. Another
segment, Interstate Gas Storage, represents natural gas storage ser-
vices provided to interstate customers, including asset optimiza-
tion services under a contract with an independent energy market-
ing company. The remaining business segment, Other, primarily
consists of non-regulated investments in alternative energy proj-
ects in California (see “Financial Corporation,” below), a Boeing
737-300 aircraft leased to Continental Airlines, low-income hous-
ing in Portland, Oregon and Northwest Energy’s limited activities
(see Note 9).
Interstate Gas Storage
Interstate gas storage services are provided to off-system inter-
state customers using Company-owned storage capacity that has
been developed in advance of core utility customers’ (residential,
commercial and industrial firm) requirements. NW Natural retains
80 percent of the income before tax from gas storage services and
credits the remaining 20 percent to a deferred regulatory account
for sharing with its core utility customers. For each of the years
ended Dec. 31, 2004, 2003 and 2002, this business segment derived
a majority of its revenues from fewer than five customers. The larg-
est of these customers is served under a long-term contract.
Results for the interstate gas storage segment also include rev-
enues, net of amounts shared with core utility customers, from a
contract with an independent energy marketing company that op-
timizes the use of NW Natural’s assets by engaging in trading ac-
tivities using temporarily unused portions of its upstream pipeline
transportation capacity and gas storage capacity. In Oregon, NW
Natural retains 80 percent of the pre-tax income from the optimi-
zation of storage and pipeline transportation capacity when the
costs of such capacity have not been included in core utility rates,
and 33 percent of the pre-tax income from such capacity when the
costs have been included in core utility rates. The remaining 20
percent and 67 percent, respectively, are credited to a deferred reg-
ulatory account for distribution to NW Natural’s core utility cus-
tomers. NW Natural has a similar sharing mechanism in Washing-
ton for revenue derived from interstate storage services and third
party optimization services.
Financial Corporation
Financial Corporation has several financial investments, includ-
ing investments as a limited partner in solar electric generating
systems, windpower electric generating projects and low-income
housing projects. Financial Corporation’s total assets were $7.6
million and $8.0 million at Dec. 31, 2004 and 2003, respectively.
On Jan. 31, 2005 Financial Corporation sold its limited partner-
ship interests in three solar electric generating systems for approx-
imately $3 million, which resulted in a $0.5 million write-down of
these systems in the fourth quarter of 2004. These systems are lo-
cated in the Mojave Desert in California. NW Natural invested in
the projects between 1986 and 1988. Financial Corporation’s own-
ership interests ranged from 4.0 percent to 5.3 percent.
Segment Information Summary
The following table presents summary financial information
about the reportable segments for 2004, 2003 and 2002. Inter-seg-
ment transactions are insignificant.
Thousands
2004
Net operating revenues
Depreciation and amortization
Other operating expenses
Income (loss) from operations
Income from financial
investments
Net income
Total assets at Dec. 31, 2004
2003
Net operating revenues
Depreciation and amortization
Other operating expenses
Income from operations
Income from financial
investments
Net income
Total assets at Dec. 31, 2003
2002
Net operating revenues
Depreciation and amortization
Other operating expenses
Income from operations
Income from financial
investments
Loss provision for PGE
transaction costs
Net income (loss)
Total assets at Dec. 31, 2002
Interstate
Utility Gas Storage
Other
Total
$ 301,769 $
56,899
140,089
104,781
6,423 $
472
652
5,299
168 $ 308,360
57,371
140,963
110,026
–
222
(54)
2,855
47,090
1,688,688
–
2,880
28,361
181
602
15,146
3,036
50,572
1,732,195
$ 278,856 $
53,798
130,619
94,439
9,036 $
451
804
7,781
174 $ 288,066
54,249
131,545
102,272
–
122
52
3,406
40,913
1,551,817
–
4,312
19,036
474
758
14,526
3,880
45,983
1,585,379
$ 279,414 $
51,693
118,156
109,565
7,944 $
396
962
6,586
186 $ 287,544
52,090
119,196
116,258
1
78
107
1,390
–
988
2,378
–
47,280
1,432,777
–
3,646
16,403
(8,414)
(7,134)
18,097
(8,414)
43,792
1,467,277
3. CAPITAL STOCK:
Common Stock
At Dec. 31, 2004, NW Natural had reserved 106,699 shares of
common stock for issuance under the Employee Stock Purchase
Plan, 288,155 shares for future conversions of its 7-1/4% Convert-
ible Debentures, 232,827 shares under its Dividend Reinvestment
and Stock Purchase Plan, 1,659,470 shares under its Restated Stock
Option Plan (see Note 4), and 3,000,000 shares under the Share-
holder Rights Plan.
In April 2004, the Company issued and sold 1,290,000 shares
of its common stock in an underwritten public offering and used
the net proceeds of $38.5 million from the offering primarily to re-
duce short-term indebtedness and to fund, in part, NW Natural’s
utility construction program.
Redeemable Preferred Stock
On Nov. 14, 2003, NW Natural redeemed all of the remaining
shares of its $7.125 Series of Redeemable Preferred Stock with an
aggregate stated value of $7.5 million, at a redemption price equiv-
alent to 102.375 percent with proceeds from sales of commercial
paper. The Company re-financed the commercial paper with the
sale of new long-term debt in the fourth quarter of 2003. The early
redemption premium was recognized as an unamortized cost pur-
suant to SFAS No. 71 and is being amortized to expense over the
life of the new debt.
Redeemable Preference Stock
On Dec. 31, 2002, NW Natural redeemed all 250,000 shares of
its $6.95 Series of Redeemable Preference Stock with proceeds from
the sale of commercial paper.
N W N AT U R A L
43
61,020
–
–
1,105
2003
2004
2003-05
2004-06
–
–
7,000
7,750
28,000
31,000
56,000
62,000
Notes to Consolidated Financial Statements
Stock Repurchase Program
NW Natural’s Board of Directors approved a stock repurchase
program in 2000 to purchase up to 2 million shares, or up to $35
million in value, of NW Natural’s common stock in the open mar-
ket or through privately negotiated transactions. The repurchase
program has been extended through May 2005. No shares were re-
purchased in 2003 or 2004. Since the program’s inception, the Com-
pany has repurchased 355,400 shares of common stock at a total
cost of $8.2 million.
Restated Stock Option Plan
In May 2002, the shareholders approved an amendment to the
Restated Stock Option Plan that increased the total number of
shares authorized for option grants from 1,200,000 to 2,400,000
shares. At Dec. 31, 2004, options on 1,228,000 shares were avail-
able for grant and options on 431,470 shares were outstanding.
The following table shows the changes in the number of shares
of NW Natural’s capital stock and the premium on common stock
for the years 2004, 2003 and 2002:
––––––––––––––––– Shares –––––––––––––––––
Premium
Redeemable Redeemable on common
stock
(thousands)
preference
stock
preferred
stock
Common
stock
25,228,074
42,862
157,288
250,000
–
–
90,000 $ 240,697
748
3,854
–
–
1,624
–
97,069
–
–
–
–
(250,000)
–
__________ __________ __________ __________
248,028
–
25,586,313
425
–
14,175
4,347
–
178,714
–
(7,500)
–
82,500
–
–
127,357
–
–
2,545
–
526
31,443
–
–
–
–
–
–
__________ __________ __________ __________
255,871
–
25,938,002
35,905
–
1,290,000
605
–
27,541
4,323
–
157,124
–
(7,500)
(75,000)
–
–
–
–
73,649
–
–
2,285
1,086
–
–
64,904
(41)
–
–
(4,500)
__________ __________ __________ __________
27,546,720
– $ 300,034
–
__________ __________ __________ __________
__________ __________ __________ __________
Balance, Dec. 31, 2001
Sales to employees
Sales to stockholders
Exercise of stock
options – net
Conversion of convertible
debentures to common
Sinking fund purchases
Redemption
Balance, Dec. 31, 2002
Sales to employees
Sales to stockholders
Exercise of stock
options – net
Conversion of convertible
debentures to common
Sinking fund purchases
Early redemption
Balance, Dec. 31, 2003
Sales to public
Sales to employees
Sales to stockholders
Exercise of stock
options – net
Conversion of convertible
debentures to common
Repurchase
Balance, Dec. 31, 2004
4. STOCK-BASED COMPENSATION:
NW Natural has 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 (NED-
SCP). 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. An
aggregate of 500,000 shares of common stock was authorized for
grants under the LTIP as stock bonus, restricted stock or perfor-
mance-based stock awards. Shares awarded under the LTIP are
purchased on the open market.
44
N W N AT U R A L
At year-end 2004, a total of 436,000 shares of common stock
were available for award under the LTIP, assuming that current
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 restricted stock awards.
Performance-based Stock Awards. Since the Plan’s inception in
2001, through December 31, 2004, five performance-based stock
awards have been granted, one based on a two-year performance
period (2001-02) and four based on three-year performance periods
(2001-03, 2002-04, 2003-05 and 2004-06). At Dec. 31, 2004, all per-
formance-based stock awards other than those covering the 2003-
05 and 2004-06 periods had lapsed because the performance-based
measures were not achieved. If the performance-based measures
are achieved, participants will also receive dividend equivalent cash
payments equal to the number of shares of common stock received
on the award payout multiplied by the aggregate cash dividends
paid per share by the Company during the performance period.
At Dec. 31, 2004, the aggregate number of performance-based
shares awarded and outstanding at the minimum, threshold, target
and maximum levels were as follows:
Performance
Year
Period
Awarded
–––––––– No. of Performance Shares Awarded ––––––––
Target Maximum
Minimum
Threshold
For the 2003-05 performance period, a series of performance
targets were established based on the Company’s average annual
return on equity (ROE) for the performance period corresponding
to award opportunities ranging from 0 percent to 200 percent of
the target awards. No awards are payable unless the threshold an-
nual average ROE level, tied to the Company’s authorized ROE, is
achieved during the award period. The maximum awards are pay-
able only upon the achievement of an average annual ROE 200 ba-
sis points above the Company’s authorized ROE. For the 2004-06
performance period, awards will be based on total shareholder re-
turn relative to a peer group of gas distribution companies over the
three-year performance period and performance milestones rela-
tive to the Company’s core and non-core strategies.
Restricted Stock Awards. Restricted stock awards also have been
granted under the LTIP. A restricted stock award consisting of 4,500
shares granted in 2001 lapsed in 2004, and a restricted stock award
was granted in 2004 consisting of 5,000 shares that is scheduled to
vest ratably over five years beginning in 2005.
RESTATED STOCK OPTION PLAN. The Restated SOP authorizes an
aggregate of 2,400,000 shares of common stock for issuance as in-
centive or non-statutory stock options. These options may be
granted only to officers and key employees designated by a com-
mittee of NW Natural’s Board of Directors. All options are granted
at an option price not less than the market value at the date of grant
and may be exercised for a period not exceeding 10 years from the
date of grant. Option holders may exchange shares they have
owned for at least six months, at the current market price, to pur-
chase shares at the option price. Since inception in 1985, options
on 1,303,721 shares of common stock have been granted at prices
ranging from $11.75 to $32.02 per share, and options on 131,721
shares have expired.
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 subscription 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.
In accordance with APB Opinion No. 25, no compensation ex-
pense was recognized for options granted under the Restated SOP
or shares issued under the ESPP during 2004 or earlier years (see
Note 1, “New Accounting Standards – Recent Accounting Pronounce-
ments”). 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. 123, “Accounting for Stock-
Based Compensation,” net income and earnings per share would
have been reduced to the pro forma amounts shown below:
Thousands, except per share amounts
2004
2003
2002
Net income as reported
Pro forma stock-based compensation
expense determined under the fair
value based method – net of tax
Pro forma net income
Redeemable preferred and
preference stock
Pro forma earnings applicable to
common stock – basic
Debenture interest less taxes
Pro forma earnings applicable
to common stock – diluted
Basic earnings per share
As reported
Pro forma
Diluted earnings per share
As reported
Pro forma
$
50,572 $
45,983 $
43,792
(423)
__________
50,149
(279)
__________
45,704
(478)
__________
43,314
–
__________
(294)
__________
(2,280)
__________
50,149
200
__________
45,410
257
__________
41,034
285
__________
$
__________
__________
50,349 $
__________
__________
45,667 $
41,319
__________
__________
$
$
$
$
1.87 $
1.86 $
1.86 $
1.85 $
1.77 $
1.76 $
1.76 $
1.75 $
1.63
1.61
1.62
1.60
The fair value of each stock option is estimated on the grant
date (there were no stock option grants in 2003) using the Black-
Scholes option pricing model with the following weighted average
assumptions:
Expected life in years
Risk-free interest rate
Expected volatility
Dividend yield
Present value of options granted
2004
7.0
3.6%
25.2%
4.1%
2002
7.0
3.6%
29.1%
4.8%
$
24.55
$
20.49
Information regarding the Restated SOP’s activity is summarized
as follows:
––––––– Price per Share –––––––
Weighted-
Average
Exercise
Price
Range
Option
Shares
Balance outstanding, Dec. 31, 2001
Granted
Exercised
Expired
387,091 $ 20.25 - 27.875 $ 22.79
26.35
26.07 - 27.850
163,750
21.74
20.25 - 27.875
(68,827)
25.43
20.25 - 27.875
(18,200)
_________
Balance outstanding, Dec. 31, 2002
Exercised
Expired
Balance outstanding, Dec. 31, 2003
Granted
Exercised
Expired
463,814
(140,470)
(1,300)
_________
322,044
202,800
(92,074)
(1,300)
_________
20.25 - 27.875
20.25 - 27.875
20.25
20.25 - 27.875
31.34 - 32.020
20.25 - 27.875
26.30 - 31.340
24.10
21.14
20.25
25.35
31.40
24.39
30.18
Balance outstanding, Dec. 31, 2004
431,470 $ 20.25 - 32.020 $ 28.38
Shares available for grant
Dec. 31, 2002
Shares available for grant
Dec. 31, 2003
Shares available for grant
Dec. 31, 2004
1,428,200
1,429,500
1,228,000
The weighted average remaining life of outstanding stock op-
tions at December 31, 2004 was 7.3 years.
The characteristics of exercisable stock options at Dec. 31, 2004
were as follows:
Range of
Exercise Prices
$20.25 – $27.875
Exercisable
Stock Options
Weighted-
Average
Exercise Price
185,120
$
25.56
NON-EMPLOYEE DIRECTORS STOCK COMPENSATION PLAN. In Feb-
ruary 2004, the NEDSCP was amended to permit non-employee
directors to receive stock awards either in cash or in Company
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 Jan. 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 the Company’s common stock was awarded
upon joining the Board. These stock awards were subject to vest-
ing 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 Company
stock were awarded an additional $20,000 worth of restricted Com-
pany stock, which vested in monthly installments in the fifth year
following the award (after the previous award has fully vested).
The Company holds the certificates for the restricted shares until
the non-employee director ceases to be a director. Participants re-
ceive all dividends and have full voting rights on both vested and
unvested shares. All awards vest immediately 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 by the Company at the time of the award.
The following table presents the changes in unearned stock
compensation for the years 2004 and 2003, which are reported as
a reduction to total common equity in the consolidated balance
sheets:
Thousands
2004
2003
Unearned stock compensation:
Balance at beginning of year
Purchases of restricted stock
Restricted stock amortizations
Balance at end of year
$
729 $
431
(298)
__________
862 $
__________
__________
711
328
(310)
__________
729
__________
__________
$
Under a separate plan, prior to Jan. 1, 2005, non-employee di-
rectors could elect to invest their cash fees and retainers for board
service in shares of the Company’s common stock. Under a new
deferral plan effective Jan. 1, 2005, such fees and retainers will be
deferred to a cash account. Cash account balances may be trans-
ferred to and invested in a Company stock account, at the election
of the director, up to four times per year.
N W N AT U R A L
45
Notes to Consolidated Financial Statements
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 pro-
visions of the Mortgage. The Mortgage constitutes a first mortgage
lien on substantially all of NW Natural’s utility property.
The 7-1/4% Series of Convertible Debentures may be converted
at any time into 50-1/4 shares of common stock for each $1,000
face value ($19.90 per share).
The maturities on the long-term debt outstanding, for each of
the 12-month periods through Dec. 31, 2009 amount to: $15 million
in 2005; $8 million in 2006; $29.5 million in 2007, $5 million in
2008; and none in 2009. Holders of certain long-term debt have put
options that, if exercised, would accelerate the maturities by $10
million in 2005 and $20 million in each of 2007, 2008 and 2009.
6. NOTES PAYABLE AND LINES OF CREDIT:
The Company’s primary source of short-term funds is commer-
cial paper notes payable. NW Natural issues commercial paper un-
der agency agreements with a commercial bank and such commer-
cial paper is supported by its committed bank lines of credit (see
below). At Dec. 31, 2004 and 2003, the amounts and average inter-
est rates of commercial paper debt outstanding were $102.5 million
and 2.3 percent and $85.2 million and 1.1 percent, respectively.
NW Natural has lines of credit with four commercial banks to-
taling $150 million. Half of the credit facility with each bank, total-
ing $75 million, is committed and available through Sept. 30, 2005,
and the other $75 million is committed and available through Sept.
30, 2007. Three of these commercial banks have each committed
$20 million for each of their 2005 and 2007 lines of credit and the
fourth commercial bank has committed $15 million for each of its
2005 and 2007 lines of credit.
NW Natural’s lines of credit require that credit ratings be main-
tained in effect at all times and that notice be given of any change
in its senior unsecured debt ratings. A change in NW Natural’s
credit rating is not an event of default, nor is the maintenance of a
specific minimum level of credit rating a condition to drawing upon
the lines of credit. However, interest rates on any loans outstand-
ing under NW Natural’s bank lines are tied to credit ratings, which
would increase or decrease the cost of bank debt, if any, when rat-
ings are changed.
The lines of credit require the Company to maintain an indebt-
edness to total capitalization ratio of 65 percent or less and to main-
tain a consolidated net worth at least equal to 80 percent of its net
worth at Sept. 30, 2004, plus 50 percent of the Company’s net in-
come for each subsequent fiscal quarter. Failure to comply with
either of these covenants would entitle the banks to terminate their
lending commitments and to accelerate the maturity of all amounts
outstanding. The Company was in compliance with both of these
covenants at Dec. 31, 2004, and with the equivalent covenants in
the prior year’s lines of credit at Dec. 31, 2003.
7. PENSION AND OTHER POSTRETIREMENT BENEFITS:
NW Natural maintains two qualified non-contributory defined
benefit pension plans covering all regular employees with more
than one year of service, several non-qualified supplemental pen-
sion plans for eligible executive officers and certain key employees
and other postretirement benefit plans for its employees. Only the
two qualified defined benefit pension plans have plan assets which
are held in a qualified trust to fund retirement benefits.
The following table provides a reconciliation of the changes in
benefit obligations and fair value of assets, as applicable, for the
pension plans and other postretirement benefit plans over the three-
year period ended Dec. 31, 2004, and a statement of the funded
status and amounts recognized in the consolidated balance sheets,
using measurement dates of Dec. 31, 2004, 2003 and 2002:
Thousands
Change in benefit obligation:
Benefit obligation at Jan. 1
Service cost
Interest cost
Special termination benefits
Expected benefits paid
Plan amendments
Net actuarial (gain) loss
Benefit obligation at Dec. 31
Change in plan assets:
Fair value of plan assets at Jan. 1
Actual return on plan assets
Employer contributions
Benefits paid
Fair value of plan assets at Dec. 31
Funded status:
Funded status at Dec. 31
Unrecognized transition obligation
Unrecognized prior service cost
Unrecognized net actuarial loss
Net amount recognized
Amounts recognized in the consolidated balance
sheets at Dec. 31:
Prepaid benefit cost
Accrued benefit liability
Intangible asset
Other comprehensive loss
––––––––––––––––––––––––––––––––––––––––––––– Post-Retirement Benefits ––––––––––––––––––––––––––––––––––––––––––––
––––––––––– Other Postretirement Benefits –––––––––––
––––––––––––––––– Pension Benefits –––––––––––––––––
2002
2002
2004
2004
2003
2003
$ 205,352
5,428
12,690
237
(10,682)
–
9,923
__________
$ 185,124
4,748
12,402
–
(10,363)
–
13,441
__________
$ 166,751
4,637
11,807
–
(9,453)
–
11,382
__________
$ 23,379
457
1,232
–
(1,040)
–
(1,299)
__________
$
18,457
456
1,336
–
(1,027)
(111)
4,268
__________
$ 16,987
395
1,174
–
(979)
(300)
1,180
__________
222,948
__________
205,352
__________
185,124
__________
22,729
__________
23,379
__________
18,457
__________
168,324
19,835
9,310
(10,682)
__________
143,164
34,520
1,003
(10,363)
__________
168,964
(17,082)
735
(9,453)
__________
–
–
1,040
(1,040)
__________
–
–
1,027
(1,027)
__________
–
–
979
(979)
__________
186,787
__________
168,324
__________
143,164
__________
–
__________
–
__________
–
__________
(36,162)
–
5,146
33,897
__________
(37,028)
–
6,240
32,156
__________
(41,960)
–
7,371
42,060
__________
(22,729)
3,292
–
6,717
__________
(23,379)
3,703
–
8,304
__________
(18,457)
4,226
–
4,437
__________
$
2,881
__________
__________
$
1,368
__________
__________
$
7,471
__________
__________
$ (12,720)
__________
__________
$
(11,372)
__________
__________
$
(9,794)
__________
__________
$ 12,745
(12,919)
–
3,055
__________
$
11,113
(11,319)
–
1,574
__________
$
17,339
(18,741)
4,438
4,435
__________
$
–
(12,720)
–
–
__________
$
–
(11,372)
–
–
__________
$
–
(9,794)
–
–
__________
Net amount recognized
$
2,881
__________
__________
$
1,368
__________
__________
$
7,471
__________
__________
$ (12,720)
__________
__________
$
(11,372)
__________
__________
$
(9,794)
__________
__________
46
N W N AT U R A L
The Company’s qualified defined benefit pension plans had an
accumulated benefit obligation in excess of plan assets at Dec. 31,
2004. The plans’ aggregate accumulated benefit obligation was
$209 million, $192 million and $172 million at Dec. 31, 2004, 2003
and 2002, respectively, and the fair value of plan assets was $186.8
million, $168.3 million and $143.2 million, respectively. The fair
value of plan assets increased from Dec. 31, 2003 to Dec. 31, 2004
due to $22.5 million in investment gains and employer contribu-
tions of $8.3 million, partially offset by $11.2 million in withdraw-
als to pay benefits and $1.1 million to pay eligible expenses of the
plans. The combination of investment returns and cash contribu-
tions is expected to provide sufficient funds to cover all benefit
obligations of the plans. The Company is not required to make a
cash contribution to either of its qualified pension plans for the
2005 plan year.
The Company’s investment policy and performance objectives
for the qualified pension plan assets (plan assets) held in the Retire-
ment Trust Fund was approved by the retirement committee which
is composed of management employees. The policy sets forth the
guidelines and objectives governing the investment of plan assets.
Plan assets are invested for total return with appropriate consider-
ation 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 (ERISA). The approved asset classes are cash and short-term
investments, fixed income, common stock and convertible securi-
ties, absolute and real return strategies, real estate and investments
in securities of NW Natural, and may be invested in separately
managed accounts or in commingled or mutual funds. Re-balanc-
ing will take place at least annually, or when significant cash flows
occur, in order to maintain the allocation of assets within the stated
target allocation ranges. The Retirement Trust Fund is not currently
invested in any NW Natural securities.
The Company’s pension plan asset allocation at Dec. 31, 2004
and 2003, and the target allocation and expected long-term rate of
return by asset category for 2005 are as follows:
Asset Category
US Large Cap Equity
US Small/Mid Cap Equity
Non-US Equity
Fixed Income
Real Estate
Absolute Return
Real Return
Weighted Average
Percent of
Plan Assets
——— Dec. 31,———
2003
2004
Target
Allocation
2005
36.3%
9.2%
19.2%
19.8%
3.6%
7.3%
4.6%
40.2%
7.3%
16.0%
24.8%
3.9%
7.8%
–
35%
8%
15%
25%
4%
8%
5%
Expected
Long-term
Rate
of Return
2005
9.00%
9.50%
9.00%
5.75%
8.00%
9.00%
8.25%
8.25%
The Company’s non-qualified supplemental pension plans’ ac-
cumulated benefit obligations were $13.6 million, $13.0 million
and $12.8 million at Dec. 31, 2004, 2003 and 2002, respectively.
Although the plans are unfunded plans with no plan assets due to
their nature as non-qualified plans, the Company indirectly funds
its obligations with trust-owned life insurance.
The Company’s plans for providing postretirement benefits
other than pensions also are unfunded plans. The aggregate ben-
efit obligation for those plans was $22.7 million, $23.4 million and
$18.5 million at Dec. 31, 2004, 2003 and 2002, respectively.
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 Dec. 31, 2004, 2003
and 2002, and the assumptions used in measuring these costs and
benefit obligations:
Thousands
Service cost
Interest cost
Expected return on plan assets
Amortization of transition obligation
Amortization of prior service cost
Recognized actuarial (gain) loss
Net periodic benefit cost (NPBC)
Assumptions:
Discount rate for NPBC
Rate of increase in compensation for NPBC
Expected long–term rate of return for NPBC
Discount rate for determination of funded status
Rate of increase in compensation for funded status
Expected long–term rate of return for funded status
––––––––––––––––––––––––––––––––––––––––––––– Post-Retirement Benefits ––––––––––––––––––––––––––––––––––––––––––––
––––––––––– Other Postretirement Benefits –––––––––––
––––––––––––––––– Pension Benefits –––––––––––––––––
2002
2002
2004
2004
2003
2003
$
5,428
12,689
(13,284)
–
1,094
1,631
__________
7,558
$
__________
__________
$
4,748
12,402
(12,232)
–
1,132
1,058
__________
$
7,108
__________
__________
$
4,637
11,807
(16,335)
351
1,204
(216)
__________
$
1,448
__________
__________
$
457
1,232
–
411
–
288
__________
$
2,388
__________
__________
6.25%
4.00 – 5.00%
8.25%
6.00%
4.00 – 5.00%
8.25%
6.75%
4.25 – 5.00%
8.00%
6.25%
4.00 – 5.00%
8.25%
7.25%
4.25 – 5.00%
9.00%
6.75%
4.25 – 5.00%
8.00%
6.25%
n/a
n/a
6.00%
n/a
n/a
$
456
1,336
–
411
–
401
__________
$
2,604
__________
__________
6.75%
n/a
n/a
6.25%
n/a
n/a
$
395
1,174
–
436
6
147
__________
$
2,158
__________
__________
7.25%
n/a
n/a
6.75%
n/a
n/a
N W N AT U R A L
47
8. INCOME TAXES:
A reconciliation between income taxes calculated at the statu-
tory federal tax rate and the tax provision reflected in the financial
statements is as follows:
Thousands
2004
2003
2002
$
Computed income taxes based on
statutory federal income tax rate
of 35%
Increase (reduction) in taxes
resulting from:
Difference between book and
tax depreciation
Current state income tax, net of
federal tax benefit
Federal income tax credits
Amortization of investment tax credits
Gains on Company and trust-owned
life insurance
Removal costs
Reversal of amounts provided in
prior years
Other – net
Total provision for income taxes
Total income taxes paid
26,986 $
24,263 $
23,533
222
222
222
2,554
(210)
(920)
(955)
(813)
2,310
(357)
(879)
(1,192)
(925)
2,299
(362)
(858)
(487)
(573)
(392)
59
__________
26,531 $
$
__________
__________
2,500 $
$
(226)
124
__________
23,340 $
__________
__________
13,940 $
(240)
(90)
__________
23,444
__________
__________
33,474
The provision for income taxes consists of the following:
Thousands, except percentages
2004
2003
2002
Income taxes currently payable (receivable):
Federal
State
Total
Deferred taxes – net:
Federal
State
Total
Investment and energy tax credits
restored:
From utility operations
From subsidiary operations
Total
Total provision for income taxes
Percentage of pretax income
(9,607) $
$
(1,111)
__________
(10,718)
__________
10,011 $
1,175
__________
11,186
__________
9,377
1,239
__________
10,616
__________
33,602
4,567
__________
38,169
__________
10,747
2,286
__________
13,033
__________
11,476
2,210
__________
13,686
__________
(800)
(120)
__________
(920)
__________
26,531 $
$
__________
__________
34.4%
(801)
(78)
__________
(879)
__________
23,340 $
__________
__________
33.7%
(800)
(58)
__________
(858)
__________
23,444
__________
__________
34.9%
Deferred tax assets and liabilities are comprised of the follow-
ing:
Thousands
2004
2003
Deferred tax liabilities:
Plant and property
Regulatory income tax assets
Regulatory liabilities
Other deferred liabilities
Total
Deferred tax assets:
Regulatory assets
Minimum pension liability
Other deferred assets
Alternative minimum tax credit carryforward
Loss and credit carryforwards
Total
Net accumulated deferred income tax liability
$ 146,657 $ 113,781
63,449
–
6,109
__________
183,339
__________
64,734
5,730
5,534
__________
222,655
__________
970
557
10,015
–
–
__________
11,542
__________
$ 210,715 $ 171,797
__________
__________
–
1,068
7,330
1,631
1,911
__________
11,940
__________
__________
__________
Notes to Consolidated Financial Statements
The assumed annual increase in trend rates used in measuring
postretirement benefits as of Dec. 31, 2004 were 10 percent for
medical and 13 percent for prescription drugs. Medical costs were
assumed to decrease gradually each year to a rate of 4.5 percent
for 2012, while prescription drug costs were assumed to decrease
gradually each year to a rate of 4.5 percent for 2013.
Assumed health care cost trend rates have a significant effect
on the amounts reported for the health care plans. A one percent-
age point change in assumed health care cost trend rates would
have the following effects:
Thousands
1% Decrease
1% Increase
Effect on the total service and interest cost
components of net periodic postretirement
health care benefit cost
Effect on the health care cost component of the
accumulated postretirement benefit obligation
$
$
48
901
$
(47)
$ (815)
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 Dec. 31, 2004 and 2003, and es-
timated future payments:
Thousands
Employer Contributions by Plan Year
2003
2004
2005 (estimated)
Benefit Payments
2002
2003
2004
Estimated Future Payments
2005
2006
2007
2008
2009
2010 – 2014
Pension
Benefits
Other
Benefits
$ 3,922
6,390
1,620
$ 9,453
10,363
10,682
$ 12,404
12,817
13,106
13,892
14,325
82,578
$ 1,027
1,040
1,452
$ 979
1,027
1,040
$ 1,452
1,561
1,641
1,738
1,794
9,667
NW Natural’s Retirement K Savings Plan (RKSP) is a qualified
defined contribution plan under Internal Revenue Code Section
401(k). NW Natural also has non-qualified deferred compensation
plans for eligible officers and senior managers. These plans are de-
signed to enhance the retirement program of employees and to as-
sist them in strengthening their financial security by providing an
incentive to save and invest regularly. NW Natural’s matching con-
tributions to these plans totaled $1.7 million in 2004, $1.6 million
in 2003 and $1.4 million in 2002. Effective Jan. 1, 2002, the RKSP
was amended to establish an Employee Stock Ownership Plan
(ESOP) within the RKSP by converting the existing RKSP Company
Stock Fund into an ESOP.
Effective Jan. 1, 2005, the Company will make a contribution of
25 cents per compensable hour on behalf of each union employee
to the Western States Office and Professional Employees Pension
Fund, which contributions will increase 3 percent each year, up to
30 cents per compensable hour.
48
N W N AT U R A L
The amount of income taxes paid in 2004 and 2003 decreased
significantly as compared to the total provision for income taxes,
primarily due to the effects of accelerated depreciation provisions
provided by the Job Creation and Worker Assistance Act of 2002
(the Assistance Act) and the Jobs and Growth Tax Relief Recon-
ciliation Act of 2003 (the Reconciliation Act). The Assistance Act
provided for an additional depreciation deduction equal to 30 per-
cent of an asset’s adjusted basis. The Reconciliation Act increased
this first-year additional depreciation deduction to 50 percent of an
asset’s adjusted basis. The additional first-year depreciation deduc-
tion is an acceleration of depreciation deductions that otherwise
would have been taken in the later years of an asset’s recovery pe-
riod. The accelerated depreciation provisions provided by both the
Assistance Act and the Reconciliation Act expired at Dec. 31, 2004.
The Company realized enhanced cash flow from reduced income
taxes totaling an estimated $55 million during the effective period,
based on plant investments made between Sept. 11, 2001 and Dec.
31, 2004.
For the year ended Dec. 31, 2004, the Company had an estimated
federal net operating loss (NOL) of $15.4 million and an Oregon
NOL of $18.6 million, primarily due to the effects of accelerated
tax depreciation provided by the Assistance Act and the Reconcil-
iation Act. The federal NOL will be carried back to 2002 for a re-
fund of taxes paid in prior years, and the Oregon NOL will be used
to reduce future Oregon taxable income. The Oregon NOL will ex-
pire in 2019.
At Dec. 31, 2004 the Company had $1.6 million of alternative
minimum tax credit carryforwards to offset regular federal income
tax payable in future years. In addition, the Company had certain
tax credits of approximately $0.7 million which are available to re-
duce certain federal and state income tax liabilities through 2011.
The Company anticipates that it will be able to utilize all loss and
credit carryforwards in future years.
9. PROPERTY AND INVESTMENTS:
The following table sets forth the major classifications of NW
Natural’s utility plant and accumulated depreciation at Dec. 31:
––––––––– 2003 –––––––––
Weighted
Average
Depreciation
Rate
––––––––– 2004 –––––––––
Weighted
Average
Depreciation
Rate
Thousands, except percentages
Amount
Amount
Transmission and
distribution
Utility storage
General
Intangible and other
Utility plant in service
Gas stored long-term
Held for future use
Construction work
in progress
Total utility plant
Accumulated depreciation
Regulatory liability – accrued
asset removal costs
Utility plant – net
$ 1,509,475
109,613
91,229
61,573
__________
1,771,890
13,434
1,833
7,815
__________
1,794,972
(658,544)
153,258
__________
$ 1,289,686
__________
__________
3.2% $ 1,347,402
107,547
2.6%
84,381
3.4%
56,429
8.5%
__________
1,595,759
3.4%
12,778
1,226
47,826
__________
1,657,589
(607,354)
135,638
__________
$ 1,185,873
__________
__________
3.3%
2.7%
6.0%
5.1%
3.5%
Accumulated depreciation does not include $153.3 million and
$135.6 million at Dec. 31, 2004 and 2003, respectively, which rep-
resent accrued asset removal costs and are reflected on the balance
sheets as a regulatory liability (see Note 1).
The following table summarizes the Company’s investments in
non-utility plant at Dec. 31:
Thousands, except percentages
Non-utility storage
Dock, land, oil station
and other
Non-utility plant in service
Construction work
in progress
Total non-utility plant
Less accumulated
depreciation
Non-utility plant – net
––––––––– 2004 –––––––––
Weighted
Average
Depreciation
Rate
Amount
––––––––– 2003 –––––––––
Weighted
Average
Depreciation
Rate
Amount
$
24,900
$
18,507
4,728
__________
29,628
4,335
__________
33,963
5,244
__________
28,719
$
__________
__________
3,846
__________
22,353
2.3%
2.3%
1,042
__________
23,395
4,855
_______–__
18,540
$
__________
__________
The following table summarizes the Company’s other long-term
investments, including financial investments in life insurance pol-
icies accounted for at fair value based on cash surrender values,
equity investments in certain partnerships and joint ventures ac-
counted for under the equity or cost methods, and a leveraged lease
investment in an aircraft, at Dec. 31:
Thousands
2004
2003
Life insurance
Aircraft leveraged lease
Real estate partnership
Note receivable
Gas pipeline and other
Electric generation
Total other investments
$
45,011 $
6,621
1,500
1,240
3,263
2,983
__________
60,618 $
__________
__________
59,710
6,438
1,500
–
2,880
3,317
__________
73,845
__________
__________
$
In 1987, the Company invested in a Boeing 737-300 aircraft,
which is leased to Continental Airlines for 20 years under a lever-
aged lease agreement.
A Financial Corporation subsidiary, KB Pipeline Company (KB
Pipeline), owns a 10 percent interest in an 18-mile interstate natu-
ral gas pipeline. KB Pipeline operated the pipeline for twelve years
until Dec. 1, 2004, when a third party gas distribution company
became the operator. KB Pipeline resigned as pipeline operator due,
in part, to increased obligations resulting from final Federal Energy
Regulatory Commission regulations implementing Standards of
Conduct for Transmission Providers. Those regulations govern the
relationship between interstate natural gas pipelines and their en-
ergy affiliates or marketing functions and impose obligations pre-
viously inapplicable to KB Pipeline with regard to separation of
duties and related matters. FERC granted KB Pipeline an exemp-
tion from most of the requirements of the Standards of Conduct;
however, the remainder of the regulations continue to be applicable
to KB Pipeline as a co-owner of the pipeline.
At Dec. 31, 2004, Financial Corporation held ownership inter-
ests ranging from 4.0 to 5.3 percent in three solar electric genera-
tion plants located near Barstow, California. Power generated by
these plants is sold to Southern California Edison Company under
long-term contracts. Financial Corporation also has ownership in-
terests ranging from 25 to 41 percent in wind power electric gen-
eration projects located near Livermore and Palm Springs, Califor-
nia. The wind-generated power is sold to Pacific Gas and Electric
Company and Southern California Edison Company under long-
term contracts. Financial Corporation sold its interests in the solar
electric generation plants on Jan. 31, 2005 (see Note 2).
N W N AT U R A L
49
Notes to Consolidated Financial Statements
FASB Interpretation No. 46, “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 enti-
ties.” The Company does not have any significant interests in vari-
able interest entities for which it is a 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 appro-
priate valuation methodologies. The following are financial instru-
ments whose carrying values are sensitive to market conditions:
–––––– Dec. 31, 2004 ––––– –––––– Dec. 31, 2003 ––––––
Estimated
Fair Value
Estimated
Fair Value
Carrying
Amount
Carrying
Amount
Thousands
Long-term debt including
amount due within one year $ 499,027 $ 567,926 $ 500,319 $ 562,688
Fair value of the long-term debt was estimated using market
prices on the valuation date for debt with similar credit ratings,
maturities, interest rates and other terms.
11. USE OF FINANCIAL DERIVATIVES:
NW Natural enters into short-term, medium-term and long-term
natural gas purchase contracts with suppliers, including contracts
tied to market-based index prices, and thus is exposed to changes
in commodity prices. Natural gas prices are subject to fluctuations
due to unpredictable factors including weather, inventory levels,
pipeline transportation availability, and the economy, each of
which affects short-term supply and demand. As part of its overall
strategy to maintain an acceptable level of exposure to gas price
fluctuations, NW Natural uses a targeted mix of fixed-rate and cap-
protected derivative instruments to hedge the exposure under float-
ing price gas supply contracts. Swap contracts are used to convert
certain long-term gas purchase contracts from floating prices to
fixed prices. Call option contracts are used to limit the maximum
adverse impact from floating price contracts while retaining the
potential favorable impact from declining gas prices. The prices
embedded in these commodity hedge contracts are incorporated
in annual rate changes under the PGA rate mechanisms, thereby
limiting customers’ exposure to frequent changes in purchased gas
costs. The estimated fair value of gains and losses from commod-
ity hedge contracts are recorded as a derivative asset or liability,
and are offset by a corresponding amount recorded to a deferred
regulatory asset or liability account for the effective portion of each
hedge contract. The actual gains and losses realized at settlement
of the hedge contracts are used to offset the actual gas purchase
cost from NW Natural’s physical supply contracts.
Certain natural gas purchases from Canadian suppliers are in-
voiced in Canadian dollars, including both commodity and demand
charges, thereby exposing NW Natural to adverse changes in for-
eign currency rates. Foreign currency forward contracts are used
to minimize the impact of fluctuations in currency rates. Foreign
currency contracts for commodity costs are purchased on a month-
to-month basis because the Canadian cost is priced at the average
noonday exchange rate for each month. Foreign currency contracts
for demand costs have terms ranging up to 24 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 longer-term currency contracts for demand charges
are subject to a regulatory deferral tariff and, as such, are recorded
as a derivative asset or liability which is offset by recording a cor-
responding amount to a deferred asset or liability account.
50
N W N AT U R A L
NW Natural did not use any derivative instruments to hedge oil
or propane prices or interest rates during 2004, 2003 or 2002.
At Dec. 31, 2004, NW Natural had the following derivatives out-
standing: a series of 24 fixed-price natural gas commodity price fi-
nancial swap contracts; four fixed-price natural gas financial call
option contracts; and 62 foreign currency forward purchase con-
tracts. All of these contracts were designated as cash flow hedges
covering exposures to commodity purchase and sale contracts. Un-
realized gains and losses from mark-to-market valuations of these
contracts are not recognized in current income but are reported as
derivative assets or liabilities and offset by a corresponding de-
ferred account balance under regulatory liabilities or regulatory as-
sets because regulatory mechanisms include the realized gains or
losses at settlement in utility gas costs subject to regulatory defer-
ral treatment. NW Natural also had outstanding at Dec. 31, 2004
two natural gas physical supply contracts with embedded options
which did not qualify as a normal purchase or normal sale. The
physical supply contracts were entered into using excess gas stor-
age and pipeline transportation capacity under the Company’s op-
timization program. The estimated fair values (unrealized gains
and losses) and the notional amounts of derivative instruments
outstanding were as follows:
Thousands
–––––– Dec. 31, 2004 ––––– –––––– Dec. 31, 2003 ––––––
Notional
Amount
Notional
Fair Value
Amount Gain (Loss)
Fair Value
Gain (Loss)
Fixed-price natural gas
financial swap contracts
Fixed-price natural gas
financial call option contracts
Natural gas physical supply
contracts with embedded
options
Fixed-price natural gas
financial swap contracts –
gas storage
Foreign currency forward
purchase contracts
Total
$
11,983 $ 375,975 $
23,285 $ 284,317
(2,195)
28,357
366
19,761
24
4,250
658
4,406
–
–
–
–
442
6,417
__________ __________ __________ __________
23,885 $ 310,495
$
__________ __________ __________ __________
__________ __________ __________ __________
10,912 $ 427,448 $
14,460
234
In 2004 and 2003, NW Natural realized net gains of $42.4 mil-
lion and $32.4 million, respectively, from the settlement of natural
gas commodity swap and call option contracts, which were re-
corded as decreases to the cost of gas, compared to net losses of
$75.5 million during 2002, which were recorded as increases to
the cost of gas. The currency exchange rate in all foreign currency
forward purchase contracts is included in NW Natural’s 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 recovery is in-
cluded in OCI.
The fair value of derivative instruments at Dec. 31, 2004 and
2003 (see table above) was determined using estimated or quoted
market prices for the periods covered by the contracts. Market
prices for the natural gas commodity-price swap and call option
contracts were obtained from external sources. NW Natural reviews
these third-party valuations for reasonableness using fair value cal-
culations for other contracts with similar terms and conditions. The
market prices for the foreign currency forward contracts were based
on currency exchange rates quoted by The Bank of Canada.
As of Dec. 31, 2004, five of the natural gas commodity price
swap contracts extended beyond Dec. 31, 2005, and two extended
beyond Oct. 31, 2006. None of the natural gas commodity call op-
tion contracts extends beyond March 31, 2005.
12. COMMITMENTS AND CONTINGENCIES:
Lease Commitments
The Company leases land, buildings and equipment under
agreements that expire in various years through 2018. Rental ex-
pense under operating leases was $4.5 million, $4.9 million and
$4.8 million for the years ended Dec. 31, 2004, 2003 and 2002, re-
spectively. The table below reflects the future minimum lease pay-
ments due under non-cancelable leases at Dec. 31, 2004. Such pay-
ments total $60.8 million for operating leases. The net present
value of payments on capital leases less imputed interest was $0.5
million. These commitments principally relate to the lease of the
Company’s office headquarters, underground gas storage facilities,
vehicles and computer equipment.
Millions
2005
2006
2007
2008
2009
Later
years
Operating leases
Capital leases
Minimum lease
payments
$ 4.5 $ 4.2 $ 4.1 $ 4.0 $ 3.9 $ 39.6
–
0.2
______ ______ ______ ______ ______ ______
0.2
0.1
–
–
$ 4.7 $ 4.4 $ 4.2 $ 4.0 $ 3.9 $ 39.6
______ ______ ______ ______ ______ ______
______ ______ ______ ______ ______ ______
Pipeline Capacity Purchase and Release Commitments
NW Natural has signed agreements providing for the reserva-
tion of firm pipeline capacity under which it must 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, NW Natural has en-
tered into long-term sale agreements to release firm pipeline capac-
ity. The aggregate amounts of these agreements were as follows at
Dec. 31, 2004:
Thousands
2005
2006
2007
2008
2009
2010 through 2024
Total
Less: Amount representing interest
Total at present value
Pipeline
Capacity
Purchase
Agreements
Pipeline
Capacity
Release
Agreements
$
66,703 $
61,514
62,696
60,949
54,417
274,891
__________
581,170
113,024
__________
$ 468,146 $
__________
__________
3,715
3,715
3,715
3,715
3,715
3,095
__________
21,670
2,369
__________
19,301
__________
__________
NW Natural’s total payments of fixed charges under capacity
purchase agreements in 2004, 2003 and 2002 were $89.3 million,
$86.7 million and $86.2 million, respectively. Included in the amounts
for 2004, 2003 and 2002 were reductions for capacity release sales
of $3.7 million, $3.7 million and $4.2 million, respectively. In ad-
dition, 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 pre-
payments subject to recovery over a longer term if future purchases
exceed the minimum annual requirements.
Environmental Matters
NW Natural owns or previously owned properties currently be-
ing investigated that may require environmental response. NW
Natural has accrued all material loss contingencies relating to en-
vironmental matters that it believes to be probable of assertion and
reasonably estimable. The Company continues to study the extent
of its environmental liabilities, but due to the preliminary nature
of the environmental investigations being conducted, the range of
loss contingencies beyond the amounts currently accrued, and the
probabilities thereof, cannot be reasonably estimated.
GASCO SITE. NW Natural owns 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 un-
der investigation by NW Natural for environmental contamination
under the Oregon Department of Environmental Quality’s (ODEQ)
Voluntary Clean-Up Program. In June 2003, the Company 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.
NW Natural continues to work with the ODEQ to determine the
appropriate remedial action from among the alternatives. Based
upon the proposed actions in the draft plan, the Company esti-
mates its range of remaining liability, including the cost of investi-
gation, from among feasible alternatives, at between $1.3 million
and $7 million.
WACKER SITE. NW Natural previously owned property adjacent
to the Gasco site that now is the location of a manufacturing plant
owned by Siltronic Corporation, formerly Wacker Siltronic Corpo-
ration (the Wacker site). In 2000, the ODEQ issued an order requir-
ing Wacker and NW Natural to determine the nature and extent of
releases of hazardous substances to Willamette River sediments
from the Wacker site. In 2004, consultant studies indicated that
some benzene is present in the soil at the Wacker site. The ODEQ
requested that NW Natural conduct further tests of groundwater
and indoor air quality. The work plan for the implementation of
the benzene indoor air-sampling program was approved by the
ODEQ in November 2004. NW Natural recorded expenses in 2004
totaling $0.1 million for its estimated costs of investigation and ini-
tial remediation at the Wacker site.
PORTLAND HARBOR. In 1998, the ODEQ and the U.S. Environ-
mental Protection Agency (EPA) completed a study of sediments
in a 5.5-mile segment of the Willamette River (the Portland Har-
bor) that includes the area adjacent to the Gasco site and the
Wacker site. In 2000, the EPA listed the Portland Harbor as a Su-
perfund site and notified the Company that it is a potentially re-
sponsible party. Subsequently, the EPA approved the Programmatic
Work Plan, Field Sampling Plan and Quality Assurance Project Plan
for the Portland Harbor Remedial Investigation/Feasibility Study.
NW Natural’s share of the estimated budget to complete the first
phase of the work is $1.0 million, which is expected to be com-
pleted in 2007. The EPA has indicated that further study in a sec-
ond phase will be required; however, the scope of the work to be
completed in a second phase has yet to be determined.
In April 2004 the Company entered into an Administrative Or-
der on Consent (AOC) providing for early action removal of a body
of tar in the river sediments adjacent to the Gasco site. In July 2004,
the EPA approved an initial work plan for the early action removal.
The Company continues to negotiate with the EPA regarding the
method and timing of the removal of the body of tar. The Company
currently estimates the removal cost to be in the range of $3.0 mil-
lion to $5.0 million. In addition, the Company has agreed with the
ODEQ to do additional work, if necessary, on the Gasco site in con-
junction with the EPA early action remediation work.
N W N AT U R A L
51
Notes to Consolidated Financial Statements
During 2004, NW Natural accrued additional loss contingencies
totaling $4.3 million for the above-described study work and the
revised estimate of tar body remediation costs. NW Natural’s liabil-
ity is based on its best estimate of probable costs, and if a specific
amount is no more or less likely than another amount in the range
of probable liability, then the Company recognizes its liability at
the lower end of the range of probable liability. Currently available
information is insufficient to determine either the total amount of
liability, or the higher end of a range for NW Natural’s estimated
share of potential future remediation related to the Portland Harbor
site. The Company expects to receive additional information when
the Remedial Investigation/Feasibility Study report is completed.
A preliminary report is expected to be available during 2005.
PORTLAND GAS SITE. The City of Portland notified NW Natural
that it was planning a sewer improvement project that would in-
clude excavation within the former site of a gas manufacturing
plant (the Portland Gas site) that was owned and operated by a
predecessor of the Company between 1860 and 1913. The prelimi-
nary assessment of this site performed by a consultant for the EPA
in 1987 indicated that it could be assumed that by-product tars may
have been disposed of on site. The report concluded, however, that
it is likely that waste residues from the plant, if present on the site,
were covered by deep fill during construction of the nearby seawall
bordering the Willamette River and probably have stabilized due
to physical and chemical processes. Neither the City of Portland nor
the ODEQ has notified NW Natural whether a further investigation
or potential remediation might be required on the site in connec-
tion with the sewer project, which has commenced. Available in-
formation is insufficient to determine either the total amount of NW
Natural’s liability or a probable range, if any, of potential liability.
OREGON STEEL MILLS SITE. On Dec. 20, 2004, the Company 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 1940’s and
1950’s petroleum wastes generated by the Company’s predecessor,
Portland Gas & Coke Company, and nine other third-party defen-
dants 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 dis-
posal facility as well as a declaratory judgment allocating liability
for future remedial action costs. NW Natural does not believe there
are facts sufficient to constitute a claim against the Company.
CORPS OF ENGINEERS NOTICE OF NONCOMPLIANCE. On July 2,
2004, the U.S. Army Corps of Engineers (Corps) issued to the Com-
pany a Notice of Noncompliance (Notice) for discharges of drilling
mud into three streams during drilling operations on the Compa-
ny’s South Mist Pipeline Extension (SMPE) project. The Corps’ No-
tice claimed that the discharges violated the scope of work in per-
mits for the drilling. The Company cooperated with the Corps in
its investigation and worked closely with the Corps and other state
and federal agencies to minimize impacts from the unintended dis-
charges. The final disposition of this matter resulted in the payment
of a nominal fine.
52
N W N AT U R A L
REGULATORY AND INSURANCE RECOVERY FOR ENVIRONMENTAL
MATTERS. In May 2003, the OPUC approved NW Natural’s request
for deferral of environmental costs associated with specific sites,
including the Gasco, Wacker, Portland Harbor and Portland Gas
sites. The authorization, which has been extended through April
2005, allows NW Natural to defer and seek recovery of unreim-
bursed environmental costs in a future general rate case. On a cu-
mulative basis through Dec. 31, 2004, the Company paid out a to-
tal of $3.3 million relating to the named sites since the effective
date of the deferral authorization. NW Natural will first seek to re-
cover the costs of investigation and remediation for which it may
be responsible with respect to the Gasco, Wacker, Portland Harbor
and Portland Gas sites, if any, from insurance. If these costs are not
recovered from insurance, then NW Natural will seek OPUC ap-
proval to recover them through future rates. At Dec. 31, 2004, NW
Natural had a receivable of $8.5 million representing an estimate
of the environmental costs it expects to recover from insurance,
consisting of $2.8 million for costs relating to the Gasco site, $5.5
million for costs relating to the Portland Harbor site and $0.2 mil-
lion relating to the Oregon Steel Mills site.
On Jan. 27, 2005, NW Natural filed a request with the OPUC for
authorization to defer costs associated with the Oregon Steel Mills
site and to extend the deferral authority for the other named envi-
ronmental sites through Jan. 26, 2006.
The following table summarizes the insurance receivables and
the accrued liabilities relating to environmental matters at Dec. 31,
2004 and 2003.
Millions
Gasco site
Wacker site
Portland Harbor site
Portland Gas site
Oregon Steel Mills site
Total
–– Insurance Receivable –– –––– Accrued Liability ––––
12/31/03
12/31/04
12/31/04
12/31/03
$
1.5
2.5 $
–
–
0.6
1.2
–
–
–
–
__________ __________ __________ __________
2.1
3.7 $
$
__________ __________ __________ __________
__________ __________ __________ __________
1.3 $
0.1
3.4
–
0.2
5.0 $
2.8 $
–
5.5
–
0.2
8.5 $
Legal Proceedings
Litigation
On October 16, 2003, Longview Fibre Company (Longview)
filed suit in Federal Court (Longview Fibre Company v. Enerfin Re-
sources Northwest Limited Partnership and Northwest Natural Gas
Company (US District Court – Oregon District)) seeking a declara-
tory judgment regarding the continuing existence of a certain oil
and gas lease in the Mist gas field between Longview and Enerfin
Resources Northwest Limited Partnership (Enerfin). NW Natural
holds a gas storage lease from Longview (the Cascade Lease),
which covers the same land as the Enerfin lease, and which grants
the right to produce native oil and gas. Enerfin originally filed
crossclaims against NW Natural alleging that NW Natural wrongly
interfered with Enerfin’s attempts to continue its oil and gas lease
with Longview; however, Enerfin agreed to dismiss those claims
in a previous settlement with NW Natural. In that settlement, NW
Natural subleased portions of the Cascade Lease to Enerfin for the
purpose of producing native gas. In September 2004, NW Natural
and Enerfin filed claims and counterclaims against Longview, and
Longview filed claims and counterclaims against NW Natural and
Enerfin. The claims that Longview made against NW Natural in-
volved allegations of unpaid royalties under the Cascade Lease.
On Dec. 20, 2004, the Company 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 1940’s and 1950’s petroleum wastes
generated by the Company’s predecessor, Portland Gas & Coke
Company, and nine 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 in-
curred by the Port regarding the former waste oil disposal facility
as well as a declaratory judgment allocating liability for future re-
medial action costs. NW Natural does not believe there are facts
sufficient to constitute a claim against the Company.
In connection with the construction of the SMPE, NW Natural
continues to negotiate with some land owners regarding valuation
of easements and rights-of-way obtained pursuant to condemna-
tion proceedings. In some cases, compensation will be determined
in individual court proceedings that have been scheduled through
June 2005. The Company is unable to determine the likelihood of
unfavorable outcomes of these matters, but believes that the ag-
gregate amount of compensation ultimately paid will not be mate-
rial to the Company’s financial condition, results of operations or
cash flows.
The Company is subject to other claims and litigation arising in
the ordinary course of business. Although the final outcome of any
of these legal proceedings cannot be predicted with certainty, the
Company does not expect that the ultimate disposition of these
matters will have a materially adverse effect on the Company’s fi-
nancial condition, results of operations or cash flows.
All parties to the Longview litigation entered into a Settlement
Agreement, effective Jan. 11, 2005. As part of the settlement,
Longview granted NW Natural an easement for use in producing
oil and gas from the lands covered by the Cascade Lease. Other
than payments made in respect of the easement, and royalty pay-
ments under the relevant leases and subleases, which were not
material, no payments were made in connection with the Longview
settlement. All claims were dismissed on Jan. 28, 2005 pursuant to
the Settlement Agreement.
On May 28, 2004, a lawsuit was filed against the Company
(Kerry Law, Arnold Zuehlke and Kenneth Cooper, on behalf of them-
selves and all others similarly situated v. Northwest Natural Gas
Company (U.S. Dist. Ct. D. Or., Case No. CV-04-728-AS)) by three
individuals alleging violation of the Fair Labor Standards Act for
failure to pay overtime. The suit was subsequently amended to in-
clude state wage and hour claims. The plaintiffs are or have been
independent backhoe operators who performed services for the
Company under contract. In the lawsuit, the plaintiffs claim that
they, and others similarly situated, should have been considered
“employees” of the Company instead of independent contractors.
The plaintiffs seek overtime and interest in amounts to be deter-
mined, liquidated damages equal to the overtime award, civil pen-
alties and attorneys fees and costs. The plaintiffs sought to certify
this case as a collective action under the Fair Labor Standards Act;
however, on Oct. 5, 2004, plaintiffs’ motion for collective action
certification was denied. As a result of this ruling, the case is pro-
ceeding with the three current plaintiffs, and any others who wish
to join must do so individually. Although no other claims have
been filed in this lawsuit, plaintiffs’ counsel has indicated to the
court their intention to file additional claims seeking employee ben-
efits allegedly due to plaintiffs. In addition, the claims in the law-
suit described below may be consolidated with this lawsuit. The
Company intends to vigorously contest the claims. There is insuf-
ficient information at this point in the litigation to reasonably esti-
mate the amount of liability, if any, from this claim.
On Feb. 18, 2005, a lawsuit was filed against the Company
(Kasey Cooper, Kevin Cooper, C.G. Nick Courtney, John V. Shooter,
Ike Whittlesey and Roger Whittlesey v. Northwest Natural (U.S. Dist.
Ct. D. Or., Case No. CV-05-241-KI)) by six additional individual in-
dependent backhoe operators who have performed services for the
Company under contract. Like the plaintiffs in the claim described
above, these plaintiffs allege that they should have been considered
“employees” of the Company. They seek overtime wages under the
Fair Labor Standards Act and interest in amounts to be determined,
liquidated damages equal to the overtime award, civil penalties and
attorneys fees and costs. In addition, the plaintiffs allege that fail-
ure to classify them as employees constituted a breach of contract
under certain of the Company’s employee benefit programs, agree-
ments and plans, which conferred employment-related compensa-
tion, rights and benefits. They seek an unspecified amount of dam-
ages for the value of what they would have received under these
programs, agreements and plans if they had been classified as em-
ployees. The Company intends to vigorously contest the claims.
There is insufficient information at this point in the litigation to rea-
sonably estimate the amount of liability, if any, from this claim.
N W N AT U R A L
53
Comparative Consolidated Income Statements
Thousands, except per share amounts (year ended December 31)
2004
2003
2002
2001
2000
1999
1998
1997
1996
1995
1994
Operating revenues:
Gross operating revenues*
Cost of sales*
Net operating revenues*
Operating expenses:
Operations and maintenance
Taxes other than income taxes
Depreciation, depletion and amortization
Total operating expenses
Income from continuing operations
Other income (expense)*
Interest charges – net
Income before income taxes
Income taxes
Net income from continuing operations
Discontinued segment
Income from discontinued segment – net of tax
Gain on sale of discontinued segment – net of tax
Net income
Redeemable preferred and preference
stock dividend requirements
Earnings applicable to common stock
Average common shares outstanding
Basic
Diluted
Basic earnings per share of common stock:
From continuing operations
From discontinued segment
From gain on sale of discontinued segment
Total basic earnings per share
Diluted earnings per share of common stock:
From continuing operations
From discontinued segment
From gain on sale of discontinued segment
Total diluted earnings per share
Dividends per share of common stock
See Notes to Consolidated Financial Statements.
$ 707,604
399,244
__________
308,360
$ 611,256
323,190
__________
288,066
102,155
38,808
57,371
__________
198,334
__________
110,026
2,828
35,751
__________
77,103
__________
26,531
__________
50,572
96,420
35,125
54,249
__________
185,794
__________
102,272
2,150
35,099
__________
69,323
__________
23,340
__________
45,983
–
–
__________
50,572
–
–
__________
45,983
–
__________
50,572
$
__________
__________
294
__________
45,689
$
__________
__________
27,016
27,283
25,741
26,061
$
1.87
–
–
__________
1.87
$
__________
__________
$
1.77
–
–
__________
1.77
$
__________
__________
$
1.86
–
–
__________
1.86
$
__________
__________
$
1.30
__________
__________
$
1.76
–
–
__________
1.76
$
__________
__________
$
1.27
__________
__________
*Interest on deferred regulatory accounts for years prior to 1998 was reclassified from gross operating
revenues or cost of sales to other income (expense).
$ 641,376
353,832
__________
287,544
$ 650,252
374,241
__________
276,011
$ 532,110
274,160
__________
257,950
$ 455,834
212,197
__________
243,637
$ 404,390
173,424
__________
230,966
$ 351,709
130,599
__________
221,110
$ 370,826
141,842
__________
228,984
$ 355,627
142,025
__________
213,602
$ 367,861
162,199
__________
205,662
85,120
34,076
__________
52,090
171,286
__________
116,258
(14,890)
__________
34,132
__________
67,236
__________
23,444
43,792
83,920
32,240
__________
49,640
165,800
__________
110,211
1,334
__________
33,805
__________
77,740
__________
27,553
50,187
77,817
28,351
__________
47,440
153,608
__________
104,342
3,860
__________
33,561
__________
74,641
__________
26,829
47,812
73,209
24,652
78,226
21,939
73,864
19,952
76,204
21,597
72,018
24,181
70,881
24,263
__________
51,008
148,869
__________
__________
43,937
144,102
__________
__________
39,051
132,867
__________
__________
37,971
135,772
__________
__________
40,594
136,793
__________
__________
38,058
133,202
__________
94,768
4,816
86,864
(13,723)
88,243
4,138
93,212
6,891
76,809
9,055
72,460
8,393
__________
30,052
__________
69,532
__________
24,591
44,941
__________
31,586
__________
41,555
__________
14,604
26,951
__________
28,469
__________
63,912
__________
21,034
42,878
__________
26,711
__________
73,392
__________
27,118
46,274
__________
25,679
__________
60,185
__________
22,120
38,065
__________
24,919
__________
55,934
__________
20,473
35,461
–
–
–
355
350
181
519
–
–
__________
–
__________
–
__________
2,412
__________
–
__________
–
__________
–
__________
–
__________
–
__________
–
43,792
50,187
50,224
45,296
27,301
43,059
46,793
38,065
35,461
__________
2,280
$
__________
__________
41,512
__________
2,401
$
__________
__________
47,786
__________
2,456
$
__________
__________
47,768
__________
2,515
$
__________
__________
42,781
__________
2,577
$
__________
__________
24,724
__________
2,646
$
__________
__________
40,413
__________
2,723
$
__________
__________
44,070
__________
2,806
$
__________
__________
35,259
__________
2,983
$
__________
__________
32,478
25,431
25,814
25,159
25,612
25,183
25,638
24,976
25,468
24,233
24,763
22,698
23,248
22,391
22,963
21,817
22,428
–
–
–
–
–
–
$
1.63
$
1.90
$
1.80
$
$
1.70
0.01
$
1.01
0.01
$
1.77
0.01
1.95
0.02
$
1.62
$
__________
–
$
__________
__________
1.63
__________
–
$
__________
__________
1.90
__________
0.10
$
__________
__________
1.90
__________
–
$
__________
__________
1.71
__________
–
$
__________
__________
1.02
__________
–
$
__________
__________
1.78
__________
–
$
__________
__________
1.97
__________
–
$
__________
__________
1.62
__________
–
$
__________
__________
1.63
$
1.62
$
1.88
$
1.79
$
$
1.69
0.01
$
1.01
0.01
$
1.75
0.01
1.92
0.02
$
1.60
$
1.61
–
__________
–
$
__________
__________
1.62
$
__________
__________
1.26
__________
–
$
__________
__________
1.88
$
__________
__________
1.245
__________
0.09
$
__________
__________
1.88
$
__________
__________
1.24
__________
–
$
__________
__________
1.70
$
__________
__________
1.225
__________
–
$
__________
__________
1.02
$
__________
__________
1.22
__________
–
$
__________
__________
1.76
$
__________
__________
1.205
__________
–
$
__________
__________
1.94
$
__________
__________
1.20
__________
–
$
__________
__________
1.60
$
__________
__________
1.18
__________
–
$
__________
__________
1.61
$
__________
__________
1.173
19,943
20,577
1.63
–
–
–
UTILITY GAS REVENUES
BY CUSTOMER CLASS
2004
8%
2%
90%
8%
4%
1994
88%
RESIDENTIAL, COMMERCIAL AND
INDUSTRIAL FIRM
INDUSTRIAL INTERRUPTIBLE
TRANSPORTATION
Revenues from residential,
commercial and industrial firm
sales customers exceed 90 percent
of total gas revenues.
NET INCOME
IN MILLIONS OF DOLLARS
$70
$60
$50
$40
$30
$20
$10
94 95 96 97 98 99 00 01 02
03 04
The Company earned $50.6
million in net income in 2004.
54 N W N AT U R A L
Thousands, except per share amounts (year ended December 31)
2004
2003
2002
2001
2000
1999
1998
1997
1996
1995
1994
Operating revenues:
Gross operating revenues*
Cost of sales*
Net operating revenues*
Operating expenses:
Operations and maintenance
Taxes other than income taxes
Depreciation, depletion and amortization
Total operating expenses
Income from continuing operations
Other income (expense)*
Interest charges – net
Income before income taxes
Income taxes
Net income from continuing operations
Discontinued segment
Income from discontinued segment – net of tax
Gain on sale of discontinued segment – net of tax
Net income
Redeemable preferred and preference
stock dividend requirements
Earnings applicable to common stock
Average common shares outstanding
Basic
Diluted
Basic earnings per share of common stock:
From continuing operations
From discontinued segment
From gain on sale of discontinued segment
Total basic earnings per share
Diluted earnings per share of common stock:
From continuing operations
From discontinued segment
From gain on sale of discontinued segment
Total diluted earnings per share
Dividends per share of common stock
See Notes to Consolidated Financial Statements.
$ 707,604
399,244
__________
308,360
$ 611,256
323,190
__________
288,066
102,155
38,808
__________
57,371
198,334
__________
110,026
2,828
__________
35,751
__________
77,103
__________
26,531
50,572
96,420
35,125
__________
54,249
185,794
__________
102,272
2,150
__________
35,099
__________
69,323
__________
23,340
45,983
–
–
__________
–
__________
–
50,572
45,983
__________
–
$
__________
__________
50,572
__________
294
$
__________
__________
45,689
27,016
27,283
25,741
26,061
1.77
–
$
1.87
$
–
–
__________
–
$
__________
__________
1.87
__________
–
$
__________
__________
1.77
$
1.86
$
1.76
–
__________
–
$
__________
__________
1.86
$
__________
__________
1.30
__________
–
$
__________
__________
1.76
$
__________
__________
1.27
*Interest on deferred regulatory accounts for years prior to 1998 was reclassified from gross operating
revenues or cost of sales to other income (expense).
$ 641,376
353,832
__________
287,544
$ 650,252
374,241
__________
276,011
$ 532,110
274,160
__________
257,950
$ 455,834
212,197
__________
243,637
$ 404,390
173,424
__________
230,966
$ 351,709
130,599
__________
221,110
$ 370,826
141,842
__________
228,984
$ 355,627
142,025
__________
213,602
$ 367,861
162,199
__________
205,662
85,120
34,076
52,090
__________
171,286
__________
116,258
(14,890)
34,132
__________
67,236
__________
23,444
__________
43,792
83,920
32,240
49,640
__________
165,800
__________
110,211
1,334
33,805
__________
77,740
__________
27,553
__________
50,187
77,817
28,351
47,440
__________
153,608
__________
104,342
3,860
33,561
__________
74,641
__________
26,829
__________
47,812
73,209
24,652
51,008
__________
148,869
__________
94,768
4,816
30,052
__________
69,532
__________
24,591
__________
44,941
78,226
21,939
43,937
__________
144,102
__________
86,864
(13,723)
31,586
__________
41,555
__________
14,604
__________
26,951
73,864
19,952
39,051
__________
132,867
__________
88,243
4,138
28,469
__________
63,912
__________
21,034
__________
42,878
76,204
21,597
37,971
__________
135,772
__________
93,212
6,891
26,711
__________
73,392
__________
27,118
__________
46,274
72,018
24,181
40,594
__________
136,793
__________
76,809
9,055
25,679
__________
60,185
__________
22,120
__________
38,065
70,881
24,263
38,058
__________
133,202
__________
72,460
8,393
24,919
__________
55,934
__________
20,473
__________
35,461
–
–
__________
43,792
–
–
__________
50,187
–
2,412
__________
50,224
355
–
__________
45,296
350
–
__________
27,301
181
–
__________
43,059
519
–
__________
46,793
–
–
__________
38,065
–
–
__________
35,461
2,280
__________
41,512
$
__________
__________
2,401
__________
47,786
$
__________
__________
2,456
__________
47,768
$
__________
__________
2,515
__________
42,781
$
__________
__________
2,577
__________
24,724
$
__________
__________
2,646
__________
40,413
$
__________
__________
2,723
__________
44,070
$
__________
__________
2,806
__________
35,259
$
__________
__________
2,983
__________
32,478
$
__________
__________
25,431
25,814
25,159
25,612
25,183
25,638
24,976
25,468
24,233
24,763
22,698
23,248
22,391
22,963
21,817
22,428
19,943
20,577
$
1.63
–
–
__________
1.63
$
__________
__________
$
1.90
–
–
__________
1.90
$
__________
__________
$
1.80
–
0.10
__________
1.90
$
__________
__________
$
1.70
0.01
–
__________
1.71
$
__________
__________
$
1.01
0.01
–
__________
1.02
$
__________
__________
$
1.77
0.01
–
__________
1.78
$
__________
__________
$
1.95
0.02
–
__________
1.97
$
__________
__________
$
1.62
–
–
__________
1.62
$
__________
__________
$
1.63
–
–
__________
1.63
$
__________
__________
$
1.62
–
–
__________
1.62
$
__________
__________
$
1.26
__________
__________
$
1.88
–
–
__________
1.88
$
__________
__________
$
1.245
__________
__________
$
1.79
–
0.09
__________
1.88
$
__________
__________
$
1.24
__________
__________
$
1.69
0.01
–
__________
1.70
$
__________
__________
$
1.225
__________
__________
$
1.01
0.01
–
__________
1.02
$
__________
__________
$
1.22
__________
__________
$
1.75
0.01
–
__________
1.76
$
__________
__________
$
1.205
__________
__________
$
1.92
0.02
–
__________
1.94
$
__________
__________
$
1.20
__________
__________
$
1.60
–
–
__________
1.60
$
__________
__________
$
1.18
__________
__________
$
1.61
–
–
__________
1.61
$
__________
__________
$
1.173
__________
__________
N W N AT U R A L
55
Comparative Consolidated Balance Sheets
Thousands of dollars (December 31)
2004
2003
2002
2001
2000
1999
1998
1997
1996
1995
1994
Assets:
Plant and property:
Utility plant
Less accumulated depreciation**
Utility plant – net
Non-utility property
Less accumulated depreciation and depletion
Non-utility property – net
Total plant and property
Other investments
Current assets:
Cash and cash equivalents
Accounts receivable – net
Accrued unbilled revenue
Inventories of gas, materials and supplies
Investment in discontinued segment
Property held for sale
Prepayments and other current assets
Total current assets
Regulatory tax assets
Deferred gas costs receivable
Unrealized loss on non-trading derivatives
Deferred debits and other
Total assets
Capitalization and liabilities:
Capitalization:
Common stock equity
Redeemable preference stock
Redeemable preferred stock
Total capital stock
First mortgage bonds
Unsecured debt
Total long-term debt
Total capitalization
Minority interest
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
Deferred investment tax credits
Deferred income taxes
Fair value of non-trading derivatives
Deferred gas costs payable
Accrued asset removal costs**
Other
Total capitalization and liabilities
$ 1,794,972
505,286
__________
1,289,686
__________
33,963
5,244
__________
28,719
__________
1,318,405
__________
60,618
__________
5,248
60,675
64,401
66,477
–
–
40,316
__________
237,117
__________
64,734
__________
9,551
__________
–
__________
41,770
__________
$ 1,732,195
__________
__________
$ 568,517
–
–
__________
568,517
__________
479,500
4,527
__________
484,027
__________
1,052,544
__________
–
__________
102,500
102,478
15,000
10,242
2,897
34,168
__________
267,285
__________
6,025
__________
210,715
__________
5,487
__________
–
__________
153,258
__________
36,881
__________
$ 1,732,195
__________
__________
$ 1,657,589
471,716
__________
1,185,873
__________
23,395
4,855
__________
18,540
__________
1,204,413
__________
73,845
__________
4,706
48,499
59,109
50,859
–
–
32,661
__________
195,834
__________
63,449
__________
–
__________
–
__________
47,838
__________
$ 1,585,379
__________
__________
$ 506,316
–
–
__________
506,316
__________
494,500
5,819
__________
500,319
__________
1,006,635
__________
–
__________
85,200
86,029
–
8,605
2,998
31,589
__________
214,421
__________
6,945
__________
171,797
__________
–
__________
5,627
__________
135,638
__________
44,316
__________
$ 1,585,379
__________
__________
*Deferred gas costs were included in deferred debits or regulatory accounts prior to 1995.
**Removal costs were reclassified from accumulated depreciation to regulatory liabilities and accrued
asset removal costs.
$ 1,539,965
435,601
__________
1,104,364
__________
20,832
__________
4,404
__________
16,428
1,120,792
__________
__________
67,619
$ 1,465,079
398,668
__________
1,066,411
__________
18,203
__________
4,007
__________
14,196
1,080,607
__________
__________
76,266
$ 1,406,970
371,437
__________
1,035,533
__________
8,649
__________
3,451
__________
5,198
1,040,731
__________
__________
63,638
$ 1,331,415
337,995
__________
993,420
__________
8,548
__________
7,654
__________
894
994,314
__________
__________
61,289
$ 1,239,690
313,149
__________
926,541
__________
89,050
__________
29,927
__________
59,123
985,664
__________
__________
53,370
$ 1,164,499
283,495
__________
881,004
__________
52,422
__________
22,843
__________
29,579
910,583
__________
__________
67,625
$ 1,055,112
260,089
__________
795,023
__________
45,689
__________
19,388
__________
26,301
821,324
__________
__________
63,548
$ 969,075
239,493
__________
729,582
__________
53,807
__________
16,997
__________
36,810
766,392
__________
__________
62,743
$ 908,238
__________
216,711
691,527
__________
49,586
__________
24,456
__________
25,130
716,657
__________
__________
61,420
7,328
46,936
44,069
58,030
–
–
10,440
64,722
57,749
49,337
–
–
11,283
60,753
45,619
46,883
–
–
10,013
43,349
31,550
33,919
29,163
16,712
7,383
47,476
34,258
21,258
–
–
6,731
39,420
23,911
17,385
–
–
8,219
40,833
22,340
14,439
–
–
7,782
34,385
21,493
14,254
–
–
8,068
42,152
20,320
14,958
–
–
__________
36,934
193,297
__________
__________
47,975
__________
–
__________
–
__________
37,594
$ 1,467,277
__________
__________
__________
28,086
210,334
__________
__________
48,469
__________
–
__________
111,641
__________
23,336
$ 1,550,653
__________
__________
__________
22,834
187,372
__________
__________
49,515
__________
16,973
__________
–
__________
27,185
$ 1,385,414
__________
__________
__________
18,349
183,055
__________
__________
51,060
__________
20,950
__________
–
__________
32,146
$ 1,342,814
__________
__________
__________
16,105
126,480
__________
__________
56,860
__________
27,795
__________
–
__________
32,535
$ 1,282,704
__________
__________
__________
17,226
104,673
__________
__________
56,860
__________
28,628
__________
–
__________
26,360
$ 1,194,729
__________
__________
__________
12,483
__________
98,314
__________
57,940
__________
–
__________
–
__________
23,795
$ 1,064,921
__________
__________
__________
12,396
__________
90,310
__________
60,430
__________
–
__________
–
__________
18,611
$ 998,486
__________
__________
__________
10,041
__________
95,539
__________
60,430
__________
*
__________
–
__________
17,659
$ 951,705
__________
__________
$ 482,392
$ 468,161
$ 452,309
$ 429,596
$ 412,404
$ 366,265
$ 346,778
$ 323,552
$ 274,408
–
__________
8,250
490,642
__________
439,500
__________
6,445
445,945
__________
936,587
__________
__________
–
69,802
74,436
20,000
7,822
2,902
__________
30,045
205,007
__________
__________
7,824
141,732
__________
__________
–
__________
10,635
125,197
__________
__________
40,295
$ 1,467,277
__________
__________
25,000
__________
9,000
502,161
__________
370,000
__________
8,377
378,377
__________
880,538
__________
__________
–
108,291
70,698
40,000
22,539
3,658
__________
28,396
273,582
__________
__________
8,682
130,424
__________
__________
111,868
__________
10,089
115,631
__________
__________
19,839
$ 1,550,653
__________
__________
25,000
__________
9,750
487,059
__________
382,000
__________
18,790
400,790
__________
887,849
__________
__________
–
56,263
110,698
20,000
8,066
2,696
__________
23,638
221,361
__________
__________
9,538
141,656
__________
__________
–
__________
–
106,701
__________
__________
18,309
$ 1,385,414
__________
__________
25,000
__________
10,564
465,160
__________
377,000
__________
19,379
396,379
__________
861,539
__________
__________
–
25,000
__________
11,499
448,903
__________
347,000
__________
19,738
366,738
__________
815,641
__________
__________
16,322
25,000
__________
12,429
403,694
__________
324,000
__________
20,303
344,303
__________
747,997
__________
__________
–
25,000
__________
13,749
385,527
__________
236,000
__________
35,838
271,838
__________
657,365
__________
__________
–
25,000
__________
14,840
363,392
__________
238,000
__________
41,945
279,945
__________
643,337
__________
__________
–
26,252
__________
15,950
316,610
__________
234,000
__________
57,076
291,076
__________
607,686
__________
__________
–
94,149
68,163
10,000
4,101
4,673
87,264
56,039
10,000
7,486
6,204
89,317
58,775
16,000
4,656
6,058
50,058
64,795
26,000
3,196
5,396
28,832
41,784
21,000
10,281
4,617
53,654
48,517
1,000
6,584
4,570
__________
39,153
220,239
__________
__________
10,393
136,150
__________
__________
–
__________
–
__________
98,391
__________
16,102
$ 1,342,814
__________
__________
__________
23,477
190,470
__________
__________
11,248
140,310
__________
__________
–
__________
–
__________
90,968
__________
17,745
$ 1,282,704
__________
__________
__________
21,390
196,196
__________
__________
11,949
139,953
__________
__________
–
__________
–
__________
83,112
__________
15,522
$ 1,194,729
__________
__________
__________
19,418
168,863
__________
__________
11,668
123,625
__________
__________
–
__________
8,058
__________
76,052
__________
19,290
$ 1,064,921
__________
__________
__________
13,204
119,718
__________
__________
12,493
118,692
__________
__________
–
__________
19,914
__________
69,209
__________
15,123
$ 998,486
__________
__________
__________
11,757
126,082
__________
__________
13,530
112,433
__________
__________
–
__________
*
__________
62,401
__________
29,573
$ 951,705
__________
__________
NET UTILITY PLANT
IN MILLIONS OF DOLLARS
$1,250
$1,000
$750
$500
$250
94 95 96 97 98 99 00 01 02
03 04
Utility plant continued to increase
in 2004 as a result of customer
growth and investments in
infrastructure and gas storage.
CAPITALIZATION
IN MILLIONS OF DOLLARS
$1200
$1000
$800
$600
$400
$200
94 95 96 97 98 99 00 01 02
03 04
COMMON EQUITY
PREFERRED AND PREFERENCE
STOCK
LONG-TERM DEBT
SHORT-TERM DEBT
$35.1 million in cash dividends
were paid to common share-
holders in 2004; $40 million
in new common equity was
issued; no long-term debt was
issued or retired.
56 N W N AT U R A L
Thousands of dollars (December 31)
2004
2003
2002
2001
2000
1999
1998
1997
1996
1995
1994
Assets:
Plant and property:
Utility plant
Utility plant – net
Non-utility property
Less accumulated depreciation**
Less accumulated depreciation and depletion
Non-utility property – net
Total plant and property
Other investments
Current assets:
Cash and cash equivalents
Accounts receivable – net
Accrued unbilled revenue
Inventories of gas, materials and supplies
Investment in discontinued segment
Property held for sale
Prepayments and other current assets
Unrealized loss on non-trading derivatives
Total current assets
Regulatory tax assets
Deferred gas costs receivable
Deferred debits and other
Total assets
Capitalization and liabilities:
Capitalization:
Common stock equity
Redeemable preference stock
Redeemable preferred stock
Total capital stock
First mortgage bonds
Unsecured debt
Total long-term debt
Total capitalization
Minority interest
Current liabilities:
Notes payable
Accounts payable
Taxes accrued
Interest accrued
Long-term debt due within one year
Other current and accrued liabilities
Total current liabilities
Deferred investment tax credits
Deferred income taxes
Fair value of non-trading derivatives
Deferred gas costs payable
Accrued asset removal costs**
Other
Total capitalization and liabilities
$ 1,794,972
505,286
__________
1,289,686
__________
33,963
__________
5,244
__________
28,719
1,318,405
__________
__________
60,618
$ 1,657,589
471,716
__________
1,185,873
__________
23,395
__________
4,855
__________
18,540
1,204,413
__________
__________
73,845
5,248
60,675
64,401
66,477
–
–
4,706
48,499
59,109
50,859
–
–
__________
40,316
237,117
__________
__________
64,734
__________
9,551
__________
–
__________
41,770
$ 1,732,195
__________
__________
__________
32,661
195,834
__________
__________
63,449
__________
–
__________
–
__________
47,838
$ 1,585,379
__________
__________
$ 568,517
$ 506,316
–
__________
–
568,517
__________
479,500
__________
4,527
484,027
__________
1,052,544
__________
__________
–
102,500
102,478
15,000
10,242
2,897
__________
34,168
267,285
__________
__________
6,025
210,715
__________
__________
5,487
__________
–
153,258
__________
__________
36,881
$ 1,732,195
__________
__________
–
__________
–
506,316
__________
494,500
__________
5,819
500,319
__________
1,006,635
__________
__________
–
85,200
86,029
–
8,605
2,998
__________
31,589
214,421
__________
__________
6,945
171,797
__________
__________
–
__________
5,627
135,638
__________
__________
44,316
$ 1,585,379
__________
__________
*Deferred gas costs were included in deferred debits or regulatory accounts prior to 1995.
**Removal costs were reclassified from accumulated depreciation to regulatory liabilities and accrued
asset removal costs.
$ 1,539,965
435,601
__________
1,104,364
__________
20,832
4,404
__________
16,428
__________
1,120,792
__________
67,619
__________
7,328
46,936
44,069
58,030
–
–
36,934
__________
193,297
__________
47,975
__________
–
__________
–
__________
37,594
__________
$ 1,467,277
__________
__________
$ 482,392
–
8,250
__________
490,642
__________
439,500
6,445
__________
445,945
__________
936,587
__________
–
__________
69,802
74,436
20,000
7,822
2,902
30,045
__________
205,007
__________
7,824
__________
141,732
__________
–
__________
10,635
__________
125,197
__________
40,295
__________
$ 1,467,277
__________
__________
$ 1,465,079
398,668
__________
1,066,411
__________
18,203
4,007
__________
14,196
__________
1,080,607
__________
76,266
__________
10,440
64,722
57,749
49,337
–
–
28,086
__________
210,334
__________
48,469
__________
–
__________
111,641
__________
23,336
__________
$ 1,550,653
__________
__________
$ 468,161
25,000
9,000
__________
502,161
__________
370,000
8,377
__________
378,377
__________
880,538
__________
–
__________
108,291
70,698
40,000
22,539
3,658
28,396
__________
273,582
__________
8,682
__________
130,424
__________
111,868
__________
10,089
__________
115,631
__________
19,839
__________
$ 1,550,653
__________
__________
$ 1,406,970
371,437
__________
1,035,533
__________
8,649
3,451
__________
5,198
__________
1,040,731
__________
63,638
__________
11,283
60,753
45,619
46,883
–
–
22,834
__________
187,372
__________
49,515
__________
16,973
__________
–
__________
27,185
__________
$ 1,385,414
__________
__________
$ 452,309
25,000
9,750
__________
487,059
__________
382,000
18,790
__________
400,790
__________
887,849
__________
–
__________
56,263
110,698
20,000
8,066
2,696
23,638
__________
221,361
__________
9,538
__________
141,656
__________
–
__________
–
__________
106,701
__________
18,309
__________
$ 1,385,414
__________
__________
$ 1,331,415
337,995
__________
993,420
__________
8,548
7,654
__________
894
__________
994,314
__________
61,289
__________
10,013
43,349
31,550
33,919
29,163
16,712
18,349
__________
183,055
__________
51,060
__________
20,950
__________
–
__________
32,146
__________
$ 1,342,814
__________
__________
$ 429,596
25,000
10,564
__________
465,160
__________
377,000
19,379
__________
396,379
__________
861,539
__________
–
__________
94,149
68,163
10,000
4,101
4,673
39,153
__________
220,239
__________
10,393
__________
136,150
__________
–
__________
–
__________
98,391
__________
16,102
__________
$ 1,342,814
__________
__________
$ 1,239,690
313,149
__________
926,541
__________
89,050
29,927
__________
59,123
__________
985,664
__________
53,370
__________
7,383
47,476
34,258
21,258
–
–
16,105
__________
126,480
__________
56,860
__________
27,795
__________
–
__________
32,535
__________
$ 1,282,704
__________
__________
$ 412,404
25,000
11,499
__________
448,903
__________
347,000
19,738
__________
366,738
__________
815,641
__________
16,322
__________
87,264
56,039
10,000
7,486
6,204
23,477
__________
190,470
__________
11,248
__________
140,310
__________
–
__________
–
__________
90,968
__________
17,745
__________
$ 1,282,704
__________
__________
$ 1,164,499
283,495
__________
881,004
__________
52,422
22,843
__________
29,579
__________
910,583
__________
67,625
__________
6,731
39,420
23,911
17,385
–
–
17,226
__________
104,673
__________
56,860
__________
28,628
__________
–
__________
26,360
__________
$ 1,194,729
__________
__________
$ 366,265
25,000
12,429
__________
403,694
__________
324,000
20,303
__________
344,303
__________
747,997
__________
–
__________
89,317
58,775
16,000
4,656
6,058
21,390
__________
196,196
__________
11,949
__________
139,953
__________
–
__________
–
__________
83,112
__________
15,522
__________
$ 1,194,729
__________
__________
$ 1,055,112
260,089
__________
795,023
__________
45,689
19,388
__________
26,301
__________
821,324
__________
63,548
__________
8,219
40,833
22,340
14,439
–
–
12,483
__________
98,314
__________
57,940
__________
–
__________
–
__________
23,795
__________
$ 1,064,921
__________
__________
$ 346,778
25,000
13,749
__________
385,527
__________
236,000
35,838
__________
271,838
__________
657,365
__________
–
__________
50,058
64,795
26,000
3,196
5,396
19,418
__________
168,863
__________
11,668
__________
123,625
__________
–
__________
8,058
__________
76,052
__________
19,290
__________
$ 1,064,921
__________
__________
$ 969,075
239,493
__________
729,582
__________
53,807
16,997
__________
36,810
__________
766,392
__________
62,743
__________
7,782
34,385
21,493
14,254
–
–
12,396
__________
90,310
__________
60,430
__________
–
__________
–
__________
18,611
__________
$ 998,486
__________
__________
$ 323,552
25,000
14,840
__________
363,392
__________
238,000
41,945
__________
279,945
__________
643,337
__________
–
__________
28,832
41,784
21,000
10,281
4,617
13,204
__________
119,718
__________
12,493
__________
118,692
__________
–
__________
19,914
__________
69,209
__________
15,123
__________
$ 998,486
__________
__________
$ 908,238
216,711
__________
691,527
__________
49,586
24,456
__________
25,130
__________
716,657
__________
61,420
__________
8,068
42,152
20,320
14,958
–
–
10,041
__________
95,539
__________
60,430
__________
*
__________
–
__________
17,659
__________
$ 951,705
__________
__________
$ 274,408
26,252
15,950
__________
316,610
__________
234,000
57,076
__________
291,076
__________
607,686
__________
–
__________
53,654
48,517
1,000
6,584
4,570
11,757
__________
126,082
__________
13,530
__________
112,433
__________
–
__________
*
__________
62,401
__________
29,573
__________
$ 951,705
__________
__________
N W N AT U R A L
57
Comparative Financial Statistics
YEAR-END MARKET PRICE
& BOOK VALUE PER SHARE
IN DOLLARS
$35
$30
$25
$20
$15
$10
$5
94 95 96 97 98 99 00 01 02
03 04
BOOK VALUE PER SHARE
EXCESS OF MARKET PRICE OVER
BOOK VALUE PER SHARE
The 2004 year-end market-to-book
ratio was 1.63x, and the average
was 1.53x over the past 10 years.
Total return to shareholders
(dividends paid plus market
appreciation) was 10.9 percent
over the 10-year period.
HIGH/LOW MARKET
PRICE PER SHARE
(IN DOLLARS)
$35
$30
$25
$20
$15
$10
94
95
96 97 98 99 00 01
02 03 04
HIGH
LOW
YEAR-END
2004
2003
2002
2001
2000
1999
1998
1997
1996
1995
1994
Common stock
Ratios – year-end:
Price/earnings ratio
Dividend yield at year-end rate – %
Dividend payout – %
Return on average common equity – %
Per share data – ($):
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
Coverage data – times earned
Fixed charges – Securities and
Exchange Commission
Fixed charges – Standard & Poor’s
Utility plant
Capital expenditures (000) $
Depreciation – % of avg depreciable utility plant
Accumulated depreciation –
% of depreciable utility plant
Capital structure – year-end (%)
(Exclusive of current portion of long-term debt)
First mortgage bonds
Unsecured debt
Total long-term debt
Redeemable preferred stock
Redeemable preference stock
Common stock equity
Total capital stock
Total capital structure
18.0
3.9
69.5
9.4
1.87
1.86
1.30
1.30
20.64
34.13
27.46
33.74
31.061
27,547
27,016
17.3
4.1
71.8
9.3
1.77
1.76
1.27
1.30
19.52
31.30
24.05
30.75
27.724
25,938
25,741
3.02
3.07
2.84
2.89
$ 141,485
3.4
$ 124,660
3.5
37.2
38.0
45.6
0.4
______
46.0
______
–
–
54.0
______
54.0
______
100.0
______
______
49.0
0.7
______
49.7
______
–
–
50.3
______
50.3
______
100.0
______
______
16.6*
4.7
77.3*
8.7*
1.63*
1.62*
1.26
1.26
18.85*
30.70
23.46
27.06
27.577
25,586
25,431
2.85*
3.29
3.5
37.3
46.9
______
0.7
______
47.6
0.9
–
______
51.5
______
52.4
100.0
______
______
13.4
4.9
65.5
10.4
1.90
1.88
1.245
1.26
18.56
26.69
21.65
25.50
23.666
25,228
25,159
3.14
3.30
3.5
35.8
42.0
______
1.0
______
43.0
1.0
2.8
______
53.2
______
57.0
100.0
______
______
13.9
4.7
65.3
10.8
1.90
1.88
1.24
1.24
17.93
27.50
17.75
26.50
22.147
25,233
25,183
3.14
3.16
3.5
34.9
44.1
______
1.0
______
45.1
1.1
2.8
______
51.0
______
54.9
100.0
______
______
12.9
5.6
71.6
10.2
1.71
1.70
1.225
1.24
17.12
27.88
19.50
21.94
24.629
25,092
24,976
3.12
3.19
4.0
33.4
43.6
______
2.3
______
45.9
1.2
2.9
______
50.0
______
54.1
100.0
______
______
25.4*
4.7
119.6*
6.4*
1.02*
1.02*
1.22
1.22
16.59*
30.75
24.25
25.88
27.248
24,853
24,233
2.20*
2.72
3.9
33.2
42.6
______
2.4
______
45.0
1.4
3.1
______
50.5
______
55.0
100.0
______
______
17.4
3.9
67.7
11.3
1.78
1.76
1.205
1.22
16.02
31.25
23.125
31.00
25.292
22,864
22,698
2.99
3.05
3.8
32.6
43.3
______
2.7
______
46.0
1.7
3.3
______
49.0
______
54.0
100.0
______
______
12.2
5.0
60.9
13.0
1.97
1.94
1.20
1.20
15.37
25.75
20.833
24.00
23.054
22,555
22,391
3.53
3.71
3.8
33.2
35.9
______
5.5
______
41.4
2.1
3.8
______
52.7
______
58.6
100.0
______
______
13.6
5.5
73.1
11.8
1.62
1.60
1.18
1.20
14.55
22.67
18.667
22.00
20.750
22,243
21,817
3.15
2.87
4.2
32.8
37.0
______
6.5
______
43.5
2.3
3.9
______
50.3
______
56.5
100.0
______
______
12.1
6.0
72.1
12.2
1.63
1.61
1.173
1.173
13.63
24.33
19.00
19.67
21.250
20,129
19,943
3.08
2.98
4.1
31.7
38.5
______
9.4
______
47.9
2.6
4.3
______
45.2
______
52.1
100.0
______
______
$
79,530
$
71,943
$
80,444
$ 109,144
$
80,022
$ 115,886
$
83,400
$
67,163
$
77,668
Price per share at year-end
increased 72 percent in 10 years.
Effective tax rate
Effective tax rate – % of pretax income
34%
______
34%
______
______
35%
______
35%
______
36%
______
35%
______
35%
______
33%
______
37%
______
37%
______
37%
*Includes losses of $0.50 per share in 1998 due to asset write-downs for Financial Corporation and
Canor, and a loss of $0.33 per share in 2002 for PGE acquisition costs.
58 N W N AT U R A L
2004
2003
2002
2001
2000
1999
1998
1997
1996
1995
1994
16.6*
4.7
77.3*
8.7*
1.63*
1.62*
1.26
1.26
18.85*
30.70
23.46
27.06
27.577
25,586
25,431
13.4
4.9
65.5
10.4
1.90
1.88
1.245
1.26
18.56
26.69
21.65
25.50
23.666
25,228
25,159
13.9
4.7
65.3
10.8
1.90
1.88
1.24
1.24
17.93
27.50
17.75
26.50
22.147
25,233
25,183
12.9
5.6
71.6
10.2
1.71
1.70
1.225
1.24
17.12
27.88
19.50
21.94
24.629
25,092
24,976
25.4*
4.7
119.6*
6.4*
1.02*
1.02*
1.22
1.22
16.59*
30.75
24.25
25.88
27.248
24,853
24,233
17.4
3.9
67.7
11.3
1.78
1.76
1.205
1.22
16.02
31.25
23.125
31.00
25.292
22,864
22,698
12.2
5.0
60.9
13.0
1.97
1.94
1.20
1.20
15.37
25.75
20.833
24.00
23.054
22,555
22,391
13.6
5.5
73.1
11.8
1.62
1.60
1.18
1.20
14.55
22.67
18.667
22.00
20.750
22,243
21,817
12.1
6.0
72.1
12.2
1.63
1.61
1.173
1.173
13.63
24.33
19.00
19.67
21.250
20,129
19,943
2.85*
3.29
3.14
3.30
3.14
3.16
3.12
3.19
2.20*
2.72
2.99
3.05
3.53
3.71
3.15
2.87
3.08
2.98
$ 141,485
$ 124,660
$
79,530
3.5
$
71,943
3.5
$
80,444
3.5
$ 109,144
4.0
$
80,022
3.9
$ 115,886
3.8
$
83,400
3.8
$
67,163
4.2
$
77,668
4.1
37.3
35.8
34.9
33.4
33.2
32.6
33.2
32.8
31.7
46.9
0.7
______
47.6
______
0.9
–
51.5
______
52.4
______
100.0
______
______
42.0
1.0
______
43.0
______
1.0
2.8
53.2
______
57.0
______
100.0
______
______
44.1
1.0
______
45.1
______
1.1
2.8
51.0
______
54.9
______
100.0
______
______
43.6
2.3
______
45.9
______
1.2
2.9
50.0
______
54.1
______
100.0
______
______
42.6
2.4
______
45.0
______
1.4
3.1
50.5
______
55.0
______
100.0
______
______
43.3
2.7
______
46.0
______
1.7
3.3
49.0
______
54.0
______
100.0
______
______
35.9
5.5
______
41.4
______
2.1
3.8
52.7
______
58.6
______
100.0
______
______
37.0
6.5
______
43.5
______
2.3
3.9
50.3
______
56.5
______
100.0
______
______
38.5
9.4
______
47.9
______
2.6
4.3
45.2
______
52.1
______
100.0
______
______
Effective tax rate – % of pretax income
______
34%
______
34%
35%
______
35%
______
36%
______
35%
______
35%
______
33%
______
37%
______
37%
______
37%
______
Number of shares of common stock outstanding (000):
Common stock
Ratios – 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
Year-end
Average
Coverage data – times earned
Fixed charges – Securities and
Exchange Commission
Fixed charges – Standard & Poor’s
Utility plant
Capital expenditures (000) $
Depreciation – % of avg depreciable utility plant
Accumulated depreciation –
% of depreciable utility plant
Capital structure – year-end (%)
(Exclusive of current portion of long-term debt)
First mortgage bonds
Unsecured debt
Total long-term debt
Redeemable preferred stock
Redeemable preference stock
Common stock equity
Total capital stock
Total capital structure
Effective tax rate
18.0
3.9
69.5
9.4
1.87
1.86
1.30
1.30
20.64
34.13
27.46
33.74
31.061
27,547
27,016
3.02
3.07
3.4
37.2
45.6
______
0.4
______
46.0
–
–
______
54.0
______
54.0
100.0
______
______
17.3
4.1
71.8
9.3
1.77
1.76
1.27
1.30
19.52
31.30
24.05
30.75
27.724
25,938
25,741
2.84
2.89
3.5
38.0
49.0
______
0.7
______
49.7
–
–
______
50.3
______
50.3
100.0
______
______
*Includes losses of $0.50 per share in 1998 due to asset write-downs for Financial Corporation and
Canor, and a loss of $0.33 per share in 2002 for PGE acquisition costs.
N W N AT U R A L
59
Comparative Operating Statistics
COST OF PURCHASED GAS
IN CENTS PER THERM
$0.60
$0.50
$0.40
$0.30
$0.20
$0.10
94 95 96 97 98 99 00 01 02
03 04
Cost of gas, including demand
charges, increased 20 percent in
2004 and was 141 percent higher
than 10 years ago.
HEAT REQUIREMENTS
IN HEATING DEGREE-DAYS
4,700
4,500
4,300
4,100
3,900
3,700
3,500
94 95 96 97 98 99 00 01 02 03 04
DEGREE-DAYS
25-YEAR AVERAGE DEGREE-DAYS
Weather conditions in NW Natural’s
service area have been warmer than
the rolling 25-year average in seven
of the past 10 years.
Selected Utility Data
Customers at year-end
Residential
Commercial
Industrial firm
Industrial interruptible
Total sales customers
Transportation customers
Total customers
Gas sales and transportation deliveries (000 therms)
Residential
Commercial
Industrial firm
Industrial interruptible
Total gas sales
Transportation
Unbilled therms
Total volumes delivered
Operating revenues and cost of sales (000)*
Sales revenues:
Residential
Commercial
Industrial firm
Industrial interruptible
Total gas sales revenues
Transportation
Unbilled revenues
Other
Total utility operating revenues
Cost of gas
Net utility operating revenues
Non-utility net operating revenues
Net operating revenues
Customer data
Heat requirements:
Actual degree days
25-year average degree days
Average use per customer in therms:
Residential
Commercial
Average rate per therm (cents):
Residential
Commercial
Industrial firm
Industrial interruptible
Total sales
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)
Payroll (000)
Operating
Construction and other
Total
Utility employees
Number of customers served by each operating employee
2004
2003
2002
2001
2000
1999
1998
1997
1996
1995
1994
537,152
58,548
658
193
__________
596,551
84
__________
596,635
__________
__________
519,427
57,969
478
165
__________
578,039
111
__________
578,150
__________
__________
356,199
226,490
63,149
104,278
__________
750,116
389,514
(7,764)
__________
1,131,866
__________
__________
343,534
226,257
55,314
47,994
__________
673,099
414,554
12,099
__________
1,099,752
__________
__________
$ 381,526
199,725
44,625
55,380
__________
681,256
12,655
3,849
3,185
__________
700,945
399,176
__________
301,769
6,591
__________
$ 308,360
__________
__________
$ 328,464
176,385
33,578
23,661
__________
562,088
17,962
14,474
7,460
__________
601,984
323,128
__________
278,856
9,210
__________
$ 288,066
__________
__________
3,853
4,202
677
3,907
107.1
88.2
70.7
53.1
90.8
3,952
4,236
673
4,004
95.6
78.0
60.7
49.3
83.5
756,672
56.60
53.77
7,177
8,913
683,331
46.99
47.16
4,851
6,310
47,837
$
27,309
__________
75,146
$
__________
__________
1,288
721
43,993
$
27,450
__________
71,443
$
__________
__________
1,291
724
503,402
485,207
468,087
447,659
425,606
407,061
385,213
363,903
346,950
56,087
306
55,096
383
54,684
384
52,870
388
51,159
411
50,315
403
47,309
407
45,402
410
44,078
401
__________
31
__________
148
__________
126
__________
115
__________
108
__________
122
__________
119
__________
143
__________
142
559,826
__________
241
560,067
__________
__________
540,834
__________
97
540,931
__________
__________
523,281
__________
125
523,406
__________
__________
501,032
__________
131
501,163
__________
__________
477,284
__________
123
477,407
__________
__________
457,901
__________
120
458,021
__________
__________
433,048
__________
121
433,169
__________
__________
409,858
__________
91
409,949
__________
__________
391,571
__________
67
391,638
__________
__________
357,091
240,155
63,215
350,065
242,293
79,778
356,375
250,380
76,559
352,969
252,382
84,630
315,686
229,124
87,275
306,356
225,249
84,523
306,310
225,115
91,122
256,462
196,723
82,958
260,218
201,925
81,348
__________
26,241
__________
63,597
__________
56,632
__________
52,938
__________
51,521
__________
53,929
__________
63,261
__________
84,173
__________
89,899
686,702
445,999
735,733
385,783
__________
(6,617)
__________
1,771
1,126,084
__________
__________
1,123,287
__________
__________
739,946
431,136
__________
8,691
1,179,773
__________
__________
742,919
480,570
683,606
446,165
__________
(9,343)
__________
8,645
1,214,146
__________
__________
1,138,416
__________
__________
670,057
440,452
__________
3,615
1,114,124
__________
__________
685,808
410,062
__________
3,759
1,099,629
__________
__________
620,316
379,116
__________
4,946
1,004,378
__________
__________
633,390
364,461
__________
(7,519)
990,332
__________
__________
$ 354,735
$ 329,905
$ 280,642
$ 242,952
$ 205,388
$ 177,835
$ 183,802
$ 165,662
$ 176,510
201,475
190,236
159,660
139,425
117,889
100,677
104,582
42,965
49,662
37,378
35,857
34,303
27,025
30,672
99,079
31,268
108,452
34,443
__________
15,937
__________
34,283
__________
23,483
__________
17,182
__________
15,337
__________
13,944
__________
17,097
__________
24,113
__________
27,361
615,112
604,086
501,163
435,416
372,917
319,481
336,153
320,122
346,766
26,020
(12,702)
20,637
13,774
21,491
12,661
21,351
(2,671)
19,958
8,314
22,029
1,647
22,533
1,627
16,650
1,173
14,702
(5,571)
__________
4,018
__________
(2,325)
__________
(3,976)
__________
1,194
__________
2,617
__________
7,884
__________
9,824
__________
9,411
__________
429
632,448
636,172
531,339
455,290
403,806
351,041
370,137
347,356
356,326
353,034
__________
364,699
__________
273,978
__________
212,021
__________
173,242
__________
130,381
__________
141,789
__________
142,025
__________
162,437
__________
279,414
__________
8,130
$ 287,544
__________
__________
271,473
__________
4,538
$ 276,011
__________
__________
257,361
__________
589
$ 257,950
__________
__________
243,269
__________
368
$ 243,637
__________
__________
230,564
__________
402
$ 230,966
__________
__________
220,660
__________
450
$
__________
__________
221,110
228,348
__________
636
$ 228,984
__________
__________
205,331
__________
8,271
$ 213,602
__________
__________
193,889
__________
11,773
$ 205,662
__________
__________
4,232
4,255
725
4,334
99.3
83.9
68.0
61.7
89.6
51.07
51.91
4,249
6,172
4,325
4,265
738
4,435
94.2
78.5
62.2
54.0
82.1
47.19
49.45
4,247
5,996
4,416
4,273
781
4,670
78.7
63.8
48.8
41.5
67.7
37.68
36.60
4,691
5,814
4,256
4,273
810
4,851
68.8
55.2
42.4
32.5
58.6
27.85
28.90
4,144
6,211
4,011
4,282
749
4,540
65.1
51.5
39.3
29.6
54.6
25.09
25.03
6,414
7,446
4,092
4,297
777
4,670
58.0
44.7
32.0
25.9
47.7
24.05
19.35
4,447
5,744
4,427
4,311
823
4,874
60.0
46.5
33.7
27.0
49.0
22.25
20.56
5,997
7,422
3,779
4,338
726
4,420
64.6
50.4
37.7
28.6
51.6
20.67
22.71
4,375
5,717
4,020
4,364
776
4,680
67.8
53.7
42.3
30.4
54.7
23.44
25.95
3,920
5,291
708,796
739,620
745,582
773,258
712,602
702,820
692,894
640,976
642,607
$
42,268
$
40,856
$
38,979
$
38,066
$
37,573
$
35,669
$
34,037
$
33,669
$
33,888
__________
26,044
$
__________
__________
68,312
__________
25,626
$
__________
__________
66,482
__________
24,756
$
__________
__________
63,735
__________
24,322
$
__________
__________
62,388
__________
24,625
$
__________
__________
62,198
__________
24,630
$
__________
__________
60,299
__________
22,920
$
__________
__________
56,957
__________
22,074
$
__________
__________
55,743
__________
20,795
$
__________
__________
54,683
1,261
714
1,284
671
1,315
646
1,275
643
1,303
611
1,337
583
1,304
560
1,288
533
1,338
478
*Interest on deferred regulatory accounts for years prior to 1998 was reclassified from gross operating
revenues or cost of sales to other income (expense).
60 N W N AT U R A L
Gas sales and transportation deliveries (000 therms)
Selected Utility Data
Customers at year-end
Residential
Commercial
Industrial firm
Industrial interruptible
Total sales customers
Transportation customers
Total customers
Residential
Commercial
Industrial firm
Industrial interruptible
Total gas sales
Transportation
Unbilled therms
Total volumes delivered
Sales revenues:
Residential
Commercial
Industrial firm
Industrial interruptible
Total gas sales revenues
Transportation
Unbilled revenues
Other
Operating revenues and cost of sales (000)*
Total utility operating revenues
Cost of gas
Net utility operating revenues
Non-utility net operating revenues
Net operating revenues
Customer data
Heat requirements:
Actual degree days
25-year average degree days
Average use per customer in therms:
Average rate per therm (cents):
Residential
Commercial
Residential
Commercial
Industrial firm
Industrial interruptible
Total sales
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)
Payroll (000)
Operating
Construction and other
Total
Utility employees
537,152
519,427
58,548
658
57,969
478
__________
193
__________
165
596,551
__________
84
596,635
__________
__________
578,039
__________
111
578,150
__________
__________
356,199
226,490
63,149
343,534
226,257
55,314
104,278
__________
__________
47,994
750,116
389,514
673,099
414,554
__________
(7,764)
__________
12,099
1,131,866
__________
__________
1,099,752
__________
__________
$ 381,526
$ 328,464
199,725
176,385
44,625
33,578
__________
55,380
__________
23,661
681,256
562,088
12,655
3,849
17,962
14,474
__________
3,185
__________
7,460
700,945
601,984
399,176
__________
323,128
__________
301,769
__________
6,591
$ 308,360
__________
__________
278,856
__________
9,210
$ 288,066
__________
__________
3,853
4,202
677
3,907
107.1
88.2
70.7
53.1
90.8
56.60
53.77
7,177
8,913
3,952
4,236
673
4,004
95.6
78.0
60.7
49.3
83.5
46.99
47.16
4,851
6,310
756,672
683,331
2004
2003
2002
2001
2000
1999
1998
1997
1996
1995
1994
503,402
56,087
306
31
__________
559,826
241
__________
560,067
__________
__________
485,207
55,096
383
148
__________
540,834
97
__________
540,931
__________
__________
468,087
54,684
384
126
__________
523,281
125
__________
523,406
__________
__________
447,659
52,870
388
115
__________
501,032
131
__________
501,163
__________
__________
425,606
51,159
411
108
__________
477,284
123
__________
477,407
__________
__________
407,061
50,315
403
122
__________
457,901
120
__________
458,021
__________
__________
385,213
47,309
407
119
__________
433,048
121
__________
433,169
__________
__________
363,903
45,402
410
143
__________
409,858
91
__________
409,949
__________
__________
346,950
44,078
401
142
__________
391,571
67
__________
391,638
__________
__________
357,091
240,155
63,215
26,241
__________
686,702
445,999
(6,617)
__________
1,126,084
__________
__________
350,065
242,293
79,778
63,597
__________
735,733
385,783
1,771
__________
1,123,287
__________
__________
356,375
250,380
76,559
56,632
__________
739,946
431,136
8,691
__________
1,179,773
__________
__________
352,969
252,382
84,630
52,938
__________
742,919
480,570
(9,343)
__________
1,214,146
__________
__________
315,686
229,124
87,275
51,521
__________
683,606
446,165
8,645
__________
1,138,416
__________
__________
306,356
225,249
84,523
53,929
__________
670,057
440,452
3,615
__________
1,114,124
__________
__________
306,310
225,115
91,122
63,261
__________
685,808
410,062
3,759
__________
1,099,629
__________
__________
256,462
196,723
82,958
84,173
__________
620,316
379,116
4,946
__________
1,004,378
__________
__________
260,218
201,925
81,348
89,899
__________
633,390
364,461
(7,519)
__________
990,332
__________
__________
$ 354,735
201,475
42,965
15,937
__________
615,112
26,020
(12,702)
4,018
__________
632,448
353,034
__________
279,414
8,130
__________
$ 287,544
__________
__________
$ 329,905
190,236
49,662
34,283
__________
604,086
20,637
13,774
(2,325)
__________
636,172
364,699
__________
271,473
4,538
__________
$ 276,011
__________
__________
$ 280,642
159,660
37,378
23,483
__________
501,163
21,491
12,661
(3,976)
__________
531,339
273,978
__________
257,361
589
__________
$ 257,950
__________
__________
$ 242,952
139,425
35,857
17,182
__________
435,416
21,351
(2,671)
1,194
__________
455,290
212,021
__________
243,269
368
__________
$ 243,637
__________
__________
$ 205,388
117,889
34,303
15,337
__________
372,917
19,958
8,314
2,617
__________
403,806
173,242
__________
230,564
402
__________
$ 230,966
__________
__________
$ 177,835
100,677
27,025
13,944
__________
319,481
22,029
1,647
7,884
__________
351,041
130,381
__________
220,660
450
__________
221,110
$
__________
__________
$ 183,802
104,582
30,672
17,097
__________
336,153
22,533
1,627
9,824
__________
370,137
141,789
__________
228,348
636
__________
$ 228,984
__________
__________
$ 165,662
99,079
31,268
24,113
__________
320,122
16,650
1,173
9,411
__________
347,356
142,025
__________
205,331
8,271
__________
$ 213,602
__________
__________
$ 176,510
108,452
34,443
27,361
__________
346,766
14,702
(5,571)
429
__________
356,326
162,437
__________
193,889
11,773
__________
$ 205,662
__________
__________
4,232
4,255
725
4,334
99.3
83.9
68.0
61.7
89.6
4,325
4,265
738
4,435
94.2
78.5
62.2
54.0
82.1
4,416
4,273
781
4,670
78.7
63.8
48.8
41.5
67.7
4,256
4,273
810
4,851
68.8
55.2
42.4
32.5
58.6
4,011
4,282
749
4,540
65.1
51.5
39.3
29.6
54.6
4,092
4,297
777
4,670
58.0
44.7
32.0
25.9
47.7
4,427
4,311
823
4,874
60.0
46.5
33.7
27.0
49.0
3,779
4,338
726
4,420
64.6
50.4
37.7
28.6
51.6
4,020
4,364
776
4,680
67.8
53.7
42.3
30.4
54.7
708,796
51.07
51.91
4,249
6,172
739,620
47.19
49.45
4,247
5,996
745,582
37.68
36.60
4,691
5,814
773,258
27.85
28.90
4,144
6,211
712,602
25.09
25.03
6,414
7,446
702,820
24.05
19.35
4,447
5,744
692,894
22.25
20.56
5,997
7,422
640,976
20.67
22.71
4,375
5,717
642,607
23.44
25.95
3,920
5,291
Number of customers served by each operating employee
*Interest on deferred regulatory accounts for years prior to 1998 was reclassified from gross operating
revenues or cost of sales to other income (expense).
$
47,837
$
43,993
__________
27,309
$
__________
__________
75,146
__________
27,450
$
__________
__________
71,443
1,288
721
1,291
724
42,268
$
26,044
__________
68,312
$
__________
__________
1,261
714
40,856
$
25,626
__________
66,482
$
__________
__________
1,284
671
38,979
$
24,756
__________
63,735
$
__________
__________
1,315
646
38,066
$
24,322
__________
62,388
$
__________
__________
1,275
643
37,573
$
24,625
__________
62,198
$
__________
__________
1,303
611
35,669
$
24,630
__________
60,299
$
__________
__________
1,337
583
34,037
$
22,920
__________
56,957
$
__________
__________
1,304
560
33,669
$
22,074
__________
55,743
$
__________
__________
1,288
533
33,888
$
20,795
__________
54,683
$
__________
__________
1,338
478
N W N AT U R A L
61
Board of Directors
Timothy Boyle
Timothy P. Boyle, 55, is President and
Chief Executive Officer of Columbia
Sportswear Company located in
Portland, Oregon. He was elected to
the NW Natural Board of Directors
in 2003, and serves on the Finance
Committee, Strategic Planning
Committee, and Organization and
Executive Compensation Committee.
Martha (Stormy) Byorum
Ms. Byorum, 56, is Senior Managing
Director, Stephens Cori Capital Advisors,
a private equity advisory and investment
banking firm located in New York
City. She was elected to the Board in
2004 and serves as a member of the
Finance Committee.
John Carter
A member of the NW Natural Board
since 2002, John D. Carter, 59, chairs
the Board’s Governance Committee.
He is also a member of the Audit and
Finance Committees. Mr. Carter is a
principal with Imeson & Carter, a
strategic planning and public affairs
consulting firm in Portland, Oregon.
Mark Dodson
NW Natural’s President and Chief
Executive Officer is Mark S. Dodson, 60.
Previously he served as NW Natural’s
General Counsel and Senior Vice
President, Public Affairs. He has
served on the Board since 2003.
Scott Gibson
C. Scott Gibson, 52, is President of
Gibson Enterprises, a company that
manages private investments in
Portland, Oregon. Mr. Gibson joined
the NW Natural Board in 2002. He
is Chair of the Public Affairs and
Environmental Policy Committee and
a member of the Strategic Planning
Committee and the Organization and
Executive Compensation Committee.
Tod Hamachek
Chair of the Strategic Planning
Committee, Tod R. Hamachek, 59, has
served on the NW Natural Board since
1986. Mr. Hamachek is also a member
of the Board’s Audit and Governance
Committees. Until February 2005, he
served as Chairman and Chief Executive
Officer of Penwest Pharmaceuticals
Company, a firm that develops pharma-
ceutical drug delivery products and tech-
nologies in Danbury, Connecticut.
Randall Papé
A member of the Board since 1996,
Randall C. Papé, 54, chairs the Finance
Committee. Mr. Papé is President and
Chief Executive Officer of The Papé
Group, Inc., headquartered in Eugene,
Oregon, which specializes in the sales
and service of capital equipment. He
serves on the Board’s Governance
Committee and its Public Affairs and
Environmental Policy Committee.
Richard Reiten
Retired Chairman of the Board, Richard
G. Reiten, 65, has been a member of
the Board since 1996. Mr. Reiten was
President and Chief Executive Officer of
NW Natural. He also served as President
and Chief Operating Officer of Portland
General Electric from 1992-1995.
62
Richard Woolworth
Elected to the Board in 2000, Richard
L. Woolworth, 63, chairs the Audit
Committee, and was selected to serve
as Chair of the Board effective March 1,
2005. He also serves on the Governance
Committee and the Organization and
Executive Compensation Committee.
Mr. Woolworth is the Retired Chairman
and CEO of The Regence Group, a
regional affiliation of health plans in
Portland, Oregon.
Below: (left to right)
John Carter, Richard Reiten,
Scott Gibson, Richard Woolworth,
Russell Tromley, Tod Hamachek,
Randall Papé, Mark Dodson,
Stormy Byorum and Timothy Boyle.
Kenneth Thrasher, not pictured.
Mr. Reiten serves on the Finance
Committee, the Public Affairs and
Environmental Policy Committee and
the Strategic Planning Committee.
Kenneth Thrasher
Elected to the Board of Directors in
February 2005, Ken Thrasher, 55, is
Chairman and Chief Executive Officer of
Compli Corporation, a software solution
provider for corporate compliance man-
agement in employment practices and
governance. Mr. Thrasher served as an
executive for 19 years with Fred Meyer,
Inc., including President and Chief
Executive Officer from 1999-2001.
Russell Tromley
The Chair of the Organization and
Executive Compensation Committee is
Russell F. Tromley, 65. He has served
on the Board since 1994, and is a
member of the Audit and Governance
Committees. Mr. Tromley is President
and Chief Executive Officer of Tromley
Industrial Holdings, Inc., a company
in Tualatin, Oregon, that manufactures
foundry equipment and distributes non-
ferrous metals.
In Memoriam
Ronald Miller
1919-2004
President and CEO
1975-1984
Chairman of
the Board
1984-1988
Melody Teppola
1942-2004
Director
1987-2004
Corporate Officers
David H. Anderson, 43 [2004]
Senior Vice President and
Chief Financial Officer (2004- )
Senior Vice President and
Chief Financial Officer, TXU Gas (2004)
Corporate Controller & Principal
Accounting Officer, TXU Corp. (2003-2004)
Vice President, Investor Relations &
Shareholder Services, TXU Corp. (1997-2003)
Mark S. Dodson, 60 [1997]
President, Chief Executive Officer
(2003- )
President, Chief Operating Officer
(2001-2002)
General Counsel (1997-2002)
Senior Vice President, Public Affairs
(1997-2001)
Lea Anne Doolittle, 50 [2000]
Vice President, Human Resources
(2000- )
Director of Compensation, PacifiCorp
(1993-2000)
Stephen P. Feltz, 49 [1982]
Treasurer and Controller (1999- )
Assistant Treasurer and Manager,
General Accounting (1996-1999)
Gregg S. Kantor, 47 [1996]
Senior Vice President, Public and
Regulatory Affairs (2003- )
Vice President, Public Affairs and
Communications (1998-2002)
Richelle T. Luther, 36 [2002]
Assistant Secretary (2002- )
Associate, Stoel Rives LLP (1997-2002)
Michael S. McCoy, 61 [1969]
Executive Vice President, Customer
and Utility Operations (2000- )
Senior Vice President, Customer and
Utility Operations (1999-2000)
64
C. J. Rue, 59 [1974]
Secretary (1982- )
Assistant Treasurer (1987- )
[Date joined NW Natural]
Corporate Profile
NW Natural is a 146-year-old
natural gas local distribution company
headquartered in Portland, Oregon.
The Company has added customers
at a rate of 3 percent or more per year
for 18 consecutive years.
NW Natural serves about 600,000
customers in Oregon and southwest
Washington, including the Portland-
Vancouver metropolitan area, the
Willamette Valley, the northern Oregon
coast and the Columbia River Gorge.
More than 200,000 customers have
been added to NW Natural’s distribu-
tion system in the past 10 years.
In keeping with its steady growth,
the Company has increased annual
dividends paid to shareholders every
year for 49 consecutive years.
NW Natural purchases natural gas
for its core market from a variety of
suppliers in the western United States
and Canada. The Company also
operates an underground gas storage
facility in Columbia County, Oregon,
and contracts for additional gas storage
outside its service area. NW Natural
operates two liquefied natural gas
plants in its service area. The Company
also provides interstate storage services
to other energy companies in the
Northwest interstate market, using
capacity that has been developed in
advance of its core customers’ needs.
Service Territory
Earnings
Financial facts ($000):
Net operating revenues
Net income
Earnings aplicable to common stock
Financial ratios (%):
Return on average common equity
Capital structure at year-end
Long-term debt
Preferred and preference stock
Common stock equity
Common stock
Shareholder data:
Common shareholders
Average shares outstanding (000)
Per share data ($):
Basic earnings
Diluted earnings
Dividends paid on common stock
Book value at year-end
Market value at year-end
Operating highlights
Gas sales and transportation deliveries
(000 therms)
Degree days (25-year average, 4,202)
Customers at year-end
Number of utility employees
Dividends paid on common stock
Payment date (per share)
February 15
May 15
August 15
November 15
Total dividends paid
2004
2003
Percent
increase
(decrease)
7
10
11
1
(3)
5
6
6
2
6
10
3
(3)
3
–
308,360
50,572
50,572
288,066
45,983
45,689
9.4
46.0
–
54.0
9.3
49.7
–
50.3
9,359
27,016
9,695
25,741
1.87
1.86
1.30
20.64
33.74
1.77
1.76
1.27
19.52
30.75
1,131,866 1,099,752
3,952
578,150
1,291
3,853
596,635
1,288
2004
2003
$ 0.325 $ 0.315
$ 0.325 $ 0.315
$ 0.325 $ 0.315
$ 0.325 $ 0.325
________ ________
$ 1.300 $ 1.270
________ ________
________ ________
Astoria
Mist
WASHINGTON
Vancouver
Portland
Molalla
The Dalles
Salem
Lincoln
City
Newport
Albany
Eugene
Coos Bay
OREGON
Legend
Williams Gas Pipeline
NW Natural gas
transmission line
Kelso Beaver
(KB) Pipeline
Coos County Pipeline
Service territory
LNG plant
District offices
Mist underground
storage
$1.30
$1.29
$1.28
$1.27
$1.26
$1.25
$1.24
$1.23
$1.22
$1.21
$1.20
DIVIDENDS PAID
PER SHARE
IN DOLLARS
DILUTED EARNINGS
PER SHARE
IN DOLLARS
$2.00
$1.75
$1.50
$1.25
$1.00
$0.75
$0.50
$0.25
On the cover: A NW Natural truck strikes out
for new territory — the southern Oregon coast.
Coos County residents welcomed natural gas
service to their communities in 2004.
Annual dividends paid per share
in 2004 increased for the 49th
consecutive year, a growth record
matched by few companies.
Diluted earnings per share were
$1.86 per share in 2004, up 6
percent over 2003.
99
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Corporate Information
Notice of Annual Meeting
The 2005 Annual Meeting will be held at
2 p.m., Thursday, May 26, in the Colonel
Lindbergh Room of the Embassy Suites
Hotel, 319 S.W. Pine Street, Portland,
Oregon. A meeting notice and proxy
statement will be sent to all shareholders
in mid-April.
Stock Transfer Agent and Registrar
For the Common Stock:
American Stock Transfer & Trust Company
59 Maiden Lane
New York, New York 10038
Telephone: (888) 777-0321
Internet: www.amstock.com
E-mail: info@amstock.com
Trustee, Conversion and Interest
Paying Agent
For Convertible Debentures:
The Bank of New York
Corporate Debt Operations, Floor 7-E
101 Barclay Street
New York, New York 10286
(800) 548-5075
Trustee and Bond Paying Agent
For all bond issues:
DB Services Tennessee Inc.
Security Holder Relations
P.O. Box 305050
Nashville, Tennessee 37230
(800) 735-7777
Dividend Reinvestment Plan
Common shareholders of record may
reinvest all or part of their dividends in
additional shares under the Company’s
plan. Cash purchases also may be made at
the current market price under this plan,
and no brokerage fees will be charged. A
prospectus will be sent to any registered
shareholder on request.
Dividend Payment Dates
February 15, 2005
May 13, 2005
August 15, 2005
November 15, 2005
Common Stock Prices
The Company’s common stock is listed
and trades on the New York Stock
Exchange (NYSE) under the symbol NWN.
The quarterly high and low trading range
during 2003 and 2004 was:
2004
Quarter
1
2
3
4
High
$ 33.00
31.65
32.37
34.13
Low
$ 29.95
27.46
28.84
30.77
2003
Quarter
1
2
3
4
High
$ 28.47
28.88
30.11
31.30
Low
$ 24.05
24.77
27.02
28.51
Certifications
The Chief Executive Officer certified to the
NYSE on June 7, 2004 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 has
filed with the Securities and Exchange
Commission, as exhibits 31.1 and 31.2 to
its Annual Report on Form 10-K for the
year ended Dec. 31, 2004, the certificates
of the Chief Executive Officer and the
Chief Financial Officer of the Company
certifying the quality of the Company’s
public disclosure.
Request for Publications
The following publications may be
obtained without charge by contacting
the Corporate Secretary:
Annual Report
Form 10-K
Form 10-Q
Corporate Governance Standards
Director Independence Standards
Code of Ethics
Board Committee Charters
These publications, as well as other filings
made with the Securities and Exchange
Commission, also are available on NW
Natural’s web site at www.nwnatural.com.
Quarterly Financial Information (unaudited)
Dollars
(thousands except per share amounts)
March 31
———————— Quarter ended ————————
June 30
Sept. 30
Dec. 31
Total
2004
Operating revenues
Net operating revenues
Net income (loss)
Basic earnings (loss) per share
Diluted earnings (loss) per share
2003
Operating revenues
Net operating revenues
Net income (loss)
Basic earnings (loss) per share
Diluted earnings (loss) per share
$ 254,450 $ 106,659 $
112,034
32,612
1.26
1.24
52,629
(716)
(0.03)
(0.03)
81,441 $ 262,054 $ 704,604
308,360
39,483
50,572
(8,285)
1.87*
(0.30)
1.86*
(0.30)
104,214
26,961
0.98
0.97
$ 206,539 $ 117,489 $
98,588
26,404
1.03
1.01
58,549
4,462
0.17
0.17
69,481 $ 217,747 $ 611,256
288,066
91,464
39,465
45,983
21,663
(6,546)
1.77*
0.84
(0.25)
1.76*
0.83
(0.25)
*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
the Company’s business.
Shareholder Information
James R. Boehlke
Investor Relations
(503) 721-2451
(800) 422-4012,
Ext. 2451
jrb@nwnatural.com
Carol M. Frary
Shareholder Services
(503) 220-2590
(800) 422-4012,
Ext. 3412
cmf@nwnatural.com
220 N.W. Second Avenue
Portland, Oregon 97209
(503) 226-4211
(800) 422-4012
www.nwnatural.com
Contact the NW Natural Board
Concerns may be directed to the
non-management directors as follows:
■ Call 1-800-541-9967, or
■ Write to NW Natural Board of
Directors, c/o Corporate Secretary, or
■ Email Directors@nwnatural.com
Forward-looking Statements
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 Securities and Exchange
Commission on Forms 10-K and 10-Q.
220 NW Second Avenue
Portland, Oregon 97209
www.nwnatural.com
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2004 Annual Report
Ahead of
the curve