2010 ANNUAL R EP ORT
TODAY
and
It’s about
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CORPORATE PROFILE
FINANCIAL OVERVIEW
NW Natural (NYSE: NWN) is a 152-year-old
natural gas local distribution and storage
company headquartered in Portland, Oregon.
NW Natural serves about 674,000 customers
in Oregon and Southwest Washington. In
keeping with its steady growth, the company
has increased dividends paid to sharehold-
ers for 55 consecutive years. NW Natural
operates gas storage facilities and provides
gas storage services to companies on the
West Coast. In 2010, NW Natural completed
the Gill Ranch Storage facility near
Fresno, California.
SERVICE TERRITORY
AND STORAGE FACILITIES
EARNINGS
Financial facts ($000):
Gross operating revenues
Net operating revenues
Net income
Financial ratios (%):
Return on average common equity
Capital structure at year-end:
Long-term debt
Common stock equity
COMMON STOCK
Shareholder data (000):
Average shares outstanding
Year-end shares outstanding
Per share data ($):
Basic earnings
Diluted earnings
Dividends paid
Dividend rate at year-end
Book value at year-end
Market value at year-end
2010
2009
PERCENT
INCREASE
(DECREASE )
812,106
367,581
72,667
1,012,711
376,887
75,122
(20 )
(2 )
(3 )
10.7
46.1
53.9
11.7
47.7
52.3
26,589
26,668
26,511
26,533
2.73
2.73
1.68
1.74
25.99
46.47
2.83
2.83
1.60
1.66
24.88
45.04
(9 )
(3 )
3
–
1
(4 )
(4 )
5
5
4
3
(6 )
(5 )
1
(3 )
UTILITY OPERATING HIGHLIGHTS
Gas sales and transportation deliveries (000 therms) 1,061,969
1,131,365
Degree days
Customers at year-end
Employees at year-end
4,171
673,997
1,028
4,383
667,794
1,061
DIVIDENDS PAID ON COMMON STOCK (PER SHARE)
PAYMENT DATE
February 15
May 15
August 15
November 15
Total dividends paid
$ 0.415
0.415
0.415
0.435
$ 1.680
$ 0.395
0.395
0.395
0.415
$ 1.600
DILUTED EARNINGS PER SHARE
(in dollars)
DIVIDENDS PAID PER SHARE
(in dollars)
Diluted earnings per share was $2.73 in 2010.
Annual dividends paid per share in 2010 increased
for the 55th consecutive year. The current indicated
annual dividend is $1.74 per share.
Table of CONTENTS
LETTER TO SHAREHOLDERS .......................................................................... 4
OPERATIONS & INFRASTRUCTURE HIGHLIGHTS ........... ............... ....................8
COMMUNITY & SUSTAINABILITY HIGHLIGHTS ................................................ 10
FINANCIAL OVERVIEW ................................................................................. 12
CORPORATE OFFICERS ................................................................................ 18
BOARD OF DIRECTORS ................................................................................ 19
QUARTERLY FINANCIAL INFORMATION .......................................................... 20
SHAREHOLDER INFORMATION ...................................................................... 21
FORM 10-K ANNUAL REPORT
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Letter to SHAREHOLDERS
Performing today; Preparing for tomorrow
Despite a backdrop of tough economic conditions and a changing natural gas
What is the measure of a successful year? At
NW Natural we believe it comes down to two
questions: First, how well did we perform for our
key constituencies – customers, shareholders
and the communities we serve; and second, did
we better prepare our company for the future?
On both accounts, 2010 was a good year.
Gregg Kantor,
President and CEO
4
117559.indd 4
supply picture, our company continued to deliver great service effi ciently, and we
advanced our long-term strategy to grow and diversify. Our accomplishments
in 2010 included:
2010 HIGHLIGHTS
• Earnings of $2.73 per share – the third highest in our company’s history;
• Highest score in the nation in the J.D. Power and Associates Gas Utility
Residential Customer Satisfaction Survey, and best in the West in its
Business Customer Satisfaction Survey;
• Completed construction of the Gill Ranch Storage facility in California,
and went operational in the fourth quarter;
• Raised our dividend rate by 5 percent, making it the 55th consecutive
year of increasing dividends paid per share; and
• Maintained strong investment-grade credit ratings.
Long-term planning pays off during turbulent times
The seeds of last year’s success were planted well before the current economic
problems. Four years ago we realized our operating model needed to be retooled,
so we began a comprehensive restructuring focused on centralizing, streamlining,
and standardizing our operations. By 2010 we’d reduced our work force from
1,300 employees to about 1,000. As a result, we’ve been able to hold down
our utility capital and operation and maintenance expenses.
The best part of this story is that we proved
it’s possible to make these kinds of changes
without sacrificing service. Last year, we
posted the highest national score in the
J.D. Power and Associates Gas Utility
Residential Customer Satisfaction Survey,
and we received top honors in the West in
the business customer satisfaction survey.
The company’s exceptional service record is
the result of the care our employees bring every
day to interactions they have with our customers.
The J.D. Power results are a tribute to their dedication and skill, and are particu-
larly impressive given we achieved these results during some of the most diffi cult
economic times in our nation’s history.
One thing is clear: Attentive service is good for both the customer and for the
company. By listening to our customers and striving to do what’s right, we’ve
created flexible payment plan options and helped find appropriate energy assis-
tance funding when necessary. Being responsive and working with customers in
these tough times helped keep our bad debt expenses well below the industry
average and our customer satisfaction well above.
4/4/11 8:15:11 AM
Safety and good service are one
Keeping customer satisfaction ratings strong
over a long period of time requires relentless
attention to safety and reliability. From our
public safety awareness program to pipeline
operations and maintenance activities, safety
is fundamental to our mission and the ultimate
test of whether we are performing well.
NW Natural has one of the most proactive pipeline integrity management pro-
grams in the country, and our regulators and customer groups deserve a lot of
the credit. For the past three decades, they have supported and approved in
rates the cost recovery of our pipeline replacement programs. Today, we are
spending approximately $12 million per year on pipeline and system integrity
work, with about $9 million rolling into Oregon rates each November.
Competing for the future
The energy landscape is always changing, and
being ready for the future requires a dedication
to understanding the marketplace we compete
in. As we periodically do, we began 2010 by
conducting research to assess our market posi-
tion, and we were pleased to find Northwest
consumers continue to prefer natural gas over
electricity and oil for home heating. In fact, when
compared to electricity, consumers in the survey
favored gas heat by a four-to-one ratio – and
the performance over oil was even higher. The
research findings suggest participants chose
gas because it is effi cient and affordable – attri-
butes we will continue to promote and leverage
This foward-looking approach began in the 1980s when innovative rate mecha-
in our growth efforts.
Because natural gas didn’t come to the North-
west until the mid-1950s, we continue to have
more conversion opportunities than many of our
peers – opportunities we capitalized on last year.
While new home building remained sluggish,
a healthy pace of conversion activity helped
us maintain an overall customer growth rate of
about 1 percent, up slightly from 2009.
Last year, we saw natural gas prices decline for
the second year in a row, while electric rates rose
in many Northwest communities. For the 2010-11
heating season, our customers received about a
2 percent decrease in rates and are now paying
about the same amount for their natural gas as
they did in 2004. As electric prices continue to
climb, we intend to aggressively build on our
strong product preference and price advantage.
nisms allowed us to be one of the fi rst gas utilities in the nation to replace all of
our cast iron pipes, and today we have completed the removal of all bare steel
pipe in our transmission system. NW Natural has only 26 miles of bare steel pipe
left to replace in its distribution system, and we expect to complete that work
ahead of schedule and several years prior to the required date.
But our commitment to safety includes more than pipe in the ground. In 2010,
we stepped up training to expand the number of employee fi rst responders to
enhance our emergency response times.
More pipeline safety regulation is likely given recent pipeline incidents in other
states. We believe that with the work we’ve done to date, NW Natural is well
positioned to address the potential safety legislation currently being considered
in Washington, D.C. We will continue to work with regulators in Oregon and
Washington to address any changes in federal law and make sure our safety
programs remain among the nation’s best.
Successful outcomes to challenging issues
Delivering high-quality, effi cient service for our customers and solid earnings for
our shareholders means making sure laws and regulations are applied fairly. Last
year, after more than five years of effort, the company won an important prop-
erty tax ruling. The Oregon Supreme Court unanimously ruled in our favor that
gas inventories held for resale should not be taxed as personal property. Under
the ruling, the company received a refund with net proceeds of $6 million.
Making sure the company was being treated fairly also led us last year to look
for a solution to the funding challenge created by the Pension Protection Act
of 2006, an issue faced by many utilities across the country. The law had the
potential to cause signifi cant funding requirements and earnings volatility due
to increases or decreases in interest rates and pension assets. By year-end
2010, our discussions led to an agreement approved by Oregon regulators
and customer groups that sets up a balancing account, with interest, allowing
us to defer pension costs higher than what we currently collect in rates. This
agreement allows us to stabilize our pension expense impact on earnings
without increasing customer rates.
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Letter to SHAREHOLDERS
(continued)
Better prepared for tomorrow
projects, it will take a few years to get the reservoir performing at its full capacity,
2010 was a good year for our utility business.
From customer service to earnings, we delivered
on the promises we made. But as I said at the
beginning of this letter, performing well today
is only part of what makes a good year. For a
152-year-old company like NW Natural, the year
is really only a success when you end it better
prepared for tomorrow.
We met that test in 2010. In addition to a utility
that is more efficient and better prepared to
compete in tomorrow’s marketplace, our non-
utility business also ended the year having taken
big strides.
GAS STORAGE CAPACITY
(working gas capacity)
f
c
B
MIST UTILITY
MIST NONUTILITY
GILL RANCH
In 2010, Gill Ranch added 15 Bcf of design capacity to the
company’s gas storage business.
In October, we completed the construction of
an underground natural gas storage facility near
Fresno, California. Gill Ranch Storage, LLC,
NW Natural’s subsidiary, is operator of the new
facility and 75 percent owner, with Pacifi c Gas
and Electric owning the remaining 25 percent.
Our share of the facility is designed to provide
15 billion cubic feet of capacity and is well
positioned to serve the California market. To
date, the reservoir is performing as expected.
Like all new depleted gas reservoir storage
6
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as capacity increases with every injection and withdrawal.
Completing Gill Ranch was a major milestone in the execution of our business
strategy. But it did not come without struggles. Unusually heavy rain early last
year and unexpected wildlife issues caused delays in construction. Overcoming
those delays, along with increases in materials, labor and permit requirements,
added costs to the project. Our share of the facility’s capital costs were approxi-
mately $215 million.
Today a significant portion of the first year’s capacity is contracted out. And we
are applying the same fiscal discipline we use in the utility business to our non-
utility storage operations. Cost management will be critical in light of today’s weak
market for storage services caused by an abundance of gas supply, low volatility
in natural gas prices, and the struggling economy.
NW Natural’s nonutility storage business is about growing and diversifying what
we do. It's about using our core competencies to add shareholder value over the
long term. Storage values may be weak today, but we believe the signs point to
strength in the long run, particularly on the West Coast.
Oregon, Washington and California have set aggressive carbon reduction and
renewable energy development goals. In Oregon, regulators approved a plan
to close the state’s only coal-fi red plant by 2020. Negotiations to close an even
larger coal plant in Western Washington are also under way.
As electric utilities turn to natural gas to fi rm up renewable power, serve new
generation demand, and transition off coal, adequate gas infrastructure on the
West Coast – storage and pipelines – will be essential.
A new pipeline for the Northwest
The growing need for natural gas in the Northwest is what led our company to
join with TransCanada on the Palomar Pipeline. The project, which would add
another path to bring gas into the western portions of Oregon and Washington,
would provide enhanced reliability and greater access to gas supplies for the
region’s energy customers.
Last year the project saw a number of key developments. As originally proposed,
Palomar was designed as two sections, one (the western section) to ship gas
from a proposed LNG terminal near the mouth of the Columbia River, the other
(the eastern section) to bring into the region additional supplies from the U.S.
Rocky Mountains and Western Canada. Early in 2010, NorthernStar, the LNG
terminal’s developer, fi led for bankruptcy and halted further work on its project.
With that project eliminated, the Palomar team has been working to secure
shippers for the eastern section.
Without LNG, the eastern section of Palomar (Palomar East) is more important
than ever. Today the existing interstate pipeline serving our region west of the
Cascades is fully contracted and at maximum use when peak loads are reached.
Palomar East is the next logical piece of transmission pipeline infrastructure
needed to serve the Northwest.
Throughout 2010, we continued to work on advancing Palomar East with our
4/4/11 8:16:14 AM
partner, TransCanada, and we made progress on a number of important issues.
continue to seek improvements. And our empha-
Last fall, we announced that Northwest Pipeline, the company that owns the ex-
sis on safety doesn’t stop there. Employee safety
isting interstate pipeline system serving the west side of Oregon and Washington,
is a core value, and we are working on ways to
signed a nonbinding memorandum of understanding that contemplates them
ensure employees stay healthy and safe while
becoming part owner of Palomar. This is a positive step forward in consolidating
meeting the needs of our customers.
the region’s efforts to develop a cross-Cascades pipeline using the Palomar route.
In our nonutility business, we will remain focused
One other notable project accomplishment in 2010 was a new route agreement
on maximizing the return on our investment in Gill
that the Palomar team had been negotiating for some time. Last fall, the Con-
Ranch, including carefully managing costs and
federated Tribes of the Warm Springs Reservation signed an agreement with
looking for areas of commercial opportunity in the
Palomar that provides tribal consent to a right-of-way across the Warm Springs
storage market. This year we will also continue
Reservation in Central Oregon. As a result, the length of the route was shortened
planning for the next Mist expansion in anticipa-
and environmental impacts reduced. This development is a signifi cant benefi t to
tion of the increased natural gas demand created
the project as we progress into the next phase of work.
by electric generation and economic recovery in
Earlier this year, we conducted a workshop with the utility commissioners in
the Northwest.
Oregon and Washington to discuss the region’s future pipeline capacity needs
2011 will be a pivotal year for the Palomar
and the regulatory treatment of new pipeline capacity agreements. This meeting
Pipeline. In the months to come, we will work
gave the commissioners a unique opportunity to hear about the broader implica-
to make sure its importance is fully understood
tions of the growing interdependence of the electric and natural gas systems –
by all stakeholders. We also hope to solidify
from the perspective of electric providers and pipeline companies.
shipper support and make progress on FERC
Looking ahead
In 2011, the tests by which we measure ourselves will not change. We intend
to deliver on our promises to customers, shareholders and the communities we
serve. And we will continue to prepare our company for the future. This means
focusing our work in the utility to improve customer service, expand marketing
efforts and manage costs. We are also looking at innovative opportunities inside
the utility to create additional value for our customers and shareholders, such as
an effort we recently announced to invest in gas reserves to provide low cost,
long-term gas supplies for our customers.
Pipeline safety will likely dominate industry headlines in the months ahead. While
we believe our safety program is among the most proactive in the country, we will
TOTAL SHAREHOLDER RETURN
(annualized as a percent, including reinvestment of dividends)
permitting efforts.
NW Natural has proven over the years it can
deliver on today’s expectations while keeping
an eye on the horizon. And while we are well
positioned to succeed in an energy landscape
increasingly reliant on natural gas, we also
believe it is critical to continue to be ready for a
changing world. We remain actively engaged in
the policy debates at the state and federal levels
on climate change and energy issues, and we
continue to explore ways, such as our Smart
Energy carbon offset program, to better connect
to emerging public policies.
It will be a busy and challenging year for NW
Natural. We enter it excited by the opportunities
and deeply committed to both performing today
and preparing for tomorrow. From all of us who
work at NW Natural, thank you once again for
the confi dence you place in us. It is an honor
to work on your behalf.
Sincerely,
Gregg S. Kantor
President and CEO
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OPERATIONS & INFRASTRUCTURE
hhiiigggggghhllliiiggggggghhhhtttttssss
highlights
Product preference strong
Our research shows that consumers favor natural gas for
home heating over oil and electricity because of its effi ciency
and affordability. To capitalize on consumer preference, we
worked with our HVAC contractors last year to combine tax
credits with other incentives totaling nearly $2,600 toward the
purchase and installation of high-effi ciency gas equipment.
UTILITY CUSTOMERS
SERVED BY EACH OPERATING EMPLOYEE
Top service score in the U.S.
NW Natural employees demonstrated an unwav-
ering commitment to service excellence, while
navigating many changes within the company
and a diffi cult economic environment facing
customers. And their responsiveness paid off,
resulting in top J.D. Power and Associates
rankings for business and residential customer
satisfaction. This was the second time in three
years the company posted the top residential
score in the nation among participating
gas utilities.
Emergency response training
Skilled and fl exible employees are the key to
an effective emergency response program. To
ensure readiness, the company increased its
investment in emergency responder training last
year and now has about 315 fully qualifi ed fi rst
responders, a nearly 50 percent increase from
2009. We also began providing a three-day,
scenario-based emergency response training
that gives all fi rst responders hands-on experi-
ence to prepare them for the unexpected.
8
117559.indd 8
The number of customers served by operating employees continued
to increase in 2010, as we improved operational effectiveness.
4/4/11 8:16:26 AM
Strategic storage asset goes into service
Our newest infrastructure project, Gill Ranch Storage, went online
last year with 20 billion cubic feet of designed underground storage
capacity. The plant serves utilities, merchant generators, producers
and marketers in the California energy market. We believe Gill Ranch
will be a critical asset as California relies on more natural gas to meet
its electric generation needs and carbon reduction goals.
Recognition for a job well done
Gill Ranch Storage was built to meet the highest safety and environmental protection standards. The Fresno branch of
the American Society of Civil Engineers recognized Gill Ranch Storage for its geotechnical work. The award highlighted the
project’s integrated approach to storm water pollution prevention, drainage, erosion and sediment control, groundwater
monitoring, and emergency response planning.
CONSTRUCTING safely
The project experienced an excellent
safety record with almost 1 million
labor hours logged for compressor
station and pipeline construction
work and no lost-time accidents.
Economic benefi ts for the community
During construction, Gill Ranch employed a
total of almost 500 workers, 400 of which came
out of the local labor community. In total, the
project accounted for expenditures in the local
community of $75 million for wages, benefi ts,
and contract services.
Going forward we estimate that Gill Ranch
will contribute in excess of $3 million annually
to the local economy. The community will also
benefi t from property taxes paid by the facility,
which are expected to be in excess of $2 million
each year.
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COMMUNITY & SUSTAINABILITY
highlights
Living our values
Doing what is right is a guiding principle at
NW Natural. Last year, we received the Oregon
Ethics in Business Award for our consistent
demonstration of ethical business practices
in the workplace, marketplace, environment
and community. Safety, integrity, service ethic,
caring and environmental stewardship are the
building blocks of our company. NW Natural
employees embody these core values, which
drive our business decisions.
Catalyst for giving
When one of our small communities was rav-
aged by record fl oods, NW Natural was the
fi rst business to commit to a public-private
partnership fundraising effort to rebuild its
schools. Our $100,000 contribution helped
pave the way for fundraising efforts to rebuild
Vernonia, Oregon schools in a central and
safe location above the fl ood plain. The project
will result in the fi rst LEED platinum-certifi ed
public K-12 building in the United States.
Helping to make higher education attainable
As part of our philanthropic focus of helping children and families at
risk, last year we contributed more than $20,000 to several college
funds that target underserved populations. Included in that total
was our annual contribution of $10,000 to the Oregon Independent
College Foundation, which provides assistance to students of color
or first generation students. The scholarships assist students
attending the foundation’s 10 member colleges and universities.
TOTAL 2010 CONTRIBUTIONS: $1,140,400
40%40% Helping
Children and
Families at Risk
42%42% Civic,
Cultural Educational
and Environmental
5% Employee Volunteer and
Recognition Programs: Dollars
for Doers and Above & Beyond
13%13% Charitable Giving Cam-
paign Umbrella Organizations:
Black United Fund of Oregon,
Earth Share of Oregon, United
Way and Work for Art
10
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4/4/11 8:19:45 AM
Everyone wins
with Paperless Billing
Our Paperless Billing campaign
entices customers to give up
traditional paper bills by offering
the chance to vote on how to split
a $25,000 contribution to four local
environmental nonprofi t groups. In
the last five years, the campaign
has contributed $115,000. So far,
nearly 100,000 of our customers
have chosen to reduce their
emissions and waste by going
paperless.
of customer base
registered to use Web services
33%
58%
pay electronically
of customer base
Smart Energy celebrates milestone
After our customers told us they wanted help
managing their carbon footprint, we launched a
voluntary offset program called Smart Energy. Three
years later, we have signed up more than 11,000
Smart Energy customers including Oregon Con-
vention Center, Rose Garden Arena and Chinook
Winds Casino Resort. As a result, our customers
have offset nearly 80,000 tons of carbon. This is the
equivalent of removing nearly 14,000 cars from the
road for a year or reducing emissions from 8 million
gallons of gasoline.
Helping customers
achieve greater effi ciency
We believe efficiency is the most effective way
customers can control energy costs and reduce
carbon emissions. In 2010, through our energy-
effi ciency partnerships we helped customers save
4.4 million therms, the same amount of natural gas
it would take to serve more than 6,600 homes.
We’ve also partnered with local municipalities and
others in the Clean Energy Works pilot program
to make significant home weatherization invest-
ments possible. As a result, participating homes
saved more than twice as much electricity and
fi ve times as much gas as homes using the basic
statewide energy-effi ciency program.
117559.indd 11
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4/4/11 8:20:22 AM
Comparative Consolidated INCOME STATEMENTS
Thousands, except per share amounts (year ended December 31)
2010
2009
2008
2007
2006
Operating revenues:
Gross operating revenues
Less: Cost of sales
Revenue taxes
Net operating revenues
Operating expenses:
Operations and maintenance
General taxes
Depreciation and amortization
$ 812,106
$ 1,012,711
$ 1,037,855
$ 1,033,193
$ 1,013,172
424,534
19,991
611,168
24,656
656,568
25,072
639,150
25,001
648,156
24,840
367,581
376,887
356,215
369,042
340,176
120,980
23,872
65,124
127,104
28,253
62,814
113,360
26,660
72,159
120,488
114,560
25,288
68,343
24,419
64,435
Total operating expenses
209,976
218,171
212,179
214,119
203,414
Income from operations
157,605
158,716
144,036
154,923
136,762
Other income and expense - net
7,102
3,714
3,746
1,445
2,134
Interest expense - net
42,578
40,637
37,579
37,811
39,247
Income before income taxes
122,129
121,793
110,203
118,557
99,649
Income tax expense
49,462
46,671
40,678
44,060
36,234
Net income
$ 72,667
$ 75,122
$ 69,525
$ 74,497
$ 63,415
Average common shares outstanding:
Basic
Diluted
Earnings per share of common stock:
Basic
Diluted
26,589
26,657
26,511
26,576
26,438
26,594
26,821
26,995
27,540
27,657
$ 2.73
$ 2.73
$ 2.83
$ 2.83
$ 2.63
$ 2.61
$ 2.78
$ 2.76
$ 2.30
$ 2.29
Dividends declared per share of common stock
$ 1.68
$ 1.60
$ 1.52
$ 1.44
$ 1.39
These Financial Statements are condensed. See full Financial Statements and Notes to Consolidated Financial Statements in the company’s Annual Report
on Form 10-K.
NET INCOME
(in millions)
TOTAL PLANT AND PROPERTY
(in millions)
Net Income in 2010 was $73 million, the third highest
in our company's history.
At the end of 2010, Total Plant and Property was
$1.9 billion, an 11 percent increase from 2009.
12
117559.indd 12
4/4/11 8:21:08 AM
Comparative Consolidated BALANCE SHEETS
Thousands (December 31)
2010
2009
2008
2007
2006
Assets
Plant and property:
Utility plant
$ 2,277,276
$ 2,216,112
$ 2,142,988
$ 2,052,161
$ 1,963,498
Less accumulated depreciation
710,214
682,060
659,123
615,533
574,093
Utility plant - net
Non-utility property
Less accumulated depreciation
Non-utility property - net
Total plant and property
Current assets:
Cash and cash equivalents
Restricted cash
Accounts receivable
Accrued unbilled revenue
Allowance for uncollectible accounts
Inventories of gas, materials and supplies
Income taxes receivable
Prepayments and other current assets
Total current assets 1
Regulatory assets1
Derivative instruments1
Other investments
Other non-current assets
Total assets
Capitalization and liabilities
Capitalization:
Common stock equity
Long-term debt
Total capitalization
Current liabilities:
Short-term debt
Accounts payable
Current maturities of long-term debt
Taxes accrued
Interest accrued
Other current liabilities
Total current liabilities 1
Regulatory liabilities 1
Deferred tax liabilities
Derivative instruments 1
1,567,062
1,534,052
1,483,865
1,436,628
1,389,405
299,126
12,025
287,101
146,622
10,540
136,082
74,506
9,314
65,192
67,149
7,904
59,245
42,652
6,916
35,736
1,854,163
1,670,134
1,549,057
1,495,873
1,425,141
3,457
924
67,969
64,803
(2,950 )
80,385
41,066
8,432
35,543
77,438
71,230
(3,125 )
80,957
–
19,652
275,306
21,302
291,777
6,916
4,118
81,288
102,688
(2,927 )
96,067
20,811
20,098
329,059
6,107
–
69,442
78,004
(2,890 )
79,944
–
5,767
–
82,070
87,548
(3,033 )
78,128
–
25,569
256,176
21,695
272,175
401,611
346,490
435,789
193,536
196,280
2,873
69,094
13,569
7,347
67,365
16,139
4,738
54,132
5,377
3,227
54,070
11,179
6,557
47,985
8,718
$ 2,616,616
$ 2,399,252
$ 2,378,152
$ 2,014,061
$ 1,956,856
$ 693,101
$ 660,105
$ 628,373
$ 594,751
$ 599,545
591,700
601,700
512,000
512,000
517,000
1,284,801
1,261,805
1,140,373
1,106,751
1,116,545
257,435
93,243
10,000
10,579
5,182
35,457
102,000
123,729
35,000
21,037
5,435
39,097
248,000
94,422
–
12,455
2,785
36,467
143,100
119,731
5,000
13,137
2,827
29,794
100,100
113,579
29,500
21,230
2,924
21,455
411,896
326,298
394,129
313,589
288,788
275,859
373,409
55,459
295,250
300,898
22,836
248,613
257,831
158,381
178,825
275,090
206,340
18,587
93,704
214,901
210,084
49,803
76,735
Other non-current liabilities
215,192
192,165
Total capitalization and liabilities
$ 2,616,616
$ 2,399,252
$ 2,378,152
$ 2,014,061
$ 1,956,856
1 Current and long-term portions of regulatory assets, regulatory liabilities and derivative instruments are combined for presentation above.
These Financial Statements are condensed. See full Financial Statements and Notes to Consolidated Financial Statements in the company’s Annual Report
on Form 10-K.
117559.indd 13
13
4/4/11 8:21:28 AM
Comparative FINANCIAL STATISTICS
MARKET PRICE & BOOK VALUE PER SHARE
(in dollars)
COMPARISON OF FIVE-YEAR CUMULATIVE TOTAL RETURN
(based on $100 invested on 12/31/05)
YEAR-END BOOK VALUE
YEAR-END MARKET PRICE
HIGH/LOW MARKET PRICE
The year-end market-to-book ratio was 1.8 in 2010.
NWN
S&P UTILITIES INDEX
S&P SMALL CAP 600
Total shareholder return (annualized) over the five years ending
December 31, 2010 was 10.1 percent, compared to the Standard
& Poor’s (S&P) Electric & Gas Utilities Index rate of a negative
0.3 percent and the S&P Small Cap 600 Index rate of 3.5 percent.
CAPITAL EXPENDITURES
(in millions)
YEAR-END CAPITAL STRUCTURE
(in millions)
UTILITY CUSTOMER GROWTH
UTILITY SYSTEM MAINTENANCE
MIST STORAGE
UTILITY SYSTEM INTEGRITY
PALOMAR PIPELINE
GILL RANCH STORAGE
Total capital expenditures in 2010 were $226 million, of which
$86 million was utility related.
COMMON EQUITY
LONG-TERM DEBT
SHORT-TERM DEBT
Total capitalization at the end of 2010 grew to $1.6 billion, of which
45 percent was common equity.
14
117559.indd 14
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Comparative FINANCIAL STATISTICS
Common stock
Ratios at year-end:
Price/earnings ratio
Dividend yield at year-end rate - %
Dividend payout - %
Consolidated return on average common equity - %
Per share data ($):
Basic earnings
Diluted earnings
Dividends paid
Dividend rate at year-end
Book value at year-end
Market price:
High
Low
Year-end
Average
Number of shares of common stock outstanding (000):
Year-end
Average
Coverage data
2010
2009
2008
2007
2006
17.0
3.7
61.5
10.7
2.73
2.73
1.68
1.74
15.9
3.7
56.5
11.7
2.83
2.83
1.60
1.66
16.8
3.6
57.8
11.4
2.63
2.61
1.52
1.58
17.5
3.1
51.8
12.5
2.78
2.76
1.44
1.50
18.5
3.3
60.4
10.7
2.30
2.29
1.39
1.42
25.99
24.88
23.71
22.52
21.97
50.86
41.05
46.47
46.32
46.47
37.71
45.04
42.93
55.23
36.61
44.23
46.38
52.85
39.79
48.66
46.20
43.69
32.83
42.44
36.98
26,668
26,589
26,533
26,511
26,501
26,438
26,407
26,821
27,284
27,540
Ratio of earnings to fi xed charges
3.73
3.86
3.76
3.92
3.40
(Securities and Exchange Commission method)
Cash fl ow data ($000)
Cash provided by operating activities
126,469
240,335
34,721
183,640
Cash used in investing activities
(212,871 )
(162,141 )
(109,825 )
(117,479 )
148,566
(90,567 )
Plant and property
Additions ($000)
Annual depreciation ($000)
Depreciation rate - % of average depreciable plant †
Long-term capital structure at year-end (%)
Long-term debt*
Common stock equity
Total capital structure
Effective tax rate
225,505
65,124
2.8
169,480
62,814
2.9
117,450
72,159
3.4
125,511
68,343
3.4
103,008
64,435
3.4
46.1
53.9
100.0
47.7
52.3
100.0
44.9
55.1
100.0
46.3
53.7
100.0
46.3
53.7
100.0
Effective tax rate - % of pretax income
40
38
37
37
36
†Includes regulatory liability for accrued asset removal costs.
*Excludes current portion of long-term debt.
117559.indd 15
15
4/4/11 8:21:43 AM
Comparative OPERATING STATISTICS
UTILITY CUSTOMERS AT YEAR-END
(in thousands)
UTILITY GAS SALES AND TRANSPORTATION DELIVERIES
(in millions of therms)
We added 6,203 new customers in 2010, and now serve 673,997
customers.
FIRM SALES
INTERRUPTIBLE SALES
TRANSPORTATION
Gas sales and transportation deliveries in 2010 decreased 6 percent
from 2009, due primarily to warmer weather and the lingering effects
of a weak economy.
UTILITY GAS REVENUES
(by customer class)
UTILITY NET OPERATING REVENUES (MARGIN)
(in millions)
RESIDENTIAL
COMMERCIAL
INDUSTRIAL FIRM SALES
INDUSTRIAL INTERRUPTIBLE SALES
TRANSPORTATION
OTHER
Revenues from residential, commercial and industrial firm sales
accounted for 90 percent of total gas revenues in 2010.
RESIDENTIAL
COMMERCIAL
INDUSTRIAL
OTHER
Utility margin decreased 3 percent in 2010, due primarily to lower
gas cost-sharing amounts in 2010.
16
117559.indd 16
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Comparative OPERATING STATISTICS
Selected Utility Data
2010
2009
2008
2007
2006
Gas sales and transportation deliveries (000 therms):
Residential
Commercial
Industrial fi rm
Industrial interruptible
Total gas sales
Transportation
368,682
230,196
37,085
58,387
694,350
367,619
412,867
255,593
39,447
72,525
780,432
350,933
428,787
265,531
47,340
87,484
829,142
431,609
398,960
249,659
52,340
89,128
790,087
424,882
382,665
242,683
66,971
112,736
805,055
387,594
Total volumes delivered
1,061,969
1,131,365
1,260,751
1,214,969
1,192,649
Operating revenues and cost of sales ($000):
Utility operating revenues:
Residential
Commercial
Industrial fi rm
Industrial interruptible
Total gas sales revenues
Transportation
Regulatory adjustment for income taxes paid
Other
Total utility operating revenues
Cost of gas sold
Revenue taxes
456,174
227,994
30,830
36,164
555,844
292,697
41,407
62,116
566,840
298,943
46,579
68,978
555,312
298,800
54,567
74,876
536,468
290,666
66,986
93,107
751,162
952,064
981,340
983,555
987,227
13,833
7,721
17,917
790,633
424,494
13,635
5,884
21,166
14,288
1,760
21,784
14,191
12,800
5,996
12,228
–
161
992,749
1,019,172
1,015,970
1,000,188
611,088
656,504
639,094
648,081
19,991
24,656
25,072
25,001
24,840
Utility net operating revenues (margin)
346,148
357,005
337,596
351,875
327,267
Customer and weather data:
Total customers
Actual degree days
Percent colder (warmer) than average
Average use per customer (therms):
Residential
Commercial
673,997
667,794
662,341
652,012
636,584
4,171
(2)%
616
3,699
4,383
3%
686
4,113
4,576
7%
721
4,300
4,374
3%
687
4,110
4,089
(4)%
678
4,052
Gas purchases (000 therms)
716,509
784,982
829,989
806,905
820,542
Gas purchased cost per therm - net (cents)
Average sendout cost of gas (cents)
Maximum day fi rm sendout (000 therms)
Maximum day total sendout (000 therms)
Total employees at year-end
Number of customers served by each operating employee
63.07
61.36
5,764
7,252
1,028
1,077
71.96
78.40
6,980
8,339
1,061
979
86.56
79.21
6,609
8,363
1,133
932
75.00
80.89
5,845
7,344
1,141
924
75.37
80.50
5,672
7,401
1,211
845
117559.indd 17
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4/4/11 8:22:08 AM
Corporate OFFICERS
DAVID H. ANDERSON, 49 [2004]
SENIOR VICE PRESIDENT AND CHIEF
FINANCIAL OFFICER (2004-PRESENT)
Senior VP and CFO, TXU Gas (2004)
Senior VP, Corporate Controller and Principal
Accounting Offi cer, TXU Corp. (2003-2004)
VP, Investor Relations and Shareholder
Services, TXU Corp. (1997-2003)
STEPHEN P. FELTZ, 55 [1982]
TREASURER AND CONTROLLER (1999-PRESENT)
Assistant Treasurer and
Manager General Accounting (1996-1999)
LEA ANNE DOOLITTLE, 56 [2000]
SENIOR VICE PRESIDENT (2008-PRESENT)
Vice President, Human Resources (2000-2007)
Director of Compensation, Pacifi Corp (1993-2000)
GREGG S. KANTOR, 53 [1996]
PRESIDENT AND CHIEF EXECUTIVE OFFICER
(2008-PRESENT)
President and Chief Operating Offi cer (2007-2008)
Executive Vice President (2006-2007)
Senior Vice President, Public and Regulatory Affairs (2003-2006)
Vice President, Public Affairs and Communications (1998-2002)
MARGARET D. KIRKPATRICK, 56 [2005]
VICE PRESIDENT AND GENERAL COUNSEL
(2005-PRESENT)
Partner, Stoel Rives LLP (1991-2005)
C. ALEX MILLER, 53 [2002]
VICE PRESIDENT FINANCE
AND REGULATION (2009-PRESENT)
ASSISTANT TREASURER (2008-PRESENT)
Director, Rates and Regulatory Affairs (2002-2009)
MARDILYN SAATHOFF, 54 [2008]
DEPUTY GENERAL COUNSEL,
CHIEF GOVERNANCE OFFICER AND
CORPORATE SECRETARY (2008-PRESENT)
Chief Compliance Offi cer and Assistant General Counsel,
Tektronix, Inc. (2005-2008)
General Counsel to Oregon Governor Kulongoski and
Business and Economic Development Advisor (2003-2005)
DAVID R. WILLIAMS, 58 [1978]
VICE PRESIDENT UTILITY SERVICES
(2007-PRESENT)
Director, Utility Operations (2006-2007)
Director, Districts and Labor Relations (2004-2006)
General Manager, Utility Operations (1999-2004)
J. KEITH WHITE, 58 [1996]
VICE PRESIDENT BUSINESS DEVELOPMENT
AND ENERGY SUPPLY AND CHIEF STRATEGIC
OFFICER (2007-PRESENT)
Managing Director, Gas Operations and
Wholesale Services (2005-2006)
Managing Director and Chief Strategic Offi cer (2003-2005)
GRANT M. YOSHIHARA, 56 [1991]
VICE PRESIDENT UTILITY OPERATIONS
(2007-PRESENT)
Managing Director, Utility Services (2005-2006)
Director, Utility Services (2004-2005)
General Manager, Consumer Services (2003-2004)
18
117559.indd 18
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Board of DIRECTORS
Back row
JANE L. PEVERETT, 52
[2007] (2) (3) (5)
Former President and
Chief Executive Offi cer
British Columbia Transmission Corporation
Vancouver, British Columbia
KENNETH THRASHER, 61
[2005] (2) (3) (4)
Chairman of the Board
Compli Corporation
Portland, Oregon
C. SCOTT GIBSON, 58
[2002] (1) (3) (4)
President
Gibson Enterprises
Jackson, Wyoming
JOHN D. CARTER, 65
[2002] (1) (2) (6)
Chairman of the Board
Schnitzer Steel Industries, Inc.
Portland, Oregon
MARK S. DODSON, 66
[2003] (4) (5)
Former Chief Executive Offi cer
NW Natural
Vancouver, Washington
GEORGE J. PUENTES, 63
[2007] (4) (6)
Former President
Don Pancho Authentic
Mexican Foods, Inc.
Salem, Oregon
MARTHA L. “STORMY”
BYORUM, 62
[2004] (2) (6)
Senior Managing Director
Stephens Cori Capital Advisors
New York, New York
TIMOTHY P. BOYLE, 61
[2003] (4) (5)
President and
Chief Executive Offi cer
Columbia Sportswear Company
Portland, Oregon
GREGG S. KANTOR, 53
[2008]
President and
Chief Executive Offi cer
NW Natural
Portland, Oregon
Front row
TOD R. HAMACHEK, 65
[1986] (1) (2) (5)
Former Chairman and
Chief Executive Offi cer
Penwest Pharmaceuticals Company
Seattle, Washington
RUSSELL F. TROMLEY, 71
[1994] (1) (2) (3)
Chairman of the Board and
Chief Execuitve Offi cer
Tromley Industrial Holdings, Inc.
Tualatin, Oregon and
Chairman of the Board, NW Natural
Portland, Oregon
KEY: [Year elected to the board], (1) Governance Committee, (2) Audit Committee, (3) Organization and Executive Compensation Committee, (4) Public Affairs and Environmental
Policy Committee, (5) Strategic Planning Committee, (6) Finance Committee
117559.indd 19
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4/4/11 8:25:30 AM
Quarterly FINANCIAL INFORMATION
Quarterly Financial Information (unaudited)
(thousands except per share amounts)
March 31
June 30
Sept. 30
Dec. 31
Total
2010
Operating revenues
Net operating revenues
Net income (loss)
Basic earnings (loss) per share
Diluted earnings (loss) per share
2009
Operating revenues
Net operating revenues
Net income (loss)
Basic earnings (loss) per share
Diluted earnings (loss) per share
$286,529
$162,365
$95,067
$268,145
$812,106
130,926
43,608
1.64
1.64
72,193
46,211
118,251
367,581
6,888
0.26
0.26
(7,420)
29,591
72,667
(0.28)
(0.28)
1.11
1.11
2.73 *
2.73 *
$437,355
$149,060
$116,854
$309,422
$1,012,711
142,639
47,363
1.79
1.78
65,919
3,086
0.12
0.12
48,626
(6,733 )
(0.25 )
(0.25 )
119,703
31,406
1.19
1.18
376,887
75,122
2.83 *
2.83 *
* Quarterly earnings (loss) per share are based upon the average number of common shares outstanding during each quarter. Because the average number
of shares outstanding has changed in each quarter shown, the sum of quarterly earnings may not equal earnings per share for the year. Variations in earnings
between quarterly periods are due primarily to the seasonal nature of our business.
Common Stock Prices
NW Natural’s common stock is listed and trades on the New York Stock Exchange under the symbol “NWN.”
The quarterly high, low and close share price during 2010 and 2009 was:
2010
Quarter Ended
High
Low
Close
March 31
June 30
September 30
December 31
2009
$47.54
$41.05
$46.60
49.18
49.00
50.86
41.90
42.63
44.02
43.57
47.45
46.47
Quarter Ended
High
Low
Close
March 31
June 30
September 30
December 31
$45.66
$37.71
$43.42
46.07
46.00
46.47
39.58
41.12
40.83
44.32
41.66
45.04
20
117559.indd 20
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Shareholder INFORMATION
Notice of annual meeting
The 2011 Annual Meeting will be held at 2 p.m., Thursday, May 26, at the Oregon Convention Center, 777 NE Martin Luther King Jr. Blvd.,
Portland, Oregon 97232. A meeting notice and proxy statement will be sent to all shareholders in April. If you plan to attend the annual meeting,
you will need to detach and retain the admission ticket attached to your proxy card mailed to you with the notice of the annual meeting and
the proxy statement. As space is limited, you may bring only one guest to the meeting. If you hold your stock through a broker, bank, or other
nominee, please bring evidence to the meeting that you owned NW Natural Common Stock as of the record date, April 6, 2011, and we will
provide you with an admission ticket. A form of government-issued photograph identifi cation will be required to enter the meeting.
Dividend reinvestment
and direct stock purchase plan
Contact the NW Natural board
Request for publications
Concerns may be directed to the non-
The following publications may be obtained
Participants may make an initial investment
management directors by writing to
without charge by contacting the Corporate
in company stock and common sharehold-
NW Natural Board of Directors,
Secretary at NW Natural’s address: Annual
ers of record may reinvest all or part of their
c/o Corporate Secretary.
dividends in additional shares under the
company’s plan. Cash purchases may also
Forward-looking statements
Report; Form 10-K; Form 10-Q; Corporate
Governance Standards; Director Indepen-
dence Standards; Code of Ethics; and
be made. Participants in the plan bear the
The statements made in this Annual
Board Committee Charters. These publica-
cost of brokerage fees and commissions
Report that are not purely historical,
tions, as well as other fi lings made with the
for shares purchased on the open market
including statements regarding strategy,
SEC, also are available on our website at
to fulfi ll purchases under the plan. A pro-
growth, future demand for gas, com-
nwnatural.com. Our SEC filings are also
spectus will be sent upon request.
modity costs, gas supplies, investment
available in the public reference room of
Scheduled dividend payment dates
returns, business development, project
the SEC at 100 F Street NE, Washington,
timelines, pipeline replacement and safety
DC 20549, by calling (800) 732-0330 or
February 15, 2011
May 13, 2011
August 15, 2011
November 15, 2011
Certifi cations
programs, storage performance and
storage values, operational changes,
cost management, pension deferrals,
contributions to local economies, tax
estimates, governmental policy legisla-
tion and regulatory actions, economic
by accessing the SEC website at sec.gov.
STOCK TRANSFER AGENT
AND REGISTRAR
For the common stock:
American Stock Transfer & Trust Company
The Chief Executive Offi cer certifi ed to the
factors and the competitive environment
6201 15th Avenue
NYSE on June 25, 2010 that, as of that
are forward-looking statements within the
date, he was not aware of any violation by
“safe harbor” provisions of the Private
the company of NYSE’s corporate gover-
Securities Litigation Reform Act of 1995.
nance listing standards, and the company
NW Natural’s actual results could differ
had fi led with the Securities and Exchange
materially from those anticipated in these
Commission (SEC), as exhibits 31.1 and
forward-looking statements as a result of
31.2 to its Annual Report on Form 10-K
risks and uncertainties, including those
for the year ended December 31, 2009,
described in the attached report on Form
the certificates of the Chief Executive
10-K. For a more complete description
Offi cer and the Chief Financial Offi cer of
of these risks and uncertainties, please
the company certifying the quality of the
refer to our filings with the SEC on
company’s public disclosure. For the year
Forms 10-K and 10-Q.
Brooklyn, NY 11219
(888) 777-0321
Web: amstock.com
email: info@amstock.com
TRUSTEE AND BOND PAYING AGENT
For all bond issues:
Deutsche Bank Trust Company Americas
60 Wall Street
27th Floor
New York, NY 10005
(800) 735-7777
ended December 31, 2010, the certifi cates
of the Chief Executive Officer and Chief
Financial Offi cer are attached as exhibits
31.1 and 31.2 to the Form 10-K included
in this Annual Report.
Investor & Shareholder Information
Robert S. Hess
Investor Relations
(800) 422-4012, Ext. 2388
rsh@nwnatural.com
220 NW Second Avenue, Portland, OR 97209
(503) 226-4211 or toll-free (800) 422-4012
nwnatural.com
NYSE: NWN
117559.indd 21
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4/4/11 8:25:37 AM
Our MISSION & VALUES
OUR MISSION:
We provide safe, reliable
and affordable energy
in an environmentally responsible way
to better the lives
of the public we serve.
OUR CORE VALUES:
Safety
INTEGRITY
Service Ethic
CARING
Environmental Stewardship
22
117559.indd 22
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Form 10-K
Annual Report
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
[X]
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2010
OR
[
]
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from
to
Commission file number 1-15973
NORTHWEST NATURAL GAS COMPANY
(Exact name of registrant as specified in its charter)
Oregon
(State or other jurisdiction of
incorporation or organization)
93-0256722
(I.R.S. Employer
Identification No.)
220 N.W. Second Avenue, Portland, Oregon 97209
(Address of principal executive offices) (Zip Code)
Registrant’s telephone number, including area code: (503) 226-4211
Securities registered pursuant to Section 12(b) of the Act:
Title of each class
Common Stock
Securities registered pursuant to Section 12(g) of the Act: None.
Name of each exchange on which registered
New York Stock Exchange
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities
Act. Yes [ X ] No [
]
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the
Act. Yes [
] No [ X ]
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the
Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required
to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes [ X ] No [
]
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any,
every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this
chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such
files). Yes [ X ] No [
]
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405) is not
contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [ X ]
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or
a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting
company” in Rule 12b-2 of the Exchange Act. (Check one):
Large Accelerated Filer [ X ]
Non-accelerated filer [
Accelerated Filer [
Smaller Reporting Company [
]
]
]
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange
Act). Yes [
] No [ X ]
As of June 30, 2010, the registrant had 26,576,278 shares of its Common Stock outstanding. The aggregate market value
of these shares of Common Stock (based upon the closing price of these shares on the New York Stock Exchange on that
date) held by non-affiliates was $1,144,884,863.
At February 22, 2011, 26,668,712 shares of the registrant’s Common Stock (the only class of Common Stock) were
outstanding.
Portions of the Proxy Statement of the registrant, to be filed in connection with the 2011 Annual Meeting of Shareholders,
are incorporated by reference in Part III.
DOCUMENTS INCORPORATED BY REFERENCE
NORTHWEST NATURAL GAS COMPANY
Annual Report to Securities and Exchange Commission
on Form 10-K
For the Fiscal Year Ended December 31, 2010
Table of Contents
PART I
Item 1.
Glossary of Terms . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Forward-Looking Statements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Business . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
General . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Business Segments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Local Gas Distribution . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Gas Storage . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Regulation and Rates . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Environmental Issues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Employees . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Additions to Infrastructure . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Executive Officers of the Registrant
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Available Information . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 1A. Risk Factors . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 1B. Unresolved Staff Comments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 2.
Legal Proceedings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 3.
PART II
Item 5.
Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer
Purchases of Equity Securities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Selected Financial Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 6.
Item 7.
Management’s Discussion and Analysis of Financial Condition and Results of Operations . . .
Item 7A. Quantitative and Qualitative Disclosures About Market Risk . . . . . . . . . . . . . . . . . . . . . . . . . . .
Financial Statements and Supplementary Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 8.
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure . . .
Item 9.
Item 9A. Controls and Procedures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 9B. Other Information . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
PART III
Item 10.
Item 11.
Item 12.
Item 13.
Item 14.
Directors, Executive Officers and Corporate Governance . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Executive Compensation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder
Matters . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Certain Relationships and Related Transactions and Director Independence . . . . . . . . . . . . . . .
Principal Accountant Fees and Services . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
PART IV
Item 15.
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
SIGNATURES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Exhibits and Financial Statement Schedules
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GLOSSARY OF TERMS
Average weather: equal to the 25-year average
degree days based on temperatures established
in our 2003 Oregon general rate case.
Bcf: one billion cubic feet, a volumetric measure
of natural gas, roughly equal to 10 million
therms.
Btu: British thermal unit, a basic unit of thermal
energy measurement. One Btu equals the energy
required to raise one pound of water one degree
Fahrenheit at atmospheric pressure and 60
degrees Fahrenheit. One hundred thousand Btu’s
equal one therm.
Core utility customers: residential, commercial
and industrial customers on firm service from
the utility.
Cost of gas sold: the delivered cost of natural
gas sold to customers, including the cost of gas
purchased or withdrawn from storage inventory,
gains and losses from gas commodity hedges,
pipeline demand costs, seasonal demand cost
balancing adjustments, regulatory gas cost
deferrals and company gas use.
Decoupling: a rate mechanism, also referred to
as our conservation tariff, which is designed to
break the link between earnings and the quantity
of natural gas consumed by customers. The
design is intended to allow the utility to
encourage customers to conserve energy while
not adversely affecting its earnings due to
reductions in sales volumes.
Degree days: units of measure that reflect
temperature-sensitive consumption of natural
gas, calculated by subtracting the average of a
day’s high and low temperatures from 65
degrees Fahrenheit.
Demand cost: a component in all core utility
customer rates that covers the cost of securing
firm pipeline capacity to meet peak demand,
whether that capacity is used or not.
Firm service: natural gas service offered to
customers under contracts or rate schedules that
will not be disrupted to meet the needs of other
customers, particularly during cold weather.
General rate case: a periodic filing with state or
federal regulators to establish equitable rates and
balance the interests of all classes of customers
and our shareholders.
Interruptible service: natural gas service offered
to customers (usually large commercial or
industrial users) under contracts or rate schedules
that allow for interruptions when necessary to
meet the needs of firm service customers.
Liquefied natural gas (LNG): the cryogenic
liquid form of natural gas. To reach a liquid
form at atmospheric pressure, natural gas must
be cooled to approximately -260 degrees
Fahrenheit.
Purchased gas adjustment (PGA): a regulatory
mechanism for adjusting customer rates due to
changes in the cost to acquire and deliver natural
gas supplies.
Return on equity (ROE): a measure of
corporate profitability, calculated as net income
divided by average common stock
equity. Authorized ROE refers to the equity rate
approved by a regulatory agency for utility
investments funded by common stock equity.
Sales service: service provided whereby a
customer purchases both natural gas commodity
supply and transportation from the utility.
Therm: the basic unit of natural gas
measurement, equal to 100,000 Btu’s. An
average residential customer in our service area
uses about 700 therms annually in average
weather conditions.
Transportation service: service provided
whereby a customer directly purchases natural
gas commodity from a supplier but pays the
utility to transport the gas over its distribution
system to the customer’s facility.
Utility margin: utility gross revenues less the
associated cost of gas sold and applicable
revenue taxes. Also referred to as utility net
operating revenues.
Weather normalization: a rate mechanism that
allows the utility to adjust customers’ bills
during the winter heating season to reduce
variations in margin recovery due to fluctuations
from average temperatures.
1
Forward-Looking Statements
This report contains “forward-looking statements” within the meaning of the U.S. Private
Securities Litigation Reform Act of 1995. Forward-looking statements can be identified by words such
as “anticipates,” “intends,” “plans,” “seeks,” “believes,” “estimates,” “expects” and similar references
to future periods. Examples of forward-looking statements include, but are not limited to statements
regarding the following:
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plans;
objectives;
goals;
strategies;
future events or performance;
trends;
cyclicality;
earnings and dividends;
growth;
customer rates;
commodity costs;
operational performance and costs;
liquidity and financial positions;
project development and expansion;
competition;
procurement and development of new gas supplies;
liquefied natural gas;
estimated expenditures;
costs of compliance;
credit exposures;
potential efficiencies;
impacts of laws, rules and regulations;
tax liabilities or refunds;
outcomes and effects of litigation, regulatory actions, and other administrative matters;
projected obligations under retirement plans;
adequacy of, and shift in mix of, gas supplies;
approval and adequacy of regulatory deferrals; and
environmental, regulatory, litigation and insurance costs and recovery.
Forward-looking statements are based on our current expectations and assumptions regarding
our business, the economy and other future conditions. Because forward-looking statements relate to
the future, they are subject to inherent uncertainties, risks and changes in circumstances that are
difficult to predict. Our actual results may differ materially from those contemplated by the forward-
looking statements. We therefore caution you against relying on any of these forward-looking
statements. They are neither statements of historical fact nor guarantees or assurances of future
performance. Important factors that could cause actual results to differ materially from those in the
forward-looking statements are discussed at Item 1A., “Risk Factors” of Part I and Item 7. and
Item 7A., “Management’s Discussion and Analysis of Financial Condition and Results of Operations”
and “Quantitative and Qualitative Disclosures About Market Risk,” respectively, of Part II of this
report.
Any forward-looking statement made by us in this report speaks only as of the date on which it
is made. Factors or events that could cause our actual results to differ may emerge from time to time,
and it is not possible for us to predict all of them. We undertake no obligation to publicly update any
forward-looking statement, whether as a result of new information, future developments or otherwise,
except as may be required by law.
2
NORTHWEST NATURAL GAS COMPANY
PART I
ITEM 1. BUSINESS
General
Northwest Natural Gas Company (NW Natural) was incorporated under the laws of Oregon in
1910. Our company and its predecessors have supplied gas service to the public since 1859, and we
have been doing business as NW Natural since September 1997. We maintain operations in Oregon,
Washington and California and conduct businesses through NW Natural, its subsidiaries and joint
ventures. A reference to NW Natural (“we,” “us” or “our”) in this report means NW Natural and its
subsidiaries and joint ventures unless otherwise noted.
Business Segments
We operate in two primary reportable business segments, Local Gas Distribution and Gas
Storage. We also have other investments and business activities not specifically related to one of these
two reporting segments that we aggregate and report as Other.
Local Gas Distribution
We are principally engaged in the distribution of natural gas in Oregon and southwest
Washington. We refer to this business segment as our local gas distribution segment or utility. Our
local gas distribution segment involves building and maintaining a safe and reliable pipeline
distribution system, purchasing gas from producers and marketers, contracting for the transportation of
gas over pipelines from regional supply basins to our service territory, and reselling the gas to
customers subject to rates, terms and conditions approved by the Public Utility Commission of Oregon
(OPUC) or by the Washington Utilities and Transportation Commission (WUTC). Local gas
distribution also includes transporting gas owned by customers from the interstate pipeline connection,
or city gate, to the customers’ facilities for a fee, also approved by the OPUC or WUTC. In recent
years, approximately 90 percent of our consolidated assets and consolidated net income have been
related to the local gas distribution segment. The OPUC has allocated to us as our exclusive service
area a major portion of western Oregon, including the Portland metropolitan area, most of the
Willamette Valley and the coastal area from Astoria to Coos Bay. We also hold certificates from the
WUTC granting us exclusive rights to serve portions of three southwest Washington counties
bordering the Columbia River. We provide gas service in 124 cities and neighboring communities in
15 Oregon counties, as well as in 17 cities and neighboring communities in three Washington
counties. The city of Portland is the principal retail and manufacturing center in the Columbia River
Basin, and is a major port for trade with Asia.
At year-end 2010, we had approximately 674,000 utility customers, consisting of
approximately 611,000 residential, 62,000 commercial and 1,000 industrial customers. Approximately
90 percent of our utility customers are located in Oregon and 10 percent are located in
Washington. Industries we serve include: pulp, paper and other forest products; the manufacture of
electronic, electrochemical and electrometallurgical products; the processing of farm and food
products; the production of various mineral products; metal fabrication and casting; the production of
machine tools, machinery and textiles; the manufacture of asphalt, concrete and rubber; printing and
publishing; nurseries; government and educational institutions; and electric generation. No individual
customer or industry accounts for a significant portion of our utility revenues.
3
See Note 4 to the Consolidated Financial Statements for further information on total assets and
results of operations for the years ended December 31, 2010, 2009 and 2008.
Utility Gas Supply, Storage and Transportation
We meet the expected needs of our core utility customers through natural gas purchases from a
variety of suppliers. Our supply and delivery plan is based on forecasted customer requirements and
takes into account estimated load growth by type of customer, attrition, conservation, distribution
system constraints, interstate pipeline capacity and contractual limitations and the forecasted transfer of
large customers between sales service and transportation-only service. We perform sensitivity analyses
based on factors such as weather variations and price elasticity effects. We have a diverse portfolio of
short-, medium- and long-term firm gas supply contracts that are supplemented during periods of peak
demand with gas from storage facilities either owned by or contractually committed to us.
Gas Acquisition Strategy
Our goals in purchasing gas for our core utility customers are:
• Reliability—Ensuring a gas resource portfolio that is sufficient to satisfy core utility
customer requirements under extremely cold weather conditions as described below in
“Source of Supply—Design Year and Design Day Sendout”;
• Lowest reasonable cost—Applying strategies to acquire gas supplies at the lowest
reasonable cost for utility customers;
• Price stability—Making the best use of physical assets (e.g. gas storage and long-term gas
reserves) and financial instruments (e.g. financial hedge contracts such as commodity price
swaps and options) to manage commodity price volatility; and
• Cost recovery—Managing gas purchase costs prudently to minimize the risks associated
with regulatory review and recovery of gas acquisition costs.
To achieve our gas acquisition strategy, we employ a gas purchasing strategy that emphasizes a
diversity of supply, liquid trading points, price risk management strategies, asset optimization and
regulatory alignment as described below.
Diversity of supply. There are three primary means by which we diversify our gas supply
acquisitions: regional supply basins; contract types; and contract durations.
Our utility obtains its gas supplies primarily from three key regional supply basins. They are the
Alberta and British Columbia regions in Canada, and the Rocky Mountain region in the United
States. We believe that gas supplies available in the western United States and Canada are adequate to
serve our core utility requirements for the foreseeable future, but we continue to evaluate the long-term
supply mix based on projections of gas production in the U.S. Rocky Mountain regions as well as other
regions in North America. We believe that the cost of natural gas coming from western Canada and the
U.S. Rocky Mountain regions will continue to track the broader U.S. market prices. Several pipeline
projects have been built or are under construction to increase pipeline capacity out of the U.S. Rocky
Mountain region. Additionally, new technology to extract shale gas resources has developed in recent
years and has contributed to the increased availability of gas supply throughout North America. With
the recent increase in North American gas supplies and current natural gas price levels, we do not
foresee the need for a liquefied natural gas (LNG) import terminal in the Pacific Northwest at this time.
4
Although LNG could provide an additional source of gas supply to the region with potentially
competitive advantages, but based on current supply and demand outlook, we do not believe our region
currently requires an LNG supply source.
We typically enter into gas purchase contracts for:
year-round baseload supply;
additional baseload supply for the winter heating season;
•
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• winter heating season contracts where we have the option to call on all or some of the
•
supplies on a daily basis; and
spot purchases, taking into account forecasted customer requirements, storage injections
and withdrawals and seasonal weather fluctuations.
Other less frequent types of contracts include non-heating season baseload supplies,
non-heating season contracts where the supplier has the option to deliver gas to us on a daily basis, and
seasonal purchase and sale exchange contracts. We try to maintain a diversified portfolio of purchase
arrangements.
We also use a variety of multi-year contract durations to avoid re-contracting a majority of our
supplies every year. See “Core Utility Market Basic Supply,” below.
Liquid trading points. We purchase our gas supplies at liquid trading points to facilitate
competition and price transparency. These trading points include the NOVA Inventory Transfer (NIT)
point in Alberta (also referred to as AECO), Huntingdon/Sumas and Station 2 in British Columbia, and
multiple receipt points in the U.S. Rocky Mountains.
Price risk management strategies. Our four primary strategies for managing gas commodity
price risk are:
•
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•
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negotiating fixed prices either directly with gas suppliers or by purchasing long-term gas
reserves;
negotiating financial derivative instruments that effectively convert the floating price in a
physical gas supply contract to a fixed price (referred to as commodity price swaps);
negotiating financial derivative instruments that effectively set a ceiling or floor price, or
both, on a floating price physical supply contract (referred to as commodity price options
such as calls, puts, and collars); and
buying gas and injecting it into storage or buying gas reserves for longer term supply
deliveries. See “Cost of Gas Sold,” below.
Asset optimization. We use our gas supply, storage and transportation flexibility to capture
opportunities that emerge during the course of the year for gas purchases, sales, exchanges or other
means to manage net gas costs. In particular, our Mist underground storage facility provides flexibility
in this regard. In addition, in an effort to maximize the value of our gas storage and pipeline capacity,
we contract with an independent energy marketing company that optimizes our unused capacity when
those assets are not serving the needs of our core utility customers. This asset optimization service
performed by the independent energy marketing company produces cost savings that reduce our
utility’s cost of gas sold, and generates incremental revenues from a regulatory incentive sharing
mechanism that are included in our gas storage business segment.
5
Regulatory alignment. Mechanisms for gas cost recovery are designed to be fair and to
balance the interests of customers and shareholders. In general, utility rates are designed to recover the
cost of, but not earn a return on, the gas commodity sold, and we attempt to minimize risks associated
with gas cost recovery through:
•
•
•
re-setting customer rates annually for changes in forecasted gas costs and recovery of
customer deferrals of prior year’s actual versus forecasted gas costs (see Part II, Item 7.,
“Results of Operations—Regulatory Matters—Rate Mechanisms—Purchased Gas
Adjustment”);
aligning customer and shareholder interests, such as through the use of our Purchased Gas
Adjustment (PGA) incentive sharing mechanism, weather normalization, conservation, and
gas storage sharing mechanisms (see Part II, Item 7., “Results of Operations—Regulatory
Matters”); and
periodic review of regulatory deferrals with state regulatory commissions and key customer
groups.
Cost of Gas Sold
The cost of gas sold to core utility customers primarily consists of the purchase price paid to
suppliers, charges paid to pipeline companies to store and transport gas to our distribution system and
gains or losses related to gas commodity hedge contracts entered into in connection with the purchase
of gas for core utility customers.
Supply cost. Volatility in natural gas commodity prices has ebbed and flowed over the last
several years primarily due to shifts in the balance of supply and demand, which has been affected by a
variety of factors, including weather, customer growth, the level of production and availability of
natural gas, imports of natural gas, transportation constraints, availability of pipeline capacity,
transportation capacity cost increases, federal and state energy and environmental regulation and
legislation, the degree of market liquidity, supply disruptions, national and worldwide economic and
political conditions, and the price and availability of alternative fuels. With recent success in new
drilling technologies and substantial new supplies from shale gas formations around the U.S. and in
Canada, the supply of North American natural gas has increased dramatically, which has contributed to
a trend of lower gas prices. Additionally, we are in a favorable geographic position with respect to gas
production because of the proximity of our service territory to supply basins in western Canada and the
U.S. Rocky Mountains, where growth in gas production is expected to continue for the foreseeable
future.
Transportation cost. Pipeline transportation rates charged by Canadian pipelines and U.S.
interstate pipeline transportation service providers have been relatively stable over the last several
years, due in part to 2006 rate case settlement provisions for the U.S. interstate pipelines. These rates
periodically change when the Canadian pipelines and U.S. interstate pipelines file for rate change
approval from the Canadian National Energy Board or Federal Energy Regulatory Commission
(FERC), as applicable. Pipeline transportation rate increases or decreases are generally passed on to
our customers through annual PGA updates.
Gas price hedging. We seek to mitigate the effects of higher gas commodity prices and price
volatility on core utility customers by using our underground storage facilities strategically and by
entering into financial hedge contracts in an attempt to fix or limit the price of gas commodity
purchases. Realized gains or losses from financial commodity hedge contracts are treated as reductions
or increases to the cost of gas sold.
6
Managing the Cost of Gas Sold
We manage natural gas commodity price risk through active physical and financial hedging
programs. The intent of these hedging programs is to manage the price exposure for a majority of our
gas supply portfolio for the following gas contract year, which begins November 1 of each year. Our
financial hedge contracts make up a majority of our commodity price hedging activity, and these
contracts are with a variety of investment-grade credit counterparties, typically with credit ratings of
AA- or higher. See Part II, Item 7A., “Quantitative and Qualitative Disclosures About Market Risk—
Credit Risk—Credit exposure to financial derivative counterparties.” Under our financial hedge
program, we are allowed to enter into commodity swaps, puts, calls and collars with terms generally
ranging anywhere from one month to five years.
In addition to the prices that are hedged through financial contracts, we also own physical gas
supplies in storage. We purchase and inject gas into storage during the summer months when demand
and gas prices are generally lower. About 15 percent of our annual gas supply requirements is stored
for withdrawal during the winter months in five different storage facilities. We own and operate three
of these storage facilities located within our service territory, which reduces the need for additional
upstream pipeline capacity and provides cost savings and price stability. The other two storage
facilities are owned and operated by our primary pipeline supplier.
Source of Supply—Design Year and Design Day Sendout
The effectiveness of our gas supply program ultimately rests on whether we provide reliable
service at a reasonable cost to our core utility customers. For this purpose, we develop a composite
design year and include a three day design peak event that is based on the coldest weather experienced
over the last 20 years in our service territory. We also assume that all usage by interruptible customers
will be curtailed on the design day. Our projected sources of delivery for design day firm utility
customer sendout total approximately 9.1 million therms. Of this total, we are currently capable of
meeting nearly 60 percent of our firm customer maximum design day requirements with gas from
storage located within or adjacent to our service territory, while the remaining gas supply requirements
would be met by gas purchases under firm and recall gas purchase contracts. Optimal utilization of
storage on our design day reduces the cost and dependency on firm interstate pipeline
transportation. On January 5, 2004, we experienced our current record firm customer sendout of
7.2 million therms, and a total sendout of 8.9 million therms, on a day that was approximately 9
degrees Fahrenheit warmer than the design day temperature. That January 2004 cold weather event
lasted about 10 days, and the actual firm customer sendout each day provided data that confirmed our
load forecasting models required very little re-calibration. Similar cold temperatures experienced in
December 2008 and December 2009 produced very high sendout days, but firm sendout in December
2009 was still about 3 percent below our 2004 record. Accordingly, we believe that our supplies would
be sufficient to meet existing firm customer demand if we were to experience design day weather
conditions. We will continue to evaluate and update our forecasted requirements and incorporate
changes in our integrated resource plan (IRP) process (see “Integrated Resource Plan,” below).
7
The following table shows the sources of supply that are projected to be used to satisfy the
design day sendout for the 2010-2011 winter heating season:
Projected Sources of Utility Supply for Design Day Sendout
Sources of Utility Supply
Firm supply purchases
Mist underground storage (utility only)
Company-owned LNG storage
Off-system firm storage contracts
Recall agreements
Total
Therms
(in millions)
Percent
3.3
2.5
1.8
1.1
0.4
9.1
37
27
20
12
4
100
We believe the combination of the natural gas supply purchases under contract, our peaking
supplies and the transportation capacity held under contract on the interstate pipelines sufficiently
satisfies the needs of existing core utility customers and positions the utility to meet future
requirements.
Core Utility Market Basic Supply
We purchase natural gas for our core utility customers from a variety of suppliers located in
western Canada and the U.S. Rocky Mountain areas. Currently, about 60 percent of our supply comes
from Canada, with the balance coming primarily from the U.S. Rocky Mountain region. At
December 31, 2010, we have contracts with gas suppliers for deliveries ranging from three months to
four years, which provide for a maximum of 2.2 million therms of firm gas per day during the winter
heating season and 0.6 million therms per day during the entire year. These contracts have a variety of
pricing structures and purchase obligations. In addition, we have another 1.1 million therms per day of
firm gas supplies whereby we can purchase contract or spot gas supplies for delivery to our system
during the winter heating season. During 2010, we purchased a total of 715 million therms of gas under
contracts with the durations outlined in the chart below.
Contract Duration (primary term)
Percent of Purchases
Long-term (one year or longer)
Short-term (more than one month, less than one year)
Spot (one month or less)
Total
39
26
35
100
We regularly renew or replace our gas supply contracts with new agreements with a variety of
existing and new suppliers. Aside from the optimization of our core utility gas supplies by the
independent energy marketing company (see “Gas Acquisition Strategy—Asset optimization,” above),
no individual supplier provided more than 10 percent of our supply requirements. Firm year-round
supply contracts have remaining terms ranging from one to four years. Currently, all firm gas supply
contracts use price formulas tied to monthly index prices. We hedge a majority of these contracts each
year using financial derivative instruments as part of our gas purchasing strategy (see “Managing the
Cost of Gas Sold,” above).
In addition to our year-round contracts, we continue to contract in advance for firm gas supplies
to be delivered only during the winter heating season primarily under short-term contracts. During
2010, new short-term purchase contracts were entered into with 21 suppliers, which in addition to our
8
year round contracts provide for a total of up to 2.2 million therms per day during the 2010-2011
heating season. We intend to enter into new purchase contracts during 2011 for roughly the same
volume of gas with existing or new suppliers, as needed, to replace contracts that will expire in 2011.
We also buy gas on the spot market as needed to meet utility customer demand. We have
flexibility under the terms of some of our firm supply contracts, which enables us to purchase spot gas
in lieu of the firm contract volumes thereby allowing us to take advantage of more favorable pricing on
the spot market from time to time.
We continue to purchase a small amount of gas from a non-affiliated producer in the Mist gas
field in Oregon. The production area is situated near our underground gas storage facilities. Current
production supplies are less than 1 percent of our total annual purchase requirements. Production from
these wells varies as existing wells are depleted and new wells are drilled.
Core Utility Market Peaking Supply and Storage
We supplement our firm gas supply purchases with gas withdrawals from storage facilities we
own or that are contractually committed to us. Gas is generally purchased and injected into storage
during periods of low demand so that it can be withdrawn for use at a later time during periods of peak
demand. In addition to enabling us to meet our peak demand, these facilities make it possible to lower
the annual average cost of gas by allowing us to minimize our pipeline capacity demand costs and to
purchase gas for storage during the summer months when gas prices are generally lower.
Underground storage. We provide daily and seasonal peaking gas supplies to our core utility
customers from our underground gas storage facility in the Mist gas storage field. Including the latest
expansions in 2009, this facility has a maximum daily deliverability of 5.2 million therms and a total
working gas capacity of about 16 Bcf. In May 2009, a total of 100,000 therms per day of Mist storage
capacity that had previously been available for non-utility gas storage services was recalled and
committed to use for core utility customers. This was the first recalled capacity since 2004. There was
no Mist recall in 2010, but 100,000 therms per day is planned for recall in May 2011. Under our
regulatory agreement with the OPUC, non-utility gas storage at Mist was developed in advance of core
utility customer needs but can be recalled by the utility to serve utility customers as utility demand
increases. Storage capacity recalled by the utility is added to utility rate base at net book value and
tracked into utility rates in the annual PGA filing immediately following the recall, so there is minimal
regulatory lag in cost recovery. The core utility currently has 2.5 million therms per day of
deliverability and approximately 9.4 Bcf of working gas capacity committed from the Mist storage
facility.
We also have contracts with the Williams Companies’ Northwest Pipeline (Northwest Pipeline)
for firm gas storage from an underground facility at Jackson Prairie near Chehalis, Washington, and
from an LNG facility in Plymouth, Washington. Together, these two facilities provide us with daily
firm deliverability of about 1.1 million therms and total seasonal capacity of about 16 million therms.
Separate contracts with Northwest Pipeline provide for the transportation of these storage supplies to
our service territory. All of these contracts have reached the end of their primary terms, but we have
exercised our renewal rights that allow for annual extensions at our option.
Company-owned LNG storage. We own and operate two LNG storage facilities in our
Oregon service territory that liquefy gas for storage during the summer months so that it is available
9
for withdrawal during periods of peak demand in the winter heating season. These two facilities
provide a maximum combined daily deliverability of 1.8 million therms and a total seasonal capacity
of 16 million therms.
Recallable capacity from transportation customers. We also have contracts with one electric
generator and two industrial customers that together provide 390,000 therms per day of recallable
pipeline capacity and supply.
Transportation
Single transportation pipeline. Our local gas distribution system is directly connected to a
single interstate transmission pipeline, Northwest Pipeline. Although we are dependent on a single
pipeline, the pipeline’s gas flows are bi-directional and, as such, gas is transported into the Portland
metropolitan market from two directions: (1) the north, which brings supplies from the British
Columbia and Alberta supply basins; and (2) the east, which brings supplies from Alberta as well as
the U.S. Rocky Mountain supply basins. In 2003 a federal order requiring Northwest Pipeline to
replace its 26-inch mainline from the Canadian border to our service territory underscored the need for
pipeline transportation diversity. That replacement project was completed by Northwest Pipeline in
November 2006. We are pursuing options to further diversify our pipeline transportation
paths. Specifically, we are jointly developing plans to build a pipeline (Palomar) that would connect
TransCanada Pipelines Limited’s (TransCanada) Gas Transmission Northwest (GTN) interstate
transmission line to our local gas distribution system. In August 2007, we entered into an agreement
with GTN for the purpose of jointly developing, owning and operating this proposed
pipeline. Additionally, we entered into precedent agreements to become a shipper on the Palomar
pipeline. If constructed, this pipeline would provide another transportation path for gas purchases from
Alberta and the U.S. Rocky Mountains in addition to the one that currently moves gas through the
Northwest Pipeline system (See Part II, Item 7., “2011 Outlook—Strategic Opportunities—Pipeline
Diversification”).
Transportation agreements. The largest of our transportation agreements with Northwest
Pipeline extends through September 2013 and provides for firm transportation capacity of up to
2.1 million therms per day. Application to extend this contract through September 2018 has been filed
with FERC and is pending approval. This agreement provides access to natural gas supplies in British
Columbia and the U.S. Rocky Mountains.
Our second largest transportation agreement with Northwest Pipeline extends through
November 2011. It provides up to 1.0 million therms per day of firm transportation capacity from the
point of interconnection with Northwest Pipeline and GTN systems in eastern Oregon to our service
territory. Application to extend this contract through November 2016 has been filed with FERC and is
pending approval. GTN’s pipeline runs from the U.S./Canadian border through northern Idaho,
southeastern Washington and central Oregon to the California/Oregon border. We have firm long-term
capacity on GTN’s pipeline and two upstream pipelines in Canada, which match the amount of
Northwest Pipeline capacity northward into Alberta, Canada.
We also have an agreement with Northwest Pipeline that extends into 2044 for approximately
350,000 therms per day of firm transportation capacity from the U.S. Rocky Mountain
region. Additionally, in 2008 we executed an agreement with a third party to take assignment of their
firm transportation contract starting January 1, 2017, with the term extending through 2046. This
contract consists of 120,000 therms per day on Northwest Pipeline from the U.S. Rocky Mountain
region.
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In addition, we have firm long-term pipeline transportation contracts with two other major
transporters located in Canada. One contract extends through October 2014 and provides
approximately 580,000 therms per day of firm gas transportation from Station 2 in northern British
Columbia to the Huntingdon/Sumas connection with Northwest Pipeline at the U.S./Canadian
border. Another contract extends through October 2020 and provides approximately 480,000 therms
per day of firm transportation from southeastern British Columbia to the same Huntingdon/Sumas
connection with Northwest Pipeline. Our capacity on this second contract is matched with companion
contracts for pipeline capacity on the TransCanada systems in British Columbia and Alberta, allowing
purchases to be made from the gas fields of Alberta, Canada.
Rates. FERC establishes rates for interstate pipeline transportation service under long-term
agreements within the U.S., and Canadian authorities establish rates for service under agreements with
the Canadian pipelines over which we ship gas.
Integrated Resource Plan
The OPUC and WUTC have integrated resource planning processes (IRP) in which utilities
define different growth scenarios and corresponding resource acquisition strategies in an effort to:
• Evaluate supply and demand resources;
• Consider uncertainties in the planning process and the need for flexibility to respond to
changes; and
• Establish a plan for getting reliable service at the “least cost”.
In general, the IRP is filed biannually with both the OPUC and the WUTC. An annual update is
filed in Oregon in the off year. The OPUC acknowledges the IRP; whereas the WUTC provides notice
that our IRP met the requirements of the Washington Administrative Code. Commission
acknowledgment of the IRP does not constitute ratemaking approval of any specific resource
acquisition strategy or expenditure. However, the OPUC generally indicates that it would give
considerable weight in prudency reviews to utility actions that are consistent with acknowledged plans.
The WUTC has indicated that the IRP process is one factor it will consider in a prudency review. We
filed our 2011 IRP in Oregon in January 2011 and expect to file our IRP in Washington in March 2011.
Competition and Marketing
Competition with Other Energy Products
We have no direct competition in our service area from other natural gas distributors. However,
for residential customers we compete primarily with electricity, fuel oil and propane. We also compete
with electricity and fuel oil for commercial applications. In the industrial market, we compete with all
forms of energy, including competition from third-party sellers of natural gas commodity. Competition
among energy suppliers is based on price, efficiency, reliability, performance, market conditions,
technology, legislative policy, and environmental impact. Whether or not we provide the gas supplies
to serve our transportation-eligible customers, our net margins are not materially affected because we
generally do not make any margin on the commodity sold to our utility customers (see “Industrial
Markets,” below).
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Residential and Commercial Markets
The relatively low market saturation of natural gas in residential single-family dwellings in our
service territory, estimated at less than 60 percent, and our operating convenience and environmental
advantage over fuel oil, provides the potential for continuing growth from residential and commercial
conversions. In 2010, 5,906 net new residential customers were added, primarily from single- and
multi-family new construction, but also from the conversion of existing homes from oil, electric or
propane appliances to natural gas. The net increase of all new customers added in 2010 was
6,203. This represents a 12-month growth rate of 0.9 percent, which is up slightly from 2009 but still
well below historical growth rates due to the slow economic recovery and weak job market.
On an annual basis, residential and commercial customers typically account for about 55 to 60
percent of our utility’s total volumes delivered and about 85 to 90 percent of gross operating revenues,
while industrial customers account for about 40 to 45 percent of volumes and about 10 percent of gross
operating revenues. The remaining gross operating revenues are derived from miscellaneous services
and other regulatory revenues.
Industrial Markets
Competition to serve the industrial and large commercial market in the Pacific Northwest has
been relatively unchanged since the early 1990s in terms of numbers and types of
competitors. Competitors consist of gas marketers, oil/propane sellers and electric utilities.
Industrial customer businesses we serve include: pulp, paper and other forest products; the
manufacture of electronic, electrochemical and electrometallurgical products; the processing of farm
and food products; the production of various mineral products; metal fabrication and casting; the
production of machine tools, machinery and textiles; the manufacture of asphalt, concrete and rubber;
printing and publishing; nurseries; government and educational institutions; and electric generation. No
individual customer or industry group accounts for a significant portion of our industrial revenues or
margins.
The OPUC and WUTC have approved transportation tariffs under which we may contract with
customers to deliver customer-owned gas. Transportation tariffs are priced at our sales service rate less
the commodity cost included in that rate. Therefore, our transportation margins (i.e. sales minus the
cost of gas sold) are generally unaffected financially if industrial customers buy commodity supplies
directly from producers or marketers rather than purchasing gas from us, as long as they remain on a
tariff or contract with the same level of service. We do not generally make any margin on the sale of
the gas commodity. However, industrial customers may select between firm and interruptible service
as well as other levels of service, and these choices can positively or negatively affect margin. That is,
firm service has a higher profit margin than interruptible service. The relative level and volatility of
prices in the natural gas commodity markets, along with the availability of pipeline capacity to ship
customer-owned gas, are among the primary factors that have caused some industrial customers to
alternate between sales and transportation service or between higher and lower levels of service.
Our industrial tariffs include terms which are intended to give us more certainty in the level of
gas supplies we will need to purchase in order to serve this customer group. The terms include an
annual election cycle period, special pricing provisions for out-of-cycle changes and the requirement
that industrial customers on our annual weighted average PGA tariff must complete the agreed upon
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term of their service. In the case of customers switching out-of-cycle from transportation to sales
service, the customer will be charged the cost of incremental gas supply in accordance with our
regulatory tariff.
We have designed custom transportation service agreements with several of our largest
industrial customers. These agreements are primarily designed to provide transportation rates that are
competitive with the customer’s alternative capital and operating costs of installing direct connections
to Northwest Pipeline’s interstate pipeline system, which would allow them to bypass our local gas
distribution system. These agreements generally prohibit bypass during their terms. Due to the cost
pressures that confront a number of our largest customers competing in global markets, bypass
continues to be a competitive threat. Although we do not expect a significant number of our large
customers to bypass our system in the foreseeable future, we may experience further deterioration of
margin associated with customers transferring to special contracts where pricing is specifically
designed to be competitive with their bypass alternative.
Gas Storage
Our gas storage segment primarily consists of two underground natural gas storage facilities,
including the non-utility portion of our Mist gas storage facility near Mist, Oregon and our portion of
the Gill Ranch gas storage facility (Gill Ranch Storage, LLC or Gill Ranch) near Fresno, California.
Because transmission pipeline capacity and natural gas production are relatively flat over the course of
a year compared to the demand for natural gas, which fluctuates daily and seasonally, natural gas
storage facilities are needed to manage the flow and availability of gas supplies during periods of low
demand so these supplies can be stored and delivered into markets during periods of high demand. We
capitalize on the imbalance of supply and demand for natural gas by providing our gas storage
customers with the ability to store gas for resale or use in a higher value period. Our natural gas storage
facilities allow us to offer customers “multi-cycle” storage service, which permits them to inject and
withdraw natural gas multiple times a year, providing more flexibility to capture market opportunities.
Facilities
Mist Gas Storage Facility
We provide gas storage services to customers in the interstate and intrastate markets from our
Mist gas storage facilities located in Columbia County, Oregon, near the town of Mist. In 1989, the
Mist storage field began storage operations for our core local gas distribution customers. Since 2001,
we have made excess gas storage capacity at Mist available to interstate customers, and we have
developed new gas storage capacity at Mist in advance of core utility customer requirements to meet
the additional demands for interstate storage service. These interstate storage services are offered under
a limited jurisdiction blanket certificate issued by FERC. In addition, since 2005 we have offered firm
storage service in Oregon under an OPUC-approved rate schedule as an optional service to eligible
non-residential utility customers. Currently, the Mist facilities consist of seven depleted natural gas
reservoirs with a combined working gas capacity of 16 Bcf, a combined deliverability of
approximately 520,000 Dth/day, a central compression facility, gathering pipelines and other related
facilities.
In addition to earning revenue from customer storage contracts, we also use an independent
energy marketing company to provide asset optimization services for utility and non-utility storage and
transportation capacity under a contractual arrangement, the results of which are included in the gas
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storage business segment. Pre-tax income from gas storage at Mist and third-party optimization
services using our utility’s storage or transportation capacity is subject to revenue sharing with core
utility customers. In Oregon, 80 percent of the pre-tax income is retained by the gas storage segment
when the costs of the capacity used have not been included in utility rates, or 33 percent of the pre-tax
income is retained when the capacity costs have been included in utility rates. The remaining 20
percent and 67 percent of pre-tax income in each case are credited to a deferred regulatory account for
refund to our core utility customers. We have a similar sharing mechanism in Washington for pre-tax
income derived from gas storage services and third-party optimization activities.
Gill Ranch Gas Storage Facility
Gill Ranch, our subsidiary, has a joint project agreement with Pacific Gas and Electric
Company (PG&E) to develop, own and operate an underground natural gas storage facility near
Fresno, California. Gill Ranch holds a 75 percent undivided ownership interest in this facility. The
construction of this facility began in January 2010, and a majority of the construction work was
completed by October 2010. The facility began operations during the fourth quarter of 2010. Gill
Ranch is the sole operator of the facility.
The Gill Ranch storage facility currently consists of three depleted natural gas reservoirs,
twelve injection and withdrawal wells, a compressor station, dehydration and control equipment,
gathering lines, an electric substation, a natural gas pipeline that extends approximately 27 miles from
the storage field to an interconnection with the PG&E transmission system, and other related facilities.
We have rights to 75 percent of the available storage capacity at Gill Ranch. Our share of the working
gas capacity is designed to be approximately 15 Bcf, which we expect to achieve by the end of 2013.
Gill Ranch is offering storage services to the California market at market-based rates, subject to
the California Public Utilities Commission (CPUC) regulation of certain activities including, but not
limited to, service terms and conditions, tariff regulations, and security issuances.
Assets. The following table highlights certain important design information about our
non-utility gas storage assets.
Mist Gas Storage
Gill Ranch Storage
Storage
Capacity (Bcf)
Withdrawal
(MMcf/day) 3
Injection
(MMcf/day) 3
7 1
15 2
265
488
106
240
(1) Approximately 7 Bcf of Mist storage capacity is currently available to our gas storage segment.
The remaining 9 Bcf is used to provide gas storage services to the utility.
Total capacity for our share of the Gill Ranch facility is designed to be approximately 15 Bcf by
the end of 2013.
Expected maximum injection and withdrawal rates.
(2)
(3)
Gas Storage Operations
Asset optimization. With respect to the Mist gas storage facility, we contract with an
independent energy marketing company to optimize the value of our utility pipeline transportation
contracts, our utility gas supplies and our unused utility and non-utility storage assets, primarily
through the use of commodity transactions and pipeline capacity release transactions (see “Facilities—
Mist Gas Storage Facility,” above). We contract with the same independent energy marketing company
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to optimize the value of our unused storage assets at our Gill Ranch gas storage facility (see
“Facilities—Gill Ranch Gas Storage Facility,” above). The results of asset optimization at both
facilities are included in the gas storage business segment, except for amounts allocated to the utility
pursuant to a sharing agreement involving the use of utility assets.
Seasonality of business. Generally, Mist gas storage revenues do not follow seasonal patterns
similar to those experienced by the utility because most of the storage capacity is contracted with
customers for firm service, and rates for firm service are primarily in the form of fixed monthly
reservation charges and not affected by customer usage. However, there is seasonal variation from the
optimization of available surplus utility storage capacity and related transportation
capacity. Temporary surplus capacity is usually available during the spring and summer months when
the demand for gas by utility customers is low.
Although we expect much of the storage revenue at Gill Ranch to be in the form of fixed
monthly demand charges, we expect that total cash flows from the Gill Ranch storage facility may be,
at least initially, more seasonal in nature than the Mist storage facility. We expect that in the initial
years of operation of Gill Ranch a relatively greater percentage of the capacity will be optimized by the
independent energy marketing company with whom we contract than is the case with Mist, resulting in
greater seasonality of revenue for that activity, which usually occurs more often in the winter months.
A significant portion of operating costs at Gill Ranch will include the energy and demand charges for
electricity used to drive the compressors. Because compression is used primarily for the injection of
gas rather than for withdrawal, we expect power costs to be incurred disproportionately in the months
of April through October.
Gas storage customers. For our Mist interstate storage services, firm service agreements with
customers are entered into with terms typically ranging from one to 10 years. Currently, our gas
storage revenues from Mist are derived primarily from firm storage service customers who provide
energy related services, including natural gas distribution, electric generation and energy
marketing. Three storage customers currently account for over 85 percent of our existing non-utility
gas storage capacity at Mist, with the largest customer accounting for about half of total
capacity. These three customers have contracts that expire at various dates through April 2017.
Customer contracts for firm storage capacity at Gill Ranch are as long as 28 years in duration
but, our intent in the early phases of operation, is to contract for terms ranging from one to seven years
duration. We currently have several storage contracts, with the largest single contract accounting for
approximately 13 percent of our design capacity; however, we are in a start-up period and have not
contracted for the full 2011-2012 contract year. Moreover, the California market served by Gill Ranch
is larger and has a greater diversity of prospective customers than the Pacific Northwest market served
by Mist. As such, we expect there to be less sensitivity to any single or fewer set of customers for Gill
Ranch. Current storage customers provide energy related services, including natural gas marketing and
electric generation.
Competitive conditions. Our Mist gas storage facility benefits from limited competition from
other Pacific Northwest storage projects primarily because of its geographic location. However,
competition from other storage providers in the Pacific Northwest region and Canada, as well as
competition for interstate pipeline capacity, does exist. In the future, we could face increased
competition from new or expanded gas storage facilities as well as from new natural gas pipelines,
marketers and alternative energy sources.
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Our Gill Ranch storage facility competes with a number of other storage providers, including
local integrated gas companies and other independent storage operators in the northern California gas
storage market. There is also ongoing development and proposed new construction of storage capacity
and expansions in northern California that could increase competition for Gill Ranch.
Interstate gas storage. The Mist gas storage facility currently provides firm and interruptible
gas storage services with related transportation services on the utility’s system to and from Mist to
interstate pipeline interconnections in order to serve customers in interstate commerce. The interstate
storage services, and maximum rates for these services, are authorized and regulated by the FERC. The
storage capacity used by this business segment has been developed as a non-utility investment by NW
Natural in advance of core utility customers’ requirements.
We do not expect the Gill Ranch storage facility to provide, nor is it currently authorized to
provide, interstate gas storage services.
Intrastate gas storage. The Mist gas storage facility provides intrastate gas storage services in
Oregon under an OPUC-approved rate schedule that includes service eligibility and site-specific
qualifications. The firm storage service rates, terms and conditions mirror the firm interstate storage
service regulated by the FERC, except that these Mist customers are located and served in Oregon.
The Gill Ranch storage facility provides intrastate storage services in California at market-
based rates under a CPUC-approved tariff that includes firm storage service, interruptible storage
service and park and loan storage services.
Storage Expansions.
Mist Storage Facility. While the Pacific Northwest storage markets have been negatively
impacted by lower gas prices and lack of price volatility, albeit less so than in California, we continue
to plan for expansion at our gas storage facilities near Mist, Oregon but currently do not have a set
timeline for development. We believe the earliest timeframe for moving forward with the next
expansion is 2013. In the meantime, we expect to continue working on preliminary design and project
scope, which will likely include the development of storage wells, potentially a second compression
station and additional pipeline gathering facilities that would enable future storage expansions.
Gill Ranch Storage Facility. Subject to market demand, project execution, available financing,
receipt of future permits, and other rights, we have the operational capacity to expand the Gill Ranch
facility beyond our and PG&E’s combined permitted capacity of 20 Bcf, without further expansion of
our takeaway pipeline system. Taking these considerations into account and with certain infrastructure
modifications, we currently estimate that the Gill Ranch storage facility could support an aggregate
storage capacity of around 40 Bcf, of which we would have the rights to an aggregate of 20 Bcf or 50
percent of total estimated storage capacity.
Other
We have non-utility investments and other business activities which are aggregated and
reported as a business segment called “Other.” Although in the aggregate these investments and
activities are not material, we identify and report them as a stand-alone segment because these
investments and activities are not specifically related to our utility or gas storage segments. This
segment primarily consists of an equity method investment in a joint venture to build and operate an
16
interstate gas transmission pipeline in Oregon (see Part II, Item 7., “2011 Outlook—Strategic
Opportunities—Pipeline Diversification,” below), a minority interest in other pipeline assets held by
our wholly-owned subsidiary NNG Financial, as well as other operating and non-operating expenses of
the parent company that cannot be charged to utility operations. Less than 1 percent of our
consolidated assets and consolidated net income are related to activities in the “Other” business
segment. See Note 4 for more information on total assets and results of operations for the three years
ended December 31, 2010.
Regulation and Rates
We are subject to regulation with respect to, among other matters, rates, terms of services, and
systems of accounts established by the OPUC, the WUTC, the FERC and, with respect to Gill Ranch,
the CPUC. The OPUC and WUTC also regulate our issuance of securities, as does the CPUC with
respect to Gill Ranch. Approximately 90 percent of our utility operating revenues are derived from
Oregon customers, and the balance is derived from Washington customers.
We file general rate case and rate tariff requests with the OPUC, WUTC and FERC to
periodically change the rates we charge our utility and storage customers. Gill Ranch has a tariff on file
with the CPUC and is authorized to charge market-based rates for the storage services offered under
such tariff. With certain exceptions, our most recent agreement with the OPUC precludes us from
filing a general rate case request before September 2011, but does not preclude us from filing other
types of rate adjustment requests. In 2008, we filed a general rate case in Washington that was
approved in December 2008 with the resulting changes to rates effective on January 1, 2009 (see Part
II, Item 7., “Results of Operations—Regulatory Matters—General Rate Cases,” below). We are
required under our Mist interstate storage certificate authority to file every five years either a petition
for rate approval or a cost and revenue study to change or justify maintaining the existing rates for the
interstate storage service. For further information, see Part II, Item 7., “Results of Operations—
Regulatory Matters,” below and “Business Segments—Gas Storage,” above.
Environmental Issues
Properties and Facilities
We have properties and facilities that are subject to federal, state and local laws and regulations
related to environmental matters. These laws and regulations may require expenditures over a long
timeframe to control certain environmental impacts. Estimates of liabilities for environmental response
costs are difficult to determine with precision because of the various factors that can affect their
ultimate disposition. These factors include, but are not limited to, the following:
•
•
•
•
•
•
•
the complexity of the site;
changes in environmental laws and regulations at the federal, state and local levels;
the number of regulatory agencies or other parties involved;
new technology that renders previous technology obsolete, or experience with existing
technology that proves ineffective;
the ultimate selection of a particular technology;
the level of remediation required; and
variations between the estimated and actual period of time that must be dedicated to
respond to an environmentally-contaminated site.
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We own, or previously owned, properties currently being investigated that may require
environmental response, including: a property in Multnomah County, Oregon that is the site of a
former gas manufacturing plant that was closed in 1956 (Gasco site); a property adjacent to the Gasco
site that is now the location of a manufacturing plant owned by Siltronic Corporation (Siltronic site);
an area adjacent to the Gasco and the Siltronic sites in the Willamette River that has been listed by the
U.S. Environmental Protection Agency (EPA) as a Superfund site for which we have been identified as
one of a number of potentially responsible parties (Portland Harbor site); the former location of a gas
manufacturing plant operated by our predecessor that is outside the geographic scope of the current
Portland Harbor site (Front Street site); and the former site of three manufactured gas holding tanks
(Central Service Center site). Based on our current assessment of regulatory and insurance recovery of
environmental costs, we do not expect that the ultimate resolution of these matters will have a material
adverse effect on our financial condition, results of operations or cash flows; however, if it is
determined that both the insurance recovery and future rate recovery of such costs are not probable,
then the costs not expected to be recovered will be charged to expense in the period such determination
is made and could have a material impact on our financial condition or results of operations. See Note
15 for a further discussion of potential environmental responses, related costs and regulatory and
insurance recovery.
Greenhouse Gases Issues
We recognize that our businesses are likely to be impacted by carbon constraints. A variety of
legislative and regulatory measures to address greenhouse gas emissions are in various phases of
discussion or implementation. These include proposed international standards, proposed federal
legislation, proposed or enacted federal regulations, and proposed or enacted state actions to develop
statewide or regional programs, each of which has imposed or would impose measures to achieve
reductions in greenhouse gas emissions. For example, in December 2009, the EPA published its
findings that concentrations of carbon dioxide, methane and other greenhouse gases present an
endangerment to human health and the environment as drivers of climate change, and that emissions
from motor vehicles contribute to that threat. Based on these findings by the EPA, the agency
proceeded with the adoption and implementation of regulations to regulate emissions of greenhouse
gases starting in January 2011 from new motor vehicles and from stationary sources of air pollution
such as power plants and oil refineries. One of these new regulations, which the EPA refers to as the
“Tailoring Rule,” requires that permits held by larger sources of air pollution address greenhouse
gases, and also requires additional permitting and implementation of best available control technology
for limiting greenhouse gas emissions at certain new facilities and at existing facilities when they
implement modifications that increase emissions of greenhouse gases above threshold levels. Lawsuits
have been filed challenging the EPA’s regulation of greenhouse gas emissions and members of the
U.S. Congress have discussed proposing legislation that would limit the EPA’s ability to regulate
greenhouse gas emissions.
In September 2009, the EPA issued a final rule requiring the annual reporting of greenhouse
gas emissions from certain industries, specified large greenhouse gas emission sources, and facilities
that emit 25,000 metric tons or more of CO2 equivalents per year. The first reports are due by
March 31, 2011 for emissions occurring on or after January 1, 2010. Under this reporting rule, local
gas distribution companies are required to report system throughput to the EPA on an annual basis. The
EPA also issued additional greenhouse gas reporting regulations in November 2010 requiring the
annual reporting of fugitive emissions from our operations. The first report under these more recent
regulations is due by March 31, 2012.
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The outcome of these and other international, federal and state climate change initiatives cannot
be determined at this time, but these initiatives could produce a number of results including potential
new regulations, legal actions, additional charges to fund energy efficiency activities, or other
regulatory actions. The adoption and implementation of any regulations limiting emissions of
greenhouse gases from our operations could require us to incur costs to reduce emissions of
greenhouse gases associated with our operations, which could result in an increase in the prices we
charge our customers or a decline in the demand for natural gas. On the other hand, because natural gas
is a fossil fuel with relatively low carbon content, it is also possible that future carbon constraints could
create additional demand for natural gas for electric production, direct use in homes and businesses and
as a reliable and relatively low-emission back-up fuel source for alternative energy sources.
We continue to take steps to address future greenhouse gas emission issues, including actively
participating in policy development through the Oregon Governor’s Task Force on Climate Change
and leading efforts within the American Gas Association to promote the enactment of fair federal
climate change legislation. We continue to engage in policy development and in identifying ways to
reduce greenhouse gas emissions associated with our operations and our customers’ gas use, including
the introduction of the Smart Energy program, which allows customers to contribute funds to projects
that offset greenhouse gases produced from their natural gas use.
Employees
At December 31, 2010, our workforce employed by NW Natural consisted of 607 members of
the Office and Professional Employees International Union (OPEIU), Local No. 11, AFL-CIO, and
421 non-union employees. Our labor agreement with members of OPEIU that covers wages, benefits
and working conditions extends to May 31, 2014, and thereafter from year to year unless either party
serves notice of its intent to negotiate modifications to the collective bargaining agreement.
NW Natural Gas Storage, LLC (NWN Gas Storage) is our only subsidiary that currently has
employees. Its workforce currently consists of 19 non-union employees. NWN Gas Storage receives
certain services from NW Natural, and as such reimburses NW Natural for those services pursuant to a
Shared Services Agreement. Gill Ranch also receives certain services under a similar agreement with
NW Natural.
Additions to Infrastructure
We make capital expenditures in order to maintain and enhance the safety and integrity of our
pipelines, terminals, storage facilities and related assets, to expand the reach or capacity of those assets,
or improve the efficiency of our operations to pursue new business opportunities. We expect to make a
significant level of capital expenditures for additions to utility and gas storage infrastructure over the
next five years, reflecting continued investments in customer growth, technology, distribution system
enhancements and gas storage facilities. In 2011, utility capital expenditures are estimated to be
between $95 and $105 million, and non-utility capital investments are estimated to be between $5 and
$15 million. For the years 2011-2015, capital expenditures for the utility are estimated to be between
$400 and $500 million, while the amount for gas storage and other investments after 2011 will depend
largely on future decisions about potential opportunities in gas storage and pipeline projects.
Executive Officers of the Registrant
For information concerning our executive officers, see Part III, Item 10.
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Available Information
We file annual, quarterly and special reports and other information with the Securities and
Exchange Commission (SEC). Reports, proxy statements and other information filed by us can be read
and copied at the Public Reference Room of the SEC, 100 F Street, N.E., Washington, D.C. 20549.
You can obtain additional information about the Public Reference Room by calling the SEC at
1-800-SEC-0330. The SEC also maintains a website (http://www.sec.gov) that contains reports, proxy
statements and other information that we file electronically. In addition, we make available on our
website (http://www.nwnatural.com), our annual report on Form 10-K, quarterly reports on Form
10-Q, current reports on Form 8-K, and amendments to those reports, as well as proxy materials, filed
or furnished pursuant to Section 13(a) or 15(d) and Section 14 of the Securities Exchange Act of 1934,
as amended (Exchange Act), as soon as reasonably practicable after we electronically file such material
with, or furnish it to, the SEC.
We have adopted a Code of Ethics for all employees and officers, and a Financial Code of
Ethics that applies to senior financial employees, both of which are available on our website. We
intend to disclose amendments to, and any waivers from, either code on our website. Our Corporate
Governance Standards, Director Independence Standards, charters of each of the committees of the
Board of Directors and additional information about us are also available at the website. Copies of
these documents may be requested, at no cost, by writing or calling Shareholder Services, NW Natural,
One Pacific Square, 220 N.W. Second Avenue, Portland, Oregon 97209, telephone 503-226-4211.
ITEM 1A. RISK FACTORS
Our business and financial results are subject to a number of risks and uncertainties, many of
which are not within our control. When considering any investment in our securities, investors should
carefully consider the following information, as well as information contained in the caption “Forward
Looking Statements,” Item 7A., and other documents we file with the SEC. This list is not exhaustive
and the order of presentation does not reflect management’s determination of priority or likelihood.
Additionally, our listing of risk factors that primarily affect one of our business segments does not
indicate that such risk factor is inapplicable to our other business segments.
Risks Related to our Business Generally
Economic risk. Changes in the economy and in the financial markets may have a negative
impact on our financial condition and results of operations.
Changes in economic activity in our markets and in global financial markets can result in a
decline in energy consumption, which could have a negative effect on our financial condition and
results of operations. In recent years, the U.S. and world economies have slowed, credit markets have
tightened, unemployment rates and mortgage defaults have risen, and the value of homes and other
personal as well as business investments have declined, which has adversely affected the income and
financial resources of many domestic households and businesses. It is unclear whether the federal
responses to these conditions will lessen the severity or duration of this economic downturn, or could
possibly trigger inflationary conditions. Our operations and financial results are affected by these
economic conditions. Less new housing construction, fewer conversions to natural gas, fewer customer
additions, higher levels of residential foreclosures and vacancies, higher borrowing rates, and personal
and business bankruptcies or reduced spending could all result in a decline in energy consumption and
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customer growth, a slowing of collections from our customers, and a higher than normal level of
accounts receivable and bad debts, all of which could have a negative effect on our financial condition
and results of operations.
Regulatory risk. Regulation of our businesses, including changes in the regulatory
environment in general, and failure of regulatory authorities to approve rates which provide for timely
recovery of our costs and an adequate return on invested capital in particular, may adversely impact
our financial condition and results of operations.
The OPUC and WUTC have general regulatory authority over our utility business in Oregon
and Washington, respectively, including the rates charged to customers, authorized rates of return on
capital invested, the amounts and types of securities we may issue, services we provide, facilities we
own or operate, terms of customer services, system of accounts, the nature of investments we may
make, safety standards, deferral and recovery of various expenses, including, but not limited to,
pipeline replacement and environmental remediation costs, transactions with affiliated interests,
actions investors may take with respect to our company and other matters. Similarly, FERC has
regulatory authority over our interstate gas storage services, and the CPUC has regulatory authority
over our Gill Ranch gas storage operations.
The rates we charge to customers must be approved by the applicable regulatory agencies. Our
utility and gas storage rates are generally designed to allow us to recover the costs of providing such
services and to earn an adequate return on our capital investment. However, the rates charged to
customers of Gill Ranch for gas storage services are based on negotiated rates (i.e. market-based rates)
rather than on our recovery of costs plus a reasonable return on our investment (i.e. cost-based
rates). We expect to continue to make expenditures to expand, improve and operate our utility
distribution and gas storage systems. Regulators can deny such expansions or improvements or
recovery of expenditures we make if they find that such expenditures were not prudently incurred
according to their regulatory standards.
In addition, in the normal course of business we may place assets in service or incur higher than
expected levels of operating expense before rate cases can be filed to recover those costs—this is
commonly referred to as “regulatory lag.” The failure of any regulatory commission to approve
requested rate increases on a timely basis to recover increased costs or to allow an adequate return
could adversely impact our financial condition and results of operations.
Business development risk. The development, construction, startup and operation of our
business development projects may involve unanticipated changes or delays that could negatively
impact our costs as well as our financial condition, results of operations and cash flows.
Business development projects involve many risks. We are currently engaged in several
business development projects, including the early planning and development stage on the Palomar gas
transmission pipeline in Oregon and the final completion of the first phase of construction at the Gill
Ranch gas storage facility in California. We may also engage in other business development projects in
the future, including expansion of our gas storage facilities at Mist or Gill Ranch or the investment in
long-term gas reserves. With respect to these projects, we may not be able to obtain required
governmental permits and approvals, or financing, to complete our projects in a cost-efficient or timely
manner. If we do not obtain the necessary regulatory approvals in a timely manner, development
projects may be delayed or abandoned. There also may be startup and construction delays, construction
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cost overruns, inability to negotiate acceptable agreements such as rights-of-way, easements,
construction, gas supply or other material contracts, changes in customer demand, public opposition to
projects, changes in market prices, and operating cost increases. Additionally, natural gas storage and
transportation markets are highly competitive, both within the natural gas industry and with alternative
sources of energy. To fund our business development projects, we will need to secure financing from
willing investors at reasonable costs. If credit markets are inaccessible, we may be unable to finance
our business development projects at acceptable interest rates or within a scheduled timeframe for
completing the project. Similarly, an inability to obtain the necessary state permits, or arrange for
sufficient supplier commitments could impact the viability of the Palomar pipeline. One or more of
these events may mean that our equity investments could become impaired and such impairment could
have an adverse effect on our financial condition and results of operations.
Joint partner risk. Investing in business development projects through partnerships, joint
ventures or other business arrangements decreases our ability to manage certain risks and could
adversely impact our financial condition, results of operations and cash flows.
We use joint ventures and other business arrangements to manage and diversify the risks of
certain utility and non-utility development projects, including Palomar and Gill Ranch, and we may
acquire interests in other similar projects in the future. Under these types of business arrangements, we
may not be able to fully direct the management and policies of the business relationships, and other
participants in those relationships may take action contrary to our interests including making
operational decisions that could affect our costs and liabilities related to a project. In addition, other
participants may withdraw from the project, become financially distressed or bankrupt, or have
economic or other business interests or goals that are inconsistent with ours. Although we have
contractual and other legal remedies to enforce our interests, if a participant in one of these business
arrangements acts contrary to our interests, it could adversely impact the project as well as our
financial condition, results of operations and cash flows.
Global climate change risk. Management expects that future legislation may impose carbon
constraints to address global climate change exposing us to regulatory and financial risk. Additionally,
certain properties and facilities may be subject to physical risks associated with climate change.
There are a number of new international, federal and state legislative and regulatory initiatives
being proposed and adopted in an attempt to measure, control or limit the effects of global warming
and overall climate change, including greenhouse gas emissions such as carbon dioxide. The adoption
of current or future proposed legislation by the U.S. Congress or similar legislation by states, or the
adoption of related regulations by federal or state regulatory bodies such as the EPA, imposing
reporting obligations on, or limiting emissions of greenhouse gases from our equipment or operations
could have far-reaching and significant impacts on our business as well as the broader energy
industry. Such current or future legislation or regulation could also impose on us operational
requirements or restrictions or additional charges to fund energy efficiency initiatives. Such initiatives
could result in us incurring additional costs to comply with the imposed restrictions, provide a cost
advantage to energy sources other than natural gas, reduce demand for natural gas, impose costs or
restrictions on end users of natural gas, impact the prices we charge our customers, impose on us
increased costs associated with the adoption of new infrastructure and technology to respond to such
requirements, and may impact cultural perception of our service or products negatively, diminishing
the value of our brand, all of which could adversely affect our business practices, financial condition
and results of operations.
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Climate change may cause physical risks, including an increase in sea level, intensified storms,
water scarcity and changes in weather conditions, such as changes in precipitation, average
temperatures and extreme wind or other climate conditions. A significant portion of the nation’s gas
infrastructure is located in areas susceptible to storm damage that could be aggravated by wetland and
barrier island erosion, which could give rise to gas supply interruptions and price spikes.
These and other physical changes could result in changes in customer demand, increased costs
associated with repairing and maintaining distribution systems resulting in increased maintenance and
capital costs, increased financing needs, limits on our ability to meet peak customer demand, increased
regulatory oversight, and lower customer satisfaction. Also, to the extent that climate change adversely
impacts the economic health of our region, it may adversely impact customer demand and
revenues. Such physical risks could have an adverse effect on our financial condition, results of
operations, and cash flows.
Operating risk. Transporting and storing natural gas involves numerous risks that may result
in accidents and other operating risks and costs, some or all of which may not be fully covered by
insurance, and which could adversely affect our financial condition, results of operations and cash
flows.
Our operations are subject to all of the risks and hazards inherent in the businesses of natural
gas distribution and storage, including:
•
•
•
•
•
•
earthquakes, floods, storms, landslides and other adverse weather conditions and hazards;
leaks or other losses of natural gas or other hydrocarbons as a result of the malfunction of
equipment and facilities;
damages from third parties, including construction, farm and utility equipment or other
surface users;
operator errors;
negative unpredicted performance by our storage reservoirs that could cause us to fail to
meet expected or forecasted operational levels or contractual commitments to our
customers;
problems maintaining, or the malfunction of, pipelines, wellbores and related equipment
and facilities that form a part of the infrastructure that is critical to the operation of our gas
distribution and storage facilities;
collapse of storage caverns;
•
• migration of natural gas through faults in the rock or to some area of the reservoir where
•
•
existing wells cannot drain the gas effectively;
blowouts (uncontrolled escapes of gas from a pipeline or well) or other accidents, fires and
explosions; and
risks and hazards inherent in the drilling operations associated with the development of the
gas storage facilities and/or wells.
These risks could result in personal injury or loss of human life, damage to and destruction of
property and equipment, pollution or other environmental damage, breaches of our contractual
commitments, and may result in curtailment or suspension of our operations, which in turn could lead
to significant costs and/or lost revenues. Further, because our pipeline, storage and distribution
facilities are in or near populated areas, including residential areas, commercial business centers, and
industrial sites, any loss of human life or adverse financial results resulting from such events could be
23
significant. Natural gas that moves outside of the effective drainage area through migration could be
permanently lost and will need to be replaced. Additionally, we may not be able to obtain the level or
types of insurance we desire, and the insurance coverage we do obtain may contain large deductibles or
fail to cover certain hazards or cover all potential losses. The occurrence of any operating risks not
covered by insurance could adversely affect our financial condition, results of operations and cash
flows.
Business continuity risk. We may be adversely impacted by local or national disasters,
pandemic illness, terrorist activities and other extreme events to which we may not able to promptly
respond.
Local or national disasters, pandemic illness, terrorist activities and other extreme events are a
threat to our assets and operations. Companies in our industry may face a heightened risk due to
exposure to actual acts of terrorism that could target or impact our natural gas distribution,
transmission and storage facilities and result in a disruption in our operations and ability to meet
customer requirements. In addition, the threat of terrorist activities could lead to increased economic
instability and volatility in the price of natural gas that could affect our operations. Threatened or
actual national disasters or terrorist activities may also disrupt capital markets and our ability to raise
capital, or impact our suppliers or our customers directly. Local disaster or pandemic illness could
result in part of our workforce being unable to operate or maintain our infrastructure or perform other
tasks necessary to conduct our business. We maintain emergency planning and training programs to
remain ready to respond to events that could cause business interruption. However, a slow or
inadequate response to events may have an adverse impact on operations and earnings. We may not be
able to obtain sufficient insurance to cover all risks associated with local and national disasters,
pandemic illness, terrorist activities and other events, which could increase the risk that an event could
adversely affect our operations or financial results.
Employee benefit risk. The cost of providing pension and postretirement healthcare benefits is
subject to changes in pension assets and liabilities, changing employee demographics and changing
actuarial assumptions, which may have an adverse effect on our financial condition.
We provide pension plans and postretirement healthcare benefits to most eligible full-time
employees and retirees. Our cost of providing such benefits is subject to changes in the market value of
our pension assets, changes in employee demographics, including longer life expectancies of
beneficiaries, increases in healthcare costs, current and future legislative changes, including but not
limited to the Health Care Reform Act in 2010, and various actuarial calculations and assumptions.
The actuarial assumptions used to calculate our future pension and postretirement healthcare expense
may differ materially from actual results due to significant market fluctuations and changing
withdrawal rates, wage rates, interest rates and other factors. These differences may result in an
adverse impact on the amount of pension contributions, pension expense or other postretirement
benefit costs recorded in future periods. Sustained declines in equity markets and reductions in bond
prices may have a material adverse effect on the value of our pension fund assets. In these
circumstances, we may be required to recognize increased contributions and pension expense earlier
than we had planned to the extent that the value of pension assets is less than the total anticipated
liability under the plans, which could have a negative impact on financial condition, results of
operations and cash flows.
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Workforce risk. Our business is heavily dependent on being able to attract and retain
qualified employees and maintain a competitive cost structure with market-based salaries and
employee benefits, and workforce disruptions could adversely affect our operations and results.
Our ability to implement business strategy and serve our customers is dependent upon our
continuing ability to attract and retain talented professionals and a technically skilled workforce, and
being able to transfer the knowledge and expertise of our workforce to new employees as our aging
employees retire. Without an appropriately skilled workforce, our ability to provide quality service and
meet our regulatory requirements will be challenged and this could negatively impact our
earnings. Additionally, within our utility segment a majority of our workers are represented by the
Office and Professional Employees International Union Local No.11 AFL-CIO (the Union) and are
covered by a collective bargaining agreement that will expire May 31, 2014. Disputes with the Union
over terms and conditions of the agreement could result in instability in our labor relationship and work
stoppages that could impact the timely delivery of gas and other services from our utility and Mist gas
storage, which could strain relationships with customers and state regulators and cause a loss of
revenues which could adversely affect our results of operations. Our collective bargaining agreement
may also increase the cost of employing our utility segment workforce, affect our ability to continue
offering market-based salaries and employee benefits, limit our flexibility in dealing with our
workforce, and limit our ability to change work rules and practices and implement other efficiency-
related improvements to successfully compete in today’s challenging marketplace.
Legislative and taxing authority risk. We are subject to governmental regulation, and
compliance with local, state and federal requirements, including taxing requirements, and unforeseen
changes in or interpretations of such requirements could affect our financial condition and results of
operations.
We are subject to regulation by federal, state and local governmental authorities. We are
required to comply with a variety of laws and regulations and to obtain authorizations, permits,
approvals and certificates from governmental agencies in various aspects of our business. We cannot
predict with certainty the impact of any future revisions or changes in interpretations of existing
regulations or the adoption of new laws and regulations applicable to them. Changes in regulations or
the imposition of additional regulations could negatively influence our operating environment and
results of operations. For example, Oregon law required that utilities not collect in rates more income
taxes than they actually pay to taxing authorities. If amounts paid differ from amounts collected by
more than $100,000, then we are required to implement a rate schedule with an automatic adjustment
to refund or collect the difference.
Additionally, changes in federal, state or local tax laws and their related regulations, or
differing interpretation or enforcement of applicable law by a federal, state or local taxing authority,
could result in substantial cost to us and negatively affect our results of operations. Tax law and its
related regulations and case law are inherently complex and dynamic. Disputes over interpretations of
tax laws may be settled with the taxing authority in examination, upon appeal or through litigation. Our
judgments may include reserves for potential adverse outcomes regarding tax positions that have been
taken that may be subject to challenge by taxing authorities. Changes in laws, regulations or adverse
judgments may negatively affect our financial condition and results of operations.
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Environmental regulation risk. We are subject to environmental regulations which could
adversely affect our operations or financial results.
We are subject to laws, regulations and other legal requirements enacted or adopted by federal,
state and local governmental authorities relating to protection of the environment and health and safety
matters, including those legal requirements that govern discharges of substances into the air and water,
the management and disposal of hazardous substances and waste, the clean-up of contaminated sites,
groundwater quality and availability, plant and wildlife protection, as well as work practices related to
employee health and safety.
Environmental legislation also requires that our facilities, sites and other properties associated
with our operations be operated, maintained, abandoned and reclaimed to the satisfaction of applicable
regulatory authorities. Failure to comply with these laws, regulations, permits and licenses may expose
us to fines, penalties or interruptions in our operations that could adversely affect our financial results.
In addition, existing environmental regulations may be revised or our operations may become subject
to new regulations, which could negatively affect our financial condition and results of operations.
Environmental liability risk. Certain of our properties and facilities may pose environmental
risks requiring remediation, the cost of which could adversely affect our financial condition, results of
operations and cash flows.
We own, or previously owned, properties that require environmental remediation or other
action. We accrue all material loss contingencies relating to these properties, but our results of
operations may be adversely affected to the extent that estimates of the probable costs increase
significantly as additional information becomes available and to the extent we are not able to recover
the incremental cost from insurance or through customer rates. A regulatory asset at the utility has
already been recorded for estimated costs pursuant to a deferral order from the OPUC. To the extent
we are unable to recover these deferred costs in utility customer rates or through insurance, we would
be required to reduce our regulatory asset which would adversely affect our results of operations and
financial condition. In addition, disputes may arise between potentially responsible parties and
regulators as to the severity of particular environmental matters and what remediation efforts are
appropriate. These disputes could lead to adversarial administrative proceedings or litigation, with
associated costs and uncertain outcomes.
We cannot predict with certainty the amount or timing of future expenditures related to
environmental investigation and remediation that may be required, or disputes arising in relation
thereto, because of the difficulty of estimating such costs. There is also uncertainty in quantifying
liabilities under environmental laws that impose joint and several liability on all potentially responsible
parties. Moreover, there are no assurances that existing environmental regulations will not be revised
or that new stricter regulations seeking to protect the environment will not be adopted or become
applicable to us. Revised environmental regulations which result in increased compliance costs or
additional operating restrictions could have an adverse effect on our financial condition and results of
operations, particularly if those costs are not fully recoverable from insurance or through utility
customer rates.
Safety regulation risk. We may experience increased federal, state and local regulation of the
safety of our operations, which could adversely affect our operating costs and financial results.
We are committed to constantly monitoring and maintaining our pipeline and distribution
system and storage operations to ensure that natural gas is stored and delivered safely, reliably and
26
efficiently. The safety and protection of the public, our customers and our employees is our top
priority. However, primarily due to the recent unfortunate pipeline incident in California, we anticipate
companies with natural gas pipelines may be subject to even greater federal, state and local oversight
over the safety of their operations in the future. Accordingly, the costs of complying with such
increased regulations may have an impact on our future capital and operating costs and ultimately our
financial results.
Hedging risk. Our risk management policies and hedging activities cannot eliminate the risk of
commodity price movements and other financial market risks, and our hedging activities may expose
us to additional liabilities for which rate recovery may be disallowed, which could result in an adverse
impact on our operating revenues, costs, derivative assets and liabilities and operating cash flows.
In our utility segment, our gas purchasing requirements expose us to risks of commodity price
movements, while our use of debt and equity financing exposes us to interest rate, liquidity and other
financial market risks. We attempt to manage these exposures and mitigate our risks through adherence
to established risk limits and risk management procedures, including hedging activities that are in
accordance with our derivatives policy guidelines. These risk limits and risk management procedures
may not always work as planned and cannot entirely eliminate the risks associated with
hedging. Additionally, our hedging activities may cause us to incur additional expenses which could
adversely impact our financial condition, results of operations, and cash flows.
We do not hedge our entire interest rate or commodity cost exposure, and the unhedged
exposure will vary over time. Gains or losses experienced through hedging activities, including
carrying costs, generally flow through the PGA mechanism or are recovered in future general rate
cases, thereby limiting our exposure to earnings volatility on a year-to-year basis. However, the hedge
transactions we enter into for the utility are subject to a prudency review by the OPUC and WUTC,
and, if deemed imprudent, those expenses may be disallowed, which could have an adverse effect on
our financial condition and results of operations. In addition, actual business requirements and
available resources may vary from forecasts, which are used as the basis for our hedging decisions, and
could cause our exposure to be more or less than we anticipated. Moreover, if our derivative
instruments and hedging transactions do not qualify for hedge accounting under generally accepted
accounting standards, our hedges may not be effective and our results of operations and financial
condition could be adversely affected.
We also have credit-related exposure to derivative counterparties. In general, we require our
counterparties to have an investment-grade credit rating at the time the derivative instrument is entered
into, and we specify limits on the contract amount and duration based on each counterparty’s credit
rating. Nevertheless, counterparties owing us money or physical natural gas commodities could breach
their obligations. Should the counterparties to these arrangements fail to perform, we may be forced to
enter into alternative arrangements. In that event, our financial results could be adversely
affected. Although our valuations take into account the expected probability of default and the
potential loss due to a default by our counterparties, an actual default by a particular counterparty could
have a greater impact than we estimate. Additionally, under most of our hedging arrangements, any
downgrade of our senior unsecured long-term debt credit rating could allow our counterparties to
require us to post cash, a letter of credit or other form of collateral, which would expose us to
additional costs and may trigger significant increases in borrowing from our credit facilities if the
credit rating downgrade is below investment grade.
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Inability to access capital market risk. Our inability to access capital or significant increases
in the cost of capital could adversely affect our financial condition and results of operations.
Our ability to obtain adequate and cost effective short-term and long-term financing depends on
maintaining investment grade credit ratings as well as the existence of liquid and stable financial
markets. Our businesses rely on access to capital markets, including commercial paper, debt capital
markets and equity markets, to finance our operations, construction expenditures and other business
requirements, and to refund maturing debt that cannot be funded entirely by internal cash
flows. Disruptions in the capital markets could adversely affect our ability to access short-term and
long-term financing. Our access to funds under committed short-term credit facilities, which are
currently provided by a number of banks, is dependent on the ability of the participating banks to meet
their funding commitments. Those banks may not be able to meet their funding commitments if they
experience shortages of capital and liquidity. Disruptions in the bank or capital financing markets as a
result of economic uncertainty, changing or increased regulation of the financial sector, or failure of
major financial institutions could adversely affect our access to capital and negatively impact our
ability to run our business and make strategic investments.
A negative change in our current credit ratings, particularly below investment grade, could
adversely affect our cost of borrowing and/or access to sources of liquidity and capital. Such a
downgrade could further limit our access to borrowing under available credit lines. Additionally,
downgrades in our current credit ratings below investment grade could cause additional delays in
accessing the capital markets by the utility while we seek supplemental state regulatory approval,
which could hamper our ability to access credit markets on a timely basis. A credit downgrade could
also require additional support in the form of letters of credit, cash or other forms of collateral and
otherwise adversely affect our financial condition and results of operations.
Changes in accounting standards. Changes in accounting standards may adversely impact
our financial condition and results of operations.
The SEC is currently considering whether issuers in the United States should be required to
prepare financial statements in accordance with International Financial Reporting Standards (IFRS)
instead of the current generally accepted accounting principles (GAAP) in the United States. IFRS is a
comprehensive set of accounting standards promulgated by the International Accounting Standards
Board (IASB), which are currently in effect for most other countries in the world. The SEC has
indicated that it will decide in 2011 whether IFRS will be required for U.S. companies. If the SEC
decides to adopt IFRS, we expect that U.S. companies would not be required to report under these new
standards until 2015 or 2016 at the earliest. Unlike U.S. GAAP, IFRS does not currently provide an
industry accounting standard for rate-regulated activities. As such, if IFRS were adopted in its current
state, we may be precluded from applying certain regulatory accounting principles, including the
recognition of certain regulatory assets and regulatory liabilities. The potential issues associated with
rate-regulated accounting, along with other potential changes associated with the adoption of IFRS,
may adversely impact our financial condition and results of operations, should adoption of IFRS be
required. Also, the U.S. Financial Accounting Standards Board is considering various changes to U.S.
GAAP, some of which may be significant, as part of a joint effort with the IASB to converge
accounting standards over the next several years. If approved, adoption of these changes may adversely
impact our financial condition and results of operations.
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Risks Related Primarily to Our Local Utility Business
Gas price risk. Higher natural gas commodity prices and volatility in the price of gas may
adversely affect our results of operations and cash flows.
The cost of natural gas is affected by a variety of factors, including weather, changes in
demand, the level of production and availability of natural gas, imports of natural gas, transportation
constraints, availability of pipeline capacity, transportation capacity cost increases, federal and state
energy and environmental regulation and legislation, the degree of market liquidity, supply disruption,
natural disasters, wars and other catastrophic events, national and worldwide economic and political
conditions, and the price and availability of alternative fuels. In our utility segment, the cost we pay for
natural gas at the utility is generally passed through to our customers through an annual PGA rate
adjustment in Oregon and Washington (see below). Significant increases in the commodity price of
natural gas raises the cost of energy to our utility customers, thereby potentially causing those
customers to conserve or switch to alternate sources of energy. Significant price increases could also
cause new home builders and commercial developers to select heating systems other than natural
gas. Decreases in the volume of gas we sell could reduce our earnings in the absence of decoupled rate
structures, and a decline in customers could slow growth in our future earnings.
Higher gas prices may also cause us to experience an increase in short-term debt and
temporarily reduce liquidity because we pay suppliers for gas when it is purchased, which can be
several months or even a year in advance of when these costs are recovered through rates. Significant
increases in the price of gas can also slow our collection efforts as customers experience increased
difficulty in paying their higher energy bills, leading to higher than normal delinquent accounts
receivable. This could contribute to higher short-term debt levels, greater expense associated with
collection efforts and increased bad debt expense.
In Oregon and Washington, our utility has PGA tariffs which provide for annual revisions in
rates resulting from changes in the cost of purchased gas including the expected impact on bad debt
expense. In Oregon, we also have a price-elasticity adjustment that adjusts rates through the annual
PGA for expected increases or decreases in customer usage due to higher or lower gas prices. The
Oregon PGA tariff also provides an incentive to the Company to achieve lower gas costs such that a
percentage, set annually, of any difference between the estimated average PGA gas cost in rates and
the actual average gas cost incurred be recognized as current income or expense (see Part II, Item 7.,
“Results of Operations—Regulatory Matters—Rate Mechanisms”). Accordingly, higher average gas
costs than those assumed in setting rates can adversely affect our operating cash flows, liquidity and
results of operations. Notwithstanding our current rate structure, higher gas costs could result in
increased pressure on the OPUC or the WUTC to seek other means to reduce rates, which also could
adversely affect our results of operations and cash flows.
Customer growth risk. Our utility margin, earnings and cash flow may be negatively affected
if we are unable to sustain customer growth rates in our local gas distribution segment.
Our utility margins and earnings growth have largely depended upon the sustained growth of
our residential and commercial customer base due, in part, to the new construction housing market,
conversions of customers to natural gas from other fuel sources and growing commercial use of natural
gas. Continued weakness in the residential new construction and conversion market, and continued
decline in average use of natural gas by our residential and commercial customers, could result in an
adverse long-term impact on our utility margin, earnings and cash flows.
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Risk of competition. Our gas distribution business is subject to increased competition which
could negatively affect our results of operations.
In the residential market, our gas distribution business competes primarily with suppliers of
electricity, fuel oil, propane, and renewable energy providers. We also compete with suppliers of
electricity, fuel oil and renewable energy providers for commercial applications. In the industrial
market, we compete with suppliers of all forms of energy, including oil, electricity, renewable energy
providers and, as it relates to sources of energy for electric power plants, coal and hydro. Competition
among these forms of energy is based on price, efficiency, reliability, performance, market conditions
and technology.
Higher natural gas prices have at times eroded, or in some cases eliminated, the competitive
price advantage of natural gas over other energy sources. Technological improvements in other energy
sources could also erode our competitive advantage. If natural gas prices rise relative to other energy
sources, it may negatively affect our ability to attract new customers or retain our existing residential,
commercial and industrial customers, which could have a negative impact on our customer growth rate
and results of operations.
Reliance on third parties to supply natural gas risk. We rely on third parties to supply
substantially all of the natural gas in our distribution segment, and limitations on our ability to obtain
supplies could have an adverse impact on our financial results.
Our ability to secure natural gas for current and future sales depends upon our ability to purchase
and deliver supplies of natural gas from third parties, as well as our ability to acquire supplies directly
from new sources. Certain factors including the following may affect our ability to acquire and deliver
natural gas to our current and future customers: suppliers’ or other third parties’ control over drilling of
new wells and operating facilities to transport natural gas to our distribution system; competition for the
acquisition of natural gas; priority allocations on transmission pipelines; impact of severe weather
disruptions to natural gas supplies such as occurred with Hurricane Katrina in 2005; the regulatory and
pricing policies of federal, state and local government agencies; and the availability of Canadian reserves
for export to the United States. If we are unable to obtain or are limited in our ability to obtain natural gas
from our current suppliers or new sources, our financial results could be adversely impacted.
Single transportation pipeline risk. We rely on a single pipeline company for the
transportation of gas to our service territory, a disruption of which could adversely impact our ability
to meet our customers’ gas requirements.
Our distribution system is directly connected to a single interstate pipeline, Northwest
Pipeline. The pipeline’s gas flows are bi-directional, transporting gas into the Portland metropolitan
market from two directions: (1) the north, which brings supplies from the British Columbia and Alberta
supply basins; and (2) the east, which brings supplies from the Alberta and the U.S. Rocky Mountain
supply basins. If there is a rupture or inadequate capacity in the pipeline, we may not be able to meet
our customers’ gas requirements and we would likely incur costs associated with actions necessary to
mitigate service disruptions, both of which would negatively impact our results of operations.
Weather risk. Warmer than average weather or a failure to renew our weather normalization
mechanism may have a negative impact on our revenues and results of operations.
We are exposed to weather risk primarily in our utility segment. A majority of our volume is
driven from gas sales made to space heating residential and commercial customers during each winter
30
heating season. Current utility rates are based on an assumption of average weather. Weather that is
warmer than average typically results in lower gas sales. Sustained colder weather typically results in
higher gas sales. Although the effects of warmer or colder weather on utility margin in Oregon are
intended to be largely mitigated through the operation of our weather normalization mechanism, colder
weather could adversely affect utility margin because we may be required to purchase gas at spot rates
in a rising price market to secure sufficient volumes to meet customer requirements. Approximately 9
percent of our Oregon residential and commercial customers have opted out of the weather
normalization mechanism and 10 percent of our customers are in Washington where we do not have a
weather normalization mechanism. Furthermore, continuation of the weather normalization mechanism
in Oregon after October 2012 is subject to regulatory approval. As a result, we may not be fully
protected against warmer than average or colder than average weather, both of which may have an
adverse affect on our financial condition, results of operations and cash flows.
Customer conservation risk. Customers’ conservation efforts or a failure to renew our
conservation tariff may have a negative impact on our revenues.
An increasing national focus on energy conservation, including improved building practices
and appliance efficiencies, may result in increased energy conservation by customers, which can
decrease our sales of natural gas and adversely affect our results of operations. In Oregon, we have a
conservation tariff which is designed to recover lost margin due to declines in residential and
commercial customers’ consumption. The conservation tariff is scheduled to expire in October
2012. The failure of the OPUC to extend the conservation tariff in the future could adversely affect our
financial condition, results of operations and cash flows. We do not have a conservation tariff in
Washington.
Business improvements risk. Our efforts to integrate, consolidate and streamline our
operations have resulted in increased reliance on technology, the failure of which could adversely
affect our financial condition and results of operations.
Over the last several years we have undertaken a variety of initiatives to integrate, standardize,
centralize and streamline our operations. These efforts have resulted in greater reliance on
technological tools such as: an enterprise resource planning system, which provides an integrated suite
of business application software; an automated dispatch system, which provides integrated planning,
scheduling and dispatching of field resources; an automated meter reading system, which allows for
electronic reading of customers meters; and other similar technological tools and initiatives. The failure
of any of these or other similarly important technologies, or our inability to have these technologies
supported, updated, expanded or integrated into other technologies, could adversely impact our
operations. Although we have, when possible, developed alternative sources of technology and built
redundancy into our computer networks and tools, there can be no assurance that these efforts to date
would protect us against all potential issues or disaster occurrences related to the loss of any such
technologies or their use.
Risks Related Primarily to Our Gas Storage Business
Long-term stabilization of gas price risk. Any significant stabilization of natural gas prices
could have a negative impact on the demand for our natural gas storage services, which could
adversely affect our financial results.
Storage businesses benefit from price volatility, which impacts the level of demand for services
and the rates that can be charged for storage services. On a system-wide basis, natural gas is typically
31
injected into storage between April and October when natural gas prices are generally lower and
withdrawn during the winter months of November through March when natural gas prices are typically
higher. However, the market for natural gas may not continue to experience volatility and seasonal
price sensitivity in the future at the levels previously seen. If price volatility and seasonal price
sensitivity in the natural gas industry decrease because of increased production capacity or otherwise,
then the demand for our storage services and the prices that we will be able to charge for those services
may decline. A sustained decline in these prices could have an adverse affect on our financial
condition, results of operations and cash flows.
Natural gas storage competition risk. Increasing competition in the natural gas storage
business could reduce the demand for our storage services and drive prices down for our storage
business, which could adversely affect our financial condition, results of operation and cash flows.
Our natural gas storage segment competes primarily with other storage facilities and pipelines
in the storage of natural gas. Natural gas storage is an increasingly competitive business, with ongoing
and proposed third-party construction of new storage capacity and expansions of existing facilities in
California, the U.S. Rocky Mountains and elsewhere in the United States and Canada. Increased
competition in the natural gas storage business could reduce the demand for our natural gas storage
services, drive prices down for our storage business, and adversely affect our ability to renew or
replace existing contracts at rates sufficient to maintain current revenues and cash flows, which could
adversely affect our financial condition, results of operations and cash flows.
Third-party pipeline risk. Our gas storage business depends on third-party pipelines that
connect to our gas storage facilities, the failure or unavailability of which could adversely affect our
financial condition, results of operations and cash flows.
Our gas storage facilities are reliant on the continued operation of a third-party pipeline and
other facilities that provide delivery options to and from our storage facilities. Because we do not own
all of these pipelines, their operation is not within our control. If the third-party pipeline to which we
are connected were to become unavailable for current or future withdrawals or injections of natural gas
due to repairs, damage to the infrastructure, lack of capacity or other reason, our ability to operate
efficiently and satisfy our customers’ needs could be compromised, thereby potentially reducing our
revenues and cash flows.
Commencement of operations at new storage facility risk. Commencement of operations at
our new Gill Ranch storage facility involves numerous operational risks that may result in a failure to
meet expectations or contractual obligations, additional or unexpected costs and other business risks
that could adversely impact our financial condition, results of operations and cash flows.
In October, 2010 we commenced operations at our Gill Ranch storage facility. Operations at a
new storage facility involve many risks. Although we believe that Gill Ranch has been designed to
meet our contractual obligations and project specifications with respect to injection, withdrawal and
gas specifications, the facility is new and has a limited operating history. If we fail to achieve designed
capacity, inject or withdraw natural gas at the levels we expect or at contracted rates, or cannot deliver
natural gas consistent with our expectations or contractual specifications, or otherwise operate as
expected, or if operating costs are substantially higher than we expect or if we fail to control those
costs, we may not be able to contract for storage at the levels and on the terms we expect, and we could
incur higher than expected costs to satisfy our contractual obligations under contracts we obtain and
this could adversely impact our results of operations or cash flows.
32
ITEM 1B. UNRESOLVED STAFF COMMENTS
We have no unresolved comments.
ITEM 2. PROPERTIES
Utility Properties
Our natural gas distribution system consists of approximately 13,900 miles of distribution and
transmission mains located in our service territory in Oregon and Washington. In addition, the
distribution system includes service pipes, meters and regulators, and gas regulating and metering
stations. The mains are located in municipal streets or alleys pursuant to valid franchise or occupation
ordinances, in county roads or state highways pursuant to valid agreements or permits granted pursuant
to statute, or on lands of others pursuant to valid easements obtained from the owners of such lands.
We also hold all necessary permits for the crossing of the Willamette River and a number of smaller
rivers by our mains.
We own service facilities in Portland, as well as various satellite service centers, garages,
warehouses and other buildings necessary and useful in the conduct of our business. We lease office
space in Portland for our corporate headquarters, which expires on May 31, 2018. Resource centers are
maintained on owned or leased premises at convenient points in the distribution system to provide
service within our utility service territory. We own LNG storage facilities in Portland and near
Newport, Oregon.
In order to reduce risks associated with gas leakage in older parts of our system, we undertook
an accelerated pipe replacement program under which we removed or replaced 100 percent of our cast
iron mains by October 2000. In 2001, we initiated an accelerated pipe replacement program under
which we expect to eliminate all bare steel mains and services in the system by 2021.
Gas Storage Properties
We hold leases and other property interests in approximately 9,900 net acres of underground
natural gas storage in Oregon and approximately 5,000 net acres of underground natural gas storage in
California, and easements and other property interests related to pipelines associates with those
facilities. We own rights to depleted gas reservoirs near Mist, Oregon, that are continuing to be
developed and operated as underground gas storage facilities. We also hold an option to purchase
future storage rights in certain other areas of the Mist gas field in Oregon, as well as in California
related to the Gill Ranch storage project.
We consider all of our properties currently used in our operations, both owned and leased, to be
well maintained, in good operating condition, and, along with planned additions, adequate for our
present and foreseeable future needs.
Our Mortgage and Deed of Trust is a first mortgage lien on substantially all of the property
constituting our utility plant.
33
ITEM 3. LEGAL PROCEEDINGS
Other than the proceedings disclosed in Note 15 and as discussed below, we have only routine
nonmaterial litigation in the ordinary course of business.
In December 2010, NW Natural commenced litigation against certain of its historical liability
insurers in Multnomah County Circuit Court, State of Oregon, Case Number 1012-17532. The
defendants include Associated Electric & Gas Insurance Services Limited, Allianz Global Risk US
Insurance Company, certain underwriters at Lloyd’s London, certain London market insurance
companies and ten other insurance companies. In the suit, NW Natural alleges that the defendant
insurance companies issued third party liability insurance policies to NW Natural and that the
defendants have breached the terms of those policies by failing to indemnify NW Natural for liabilities
arising from environmental contamination at certain sites caused or alleged to be caused by its
historical operations. NW Natural seeks damages in excess of $40 million in losses it has incurred to
date, as well as declaratory relief for additional losses it expects to incur in the future.
34
PART II
ITEM 5. MARKET FOR THE REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER
MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
(A) Our common stock is listed and trades on the New York Stock Exchange under the
symbol “NWN.”
The high and low trades for our common stock during the past two years were as follows:
Quarter Ended
March 31
June 30
September 30
December 31
2010
High
Low
$47.54
49.18
49.00
50.86
$41.05
41.90
42.63
44.02
2009
High
Low
$45.66
46.07
46.00
46.47
$37.71
39.58
41.12
40.83
The closing quotations for our common stock on December 31, 2010 and 2009 were $46.47 and
$45.04, respectively.
(B) As of December 31, 2010, there were 7,135 holders of record of our common stock.
(C) We have paid quarterly dividends on our common stock in each year since the stock first
was issued to the public in 1951. Annual common dividend payments per share, adjusted for stock
splits, have increased each year since 1956. Dividends per share paid during the past two years were as
follows:
Payment Date
February 15
May 15
August 15
November 15
Total per share
2010
$0.415
0.415
0.415
0.435
$1.680
2009
$0.395
0.395
0.395
0.415
$1.600
The amount and timing of dividends payable on our common stock are within the sole
discretion of our Board of Directors. Subject to Board approval, we expect to continue paying cash
dividends on our common stock on a quarterly basis. However, the declaration and amount of future
dividends depend upon our earnings, cash flows, financial condition and other factors.
35
(D) The following table provides information about purchases of our equity securities that are
registered pursuant to Section 12 of the Securities Exchange Act of 1934 during the quarter ended
December 2010:
ISSUER PURCHASES OF EQUITY SECURITIES
(a)
(b)
Total Number
of Shares
Purchased (1)
Average
Price Paid
per Share
(c)
Total Number of Shares
Purchased as Part of
Publicly Announced
Plans or Programs (2)
(d)
Maximum Dollar Value of
Shares that May Yet Be
Purchased Under the
Plans or Programs (2)
1,182
22,462
1,517
25,161
$50.73
$48.79
$46.75
$48.76
2,124,528
-
-
-
2,124,528
$16,732,648
-
-
-
$16,732,648
Period
Balance forward
10/01/10-10/31/10
11/01/10-11/30/10
12/01/10-12/31/10
Total
(1) During the quarter ended December 31, 2010, 21,642 shares of our common stock were purchased on the
open market to meet the requirements of our Dividend Reinvestment and Direct Stock Purchase Plan. In
addition, 3,519 shares of our common stock were purchased on the open market during the quarter to meet
the requirements of our share-based programs. During the quarter ended December 31, 2010, no shares of
our common stock were accepted as payment for stock option exercises pursuant to our Restated Stock
Option Plan.
(2) We have a common stock share repurchase program under which we purchase shares on the open market or
through privately negotiated transactions. We currently have Board authorization through May 31, 2011 to
repurchase up to an aggregate of 2.8 million shares or up to an aggregate of $100 million. During the quarter
ended December 31, 2010, no shares of our common stock were purchased pursuant to this program. Since
the program’s inception in 2000 we have repurchased approximately 2.1 million shares of common stock at
a total cost of approximately $83.3 million.
36
ITEM 6. SELECTED FINANCIAL DATA
Thousands, except per share amounts and
ratio of earnings to fixed charges
2010
For the year ended December 31,
2008
2009
2007
2006
Utility operating revenues:
Residential sales
Commercial sales
Industrial - firm sales
Industrial - interruptible sales
Total gas sales revenues
Transportation
Regulatory adjustment for income taxes paid (1)
Other revenues
Total gross utility operating revenues
Cost of gas sold
Revenue taxes
Utility net operating revenues
Non-utility net operating revenues
$ 456,174 $ 555,844 $ 566,840 $ 555,312 $ 536,468
290,666
66,986
93,107
292,697
41,407
62,116
227,994
30,830
36,164
298,943
46,579
68,978
298,800
54,567
74,876
751,162
13,833
7,721
17,917
790,633
424,494
19,991
346,148
21,433
952,064
13,635
5,884
21,166
992,749
611,088
24,656
357,005
19,882
981,340
14,288
1,760
21,784
983,555
14,191
5,996
12,228
987,227
12,800
-
161
1,019,172
656,504
25,072
1,015,970
639,094
25,001
1,000,188
648,081
24,840
337,596
18,619
351,875
17,167
327,267
12,909
Net operating revenues
$ 367,581 $ 376,887 $ 356,215 $ 369,042 $ 340,176
Net income
$
72,667 $
75,122 $
69,525 $
74,497 $
63,415
Average common shares outstanding:
Basic
Diluted
Earnings per share of common stock:
Basic
Diluted
Dividends paid per share of common stock
26,589
26,657
26,511
26,576
26,438
26,594
26,821
26,995
27,540
27,657
$
$
$
2.73 $
2.73 $
2.83 $
2.83 $
2.63 $
2.61 $
2.78 $
2.76 $
2.30
2.29
1.68 $
1.60 $
1.52 $
1.44 $
1.39
Total assets - at end of period
$2,616,616 $2,399,252 $2,378,152 $2,014,061 $1,956,856
Long-term debt
Ratio of earnings to fixed charges
$ 591,700 $ 601,700 $ 512,000 $ 512,000 $ 517,000
3.40
3.76
3.92
3.86
3.73
(1) Regulatory adjustment for income taxes paid is the result of the implementation of the utility regulation in
2007 (see Part II, Item 7., “Business Segments—Utility Operations—Regulatory Adjustment for Income
Taxes Paid”).
37
SELECTED FINANCIAL DATA (continued)
Thousands, except customers and statistics
2010
For the year ended December 31,
2008
2009
2007
2006
Capitalization - at end of period
Common stock equity
Long-term debt
Total capitalization
Gas sales and transportation deliveries
(therms):
Residential
Commercial
Industrial - firm
Industrial - interruptible
Total gas sales
Transportation
$ 693,101 $ 660,105 $ 628,373 $ 594,751
512,000
601,700
591,700
512,000
$ 599,545
517,000
$1,284,801 $1,261,805 $1,140,373 $1,106,751
$1,116,545
368,682
230,196
37,085
58,387
694,350
367,619
412,867
255,593
39,447
72,525
780,432
350,933
428,787
265,531
47,340
87,484
829,142
431,609
398,960
249,659
52,340
89,128
790,087
424,882
382,665
242,683
66,971
112,736
805,055
387,594
Total utility volumes sold and delivered
1,061,969
1,131,365
1,260,751
1,214,969
1,192,649
Customers (average for period):
Residential
Commercial
Industrial - firm
Industrial - interruptible
Transportation
Total customers
Statistics:
Heat requirements:
607,645
62,334
590
153
174
601,989
62,142
610
169
158
594,481
61,756
625
180
136
580,346
60,749
634
189
128
670,896
665,068
657,178
642,046
564,700
59,889
650
197
99
625,535
Actual degree days
Percent colder (warmer) than average
Average annual use per customer in therms:
Residential
Commercial
Gas purchased cost per therm - net (cents)
4,171
(2%)
616
3,699
61.36
4,383
3%
686
4,113
71.96
4,576
7%
721
4,300
86.56
4,374
3%
687
4,110
75.00
4,089
(4%)
678
4,052
75.37
38
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
The following is management’s assessment of Northwest Natural Gas Company’s (NW
Natural) financial condition, including the principal factors that affect results of operations. The
discussion refers to our consolidated activities for the years ended December 31, 2010, 2009, and 2008.
Unless otherwise indicated, references in this discussion to “Notes” are to the Notes to Consolidated
Financial Statements in this report.
The consolidated financial statements include the accounts of NW Natural and its direct and
indirect wholly-owned subsidiaries which include: Gill Ranch Storage, LLC (Gill Ranch), NW Natural
Energy, LLC (NWN Energy), NW Natural Gas Storage, LLC (NWN Gas Storage), and NNG Financial
Corporation (NNG Financial). These statements also include accounts related to an equity investment
in Palomar Gas Holdings, LLC (PGH), which is developing a proposed natural gas pipeline through its
wholly-owned subsidiary Palomar Gas Transmission LLC (Palomar). These accounts include our
regulated local gas distribution business, our gas storage business, and other regulated and
non-regulated investments primarily in energy-related businesses. In this report, the term “utility” is
used to describe our regulated local gas distribution segment (distribution), and the term “non-utility”
is used to describe our gas storage segment (gas storage) as well as our other regulated and
non-regulated investments and business activities (other segment). For a further discussion of our
business segments, see Note 4.
In addition to presenting results of operations and earnings amounts in total, certain measures
are expressed in cents per share. These amounts reflect factors that directly impact earnings. We
believe this per share information is useful because it enables readers to better understand the impact of
these factors on consolidated earnings. All references in this section to earnings per share are on the
basis of diluted shares. We also show operating revenues and margins excluding the refund of gas cost
savings to customers in June and July 2009 because we believe it provides a more meaningful
comparison of operating revenues and margins between 2009 and 2010. We also present free cash flow
(see “Cash Flows—Financing Activities,” below). We use such non-GAAP (i.e. non-generally
accepted accounting principles) measures in analyzing our financial performance and believe that they
provide useful information to our investors and creditors in evaluating our financial condition and
results of operations.
Executive Summary
Highlights of 2010 include:
• Consolidated earnings of $72.7 million and $2.73 per share in 2010 compared to $75.1
million and $2.83 in 2009;
• Operating revenues (margin) of $367.6 million, a decrease of 2 percent;
• Total operating expenses of $210.0 million, a decrease of 4 percent;
•
Interest expense of $42.6 million, minus other income of $7.1 million, for a net decrease of
4 percent;
• Cash flow from operations of $126.5 million, a decrease of $113.9 million;
• Gill Ranch gas storage facility completed and operations started-up in the fourth quarter of
2010;
• Utility customer growth rate of 0.9 percent in 2010, compared to 0.8 percent in 2009;
39
• A #1 overall ranking for the best gas utility in the nation on the J.D. Power and Associates
residential customer satisfaction survey, and a #1 ranking for best in the West on the
business customer satisfaction survey; and
• Dividends paid increased 5 percent to $1.68 per share in 2010, making this the 55th
consecutive year of increasing dividends paid to shareholders.
Our primary businesses consist of regulated utility and gas storage operations. Factors critical
to the success of the utility include: maintaining a safe and reliable distribution system; acquiring an
adequate supply of natural gas; providing distribution services at competitive prices; and being able to
recover our operating and capital costs in the rates charged to customers in a reasonable and timely
manner. Our utility business is regulated by two state commissions, the Public Utility Commission of
Oregon (OPUC) and the Washington Utilities and Transportation Commission (WUTC). Factors
critical to the success of our gas storage business include: developing and operating storage capacity at
competitive market prices; retaining existing customers and successfully marketing available storage
capacity to new customers; planning for the replacement of capacity that is expected to be recalled by
the utility to serve growing demands of its customers; appropriate rates; and with respect to future
development of gas storage projects, being able to obtain financing to fund future development. Our
gas storage business is, in part, regulated by the California Public Utilities Commission (CPUC).
2011 Outlook
In 2011, we intend to remain focused on improving our core businesses, enhancing our strategic
position, advancing business development projects related to our primary business segments, and
strengthening our organizational effectiveness. The following is a brief summary of management’s
plans and objectives in these four areas. For further information, see “Issues, Challenges and
Performance Measures,” and “Strategic Opportunities,” below.
Business improvements. We continue to develop, integrate, consolidate and streamline
operations using recently acquired new technology, which include an enterprise resource planning
system, an automated dispatching system and an automated meter reading system. These and other
new technologies support our operating model.
Strategic position. We remain committed to creating shareholder value while balancing the
interests of our customers, employees and the communities we serve. To create value, we anticipate
and respond to business challenges and opportunities that lie ahead, including finding innovative
solutions to economic and environmental challenges as well as regulatory, workforce and business
development challenges and opportunities, such as the potential investment in long-term gas reserves
on behalf of our utility customers.
Business development. We continue to focus on the development of our underground gas
storage businesses, the natural gas infrastructure investment in Palomar and key utility initiatives.
Organizational effectiveness. Our employees are our most valued resource. We intend to
support our employees with a positive and safe work environment, on-going training opportunities,
continued refinement of our organizational structure and new technologies to achieve goals and
facilitate improvements.
40
Issues, Challenges and Performance Measures
Economic weakness. Ongoing weakness in local and U.S. economies has continued to impact
utility customer growth, business demand for natural gas and gas storage prices. Most recently, our
utility’s annual customer growth rate increased slightly to 0.9 percent at December 31, 2010, compared
to 0.8 percent in 2009 and 1.6 percent in 2008. We are still faced with 10 to 11 percent unemployment
rates in Oregon and southwest Washington and a sluggish business environment. However, despite
these challenges we believe we are well positioned to continue adding utility customers due to lower
natural gas prices, our relatively low market penetration, our efforts to convert homes to natural gas,
and the potential for environmental initiatives that could favor natural gas use in our region.
Managing gas prices and supplies. Our gas acquisition strategy is designed to secure
sufficient supplies of natural gas to meet the needs of our utility customers and to hedge gas prices to
effectively manage costs, reduce price volatility and maintain a competitive advantage. With recent
success in new drilling technologies and substantial new supplies from shale gas formations around the
U.S. and in Canada, the supply of North American natural gas has increased dramatically, which has
contributed to lower and more stable gas prices. We entered the 2010-11 gas contract year, which
began November 1, 2010, hedged on gas commodity prices at approximately 77 percent of our
forecasted purchase volumes. In addition, we are currently hedged at approximately 45 percent for the
2011-12 gas contract year and between 5 and 10 percent for the 2012-13 gas contract year. Our
Purchased Gas Adjustment (PGA) mechanism, along with our gas price hedging strategies and gas
supplies in storage, enable us to reduce earnings risk exposure and secure lower gas costs for
customers. These lower gas prices, coupled with good customer service and energy efficiency
programs for customers, can help strengthen natural gas’ competitive price advantage compared to
other fuels. In addition to hedging gas prices over the next few years, we are evaluating and developing
other gas acquisition strategies to potentially manage gas price volatility for customers beyond three
years, including possible investments in long-term gas reserves. Although stable gas prices provide
opportunities to manage costs for our utility customers, they present challenges for our gas storage
business by lowering the value of, and reducing demand for, storage services and limiting Gill Ranch’s
ability to contract for longer terms at favorable prices.
Environmental costs. We accrue all material environmental loss contingencies related to our
properties that require environmental investigation or remediation. Due to numerous uncertainties
surrounding the preliminary nature of investigations or the developing nature of remediation
requirements, actual costs could vary significantly from our loss estimates. As a regulated utility, we
are required to defer certain costs pursuant to regulatory decisions. We currently have a regulatory
order to defer certain environmental costs, and to seek recovery of these amounts in future rates to
customers. However, before we can seek recovery from customers, we are expected to pursue recovery
from insurance policies. Ultimate recovery of environmental costs, either from regulated utility rates or
from insurance, will depend on our ability to effectively manage costs and demonstrate that costs were
prudently incurred. Recovery may vary significantly from amounts currently recorded as regulatory
assets, and amounts not recovered would be required to be charged to income in the period they were
deemed to be unrecoverable. See Note 15.
Climate change. We recognize that our businesses will be impacted by future carbon
constraints. The outcome of federal, state, local and international climate change initiatives cannot be
determined at this time, but these initiatives could produce a number of results including potential new
regulations, additional charges to fund energy efficiency activities, or other regulatory actions. For
example, in September 2009, the EPA issued a final rule requiring the annual reporting of greenhouse
41
gas emissions from certain industries, specified large greenhouse gas emission sources, and facilities
that emit 25,000 metric tons or more of CO2 equivalents per year. The first reports are due by
March 31, 2011 for emissions occurring on or after January 1, 2010. Under this reporting rule, local
gas distribution companies are required to report system throughput to the EPA on an annual basis. The
EPA also issued additional greenhouse gas reporting regulations in November 2010 requiring the
annual reporting of fugitive emissions, an unintended release of gas, from our operations. The first
report under these more recent regulations is due by March 31, 2012. Lawsuits have been filed
challenging the EPA’s regulation of greenhouse gas emissions and members of the U.S. Congress have
discussed proposing legislation that would limit the EPA’s ability to regulate greenhouse gas
emissions. While our CO2 equivalent emission levels are relatively small, the adoption and
implementation of any regulations imposing reporting obligations, or limiting emissions of greenhouse
gases associated with our operations, could result in an increase in the prices we charge our customers
or a decline in the demand for natural gas. On the other hand, because natural gas has a relatively low
carbon content, it is also possible that future carbon constraints could create additional demand for
natural gas for electric generation, direct use in homes and businesses and as a reliable and relatively
low-emission back-up fuel source for alternative energy sources.
Performance measures. In order to deal with the challenges affecting our businesses, we
annually review and update our strategic plan to map our course over the next several years. Our plan
includes strategies for: further improving our utility gas distribution business; growing our non-utility
gas storage business; investing in new natural gas infrastructure in the region; and maintaining a
leadership role within the gas utility industry by addressing long-term energy policies and pursuing
business opportunities that support new clean energy technologies. We intend to measure our
performance and monitor progress on certain metrics including, but not limited to: earnings per share
growth; total shareholder return; return on invested capital; utility return on equity; utility customer
satisfaction ratings; utility margin; utility capital and operations and maintenance expense per
customer; and non-utility earnings before interest, taxes, depreciation and amortization (non-utility
EBITDA).
Strategic Opportunities
Business Process Improvements. To address the current economic and competitive
challenges, we continue to evaluate and implement business strategies to improve efficiencies. Our
goal is to develop, integrate, consolidate and streamline operations and support our employees with
new technology tools.
In 2009, we announced a voluntary severance program to reduce staffing levels in response to
work load declines related to the low customer growth environment and efficiency
improvements. Severance programs and normal attrition resulted in reductions of full-time positions
from 1,133 at December 31, 2008 to slightly over 1,000 in 2010, and the savings are reflected in
decreases in utility operation and maintenance costs and utility capital expenditures.
Technology investments, workforce reductions and other initiatives implemented over the last
couple years contributed to a 9 percent decrease in utility operation and maintenance cost in 2010, and
these efforts are expected to contribute to long-term operational efficiencies and lower operating and
capital costs throughout NW Natural.
Gas Storage Development. We have a joint agreement with Pacific Gas and Electric Company
(PG&E) on an underground natural gas storage facility near Fresno, California. Our 75 percent
undivided ownership interest in the facility is held by our wholly-owned subsidiary, Gill Ranch. Gill
42
Ranch is also the sole operator of the project. Construction on this facility began in January 2010, with
a majority of the construction work completed by October 2010 and the remainder of the construction
work expected to be completed in 2011. Our share of the initial development is designed to provide 15
Bcf of gas storage capacity by the end of 2013 and an associated capacity on the approximate 27 miles
of gas transmission pipeline. Gill Ranch began operations during the fourth quarter of 2010. See
Note 4.
Gill Ranch is offering storage services to the California market at market-based rates, subject to
CPUC regulation including, but not limited to, service terms and conditions, tariff regulations, and
security issuances. Due to increasing supplies and price stability of natural gas in North America, and
declining demand for natural gas due to recent economic conditions, current storage values are
expected to remain low in the near term, which will likely affect the prices at which Gill Ranch is able
to contract.
The initial construction costs of Gill Ranch included the construction of some infrastructure
that will accommodate a potential expansion of the Gill Ranch facility. Subject to market demand,
project execution, available financing and receipt of future permits, we have the operational capacity to
expand the Gill Ranch facility beyond our and PG&E’s combined permitted capacity of 20 Bcf,
without further expansion of our takeaway pipeline system. Taking these considerations into account
and with certain infrastructure modifications, we currently estimate that the Gill Ranch storage facility
could support an aggregate storage capacity of around 40 Bcf, of which we would have the rights to an
aggregate of 20 Bcf or 50 percent of total estimated storage capacity.
The Pacific Northwest storage markets also are negatively impacted by lower gas prices and
lack of gas price volatility, but less so than in California. In 2011, we expect to continue planning for
possible expansion of our gas storage facilities near Mist, Oregon in anticipation of increased natural
gas demand for electric generation in the Pacific Northwest. Currently we do not have a set timeline for
development, but we believe the earliest timeframe for moving forward with the next Mist expansion is
2013. In the meantime, we will continue to monitor the market demand and work on preliminary
design and project scope, which will ultimately require the development of storage wells, potentially a
second compression station and additional pipeline gathering facilities that
will enable future storage expansions.
Pipeline Diversification. Currently our utility and gas storage at Mist depend on a single
bi-directional interstate transmission pipeline to ship gas supplies. Palomar, a wholly-owned subsidiary
of PGH, seeks to build a new gas transmission pipeline that would provide an interconnection with our
utility distribution system. PGH is owned 50 percent by us and 50 percent by Gas Transmission
Northwest Corporation (GTN), an indirect wholly-owned subsidiary of TransCanada Corporation. The
proposed Palomar pipeline includes an east and a west segment and is designed to serve our utility and
the growing natural gas markets in Oregon and other parts of the Pacific Northwest. The proposed
pipeline would be regulated by the FERC.
In May 2010, we learned that the company proposing to build an LNG terminal on the
Columbia River had suspended its operations and filed for bankruptcy. This company had previously
entered into a binding precedent agreement with Palomar for a majority of the proposed pipeline’s
capacity. In September 2010, the bankruptcy court rejected and terminated the precedent agreement
and ruled in Palomar’s favor with regards to a lien on the bankrupt company’s assets. Palomar
currently has taken title to all of the bankrupt shipper’s assets based upon the bankruptcy court’s final
decision in this matter in October 2010.
43
Palomar also has a non-binding memorandum of understanding with The Williams Companies’
Northwest Pipeline (Northwest Pipeline) that contemplates Northwest Pipeline becoming a part owner
in the Palomar project and which consolidates the region’s efforts to develop a cross-Cascades pipeline
around the use of the Palomar route. Northwest Pipeline owns and operates the single, bi-directional
pipeline that connects to NW Natural’s utility distribution system. In early February 2011, Palomar
held a workshop with the OPUC, WUTC and other Pacific Northwest parties to address the aggregate
gas infrastructure needs for the region. Palomar expects to have an open season in 2011 and focus on
permitting activities with FERC during 2011. The date for when the Palomar pipeline is expected to go
into service will be impacted by the timing of our final FERC permit and the needs of shippers. See
“Financial Condition—Cash Flows—Investing Activities,” below for further discussion on the status
of Palomar.
As of December 31, 2010, our net equity investment in PGH, which in turn has been invested in
Palomar, was $14.8 million. As of December 31, 2010, Palomar had invested a total of $45.6 million
of capital costs for the pipeline development, including allowance for funds used during construction
(AFUDC). Palomar recovered $15.8 million from a letter of credit which supported the bankrupt
shipper’s obligations under its prior precedent agreement, and title to certain assets from the bankrupt
company’s liquidation.
In October 2010, Palomar executed an agreement with the Confederated Tribe of the Warm
Springs Reservation that provides Tribal consent for the Bureau of Indian Affairs to issue a pipeline
right-of-way grant across the Warm Springs Reservation. Adoption of this route for the east segment
will both shorten the pipeline length and reduce its environmental impact relative to the initially
proposed route in Palomar’s FERC application.
We believe the proposed pipeline’s east segment is still a viable project, and the Palomar
project remains in a development stage. We performed an impairment analysis for our total equity
investment as of December 31, 2010 and determined that no impairment write-down is needed (see
Note 12).
Consolidated Earnings and Dividends
Consolidated net income was $72.7 million, or $2.73 per share, for the year ended
December 31, 2010, compared to $75.1 million, or $2.83 per share, and $69.5 million, or $2.61 per
share, for the years ended December 31, 2009 and 2008, respectively. Consolidated earnings decreased
in fiscal year 2010 primarily due to lower earnings from our gas storage segment, which reflects partial
year operations and start-up expenses for our subsidiaries Gill Ranch and NWN Gas Storage. These
decreases were partially offset by increased earnings reported by our utility gas distribution business
and our ongoing interstate gas storage business at Mist. Consolidated returns on average stockholders’
equity for these three years were 10.7 percent, 11.7 percent and 11.4 percent, respectively.
2010 compared to 2009:
The most significant factors contributing to the $2.4 million decrease in consolidated net
income were:
•
a $13.5 million decrease in utility net operating revenue (margin) from the regulatory gas
cost incentive sharing mechanism, which reflects gains of $15.1 million in 2009 compared
to gains of $1.6 million in 2010;
44
•
•
•
a $2.9 million net loss from Gill Ranch, and a $0.6 million net loss from NWN Gas Storage,
primarily reflecting higher operating expenses related to start-up activities;
a $2.8 million increase in income tax expense primarily reflecting higher taxable income
from the utility, including an accelerated amortization of regulatory tax balances related to
pre-1981 assets which are offset by increased revenues collected in utility margin; and
a $1.9 million increase in interest expense primarily reflecting the full year effect of long-
term debt issued during 2009 and higher balances of short-term debt outstanding.
Partially offsetting the above factors were:
•
•
•
a $5.0 million increase in utility margin from residential and commercial customers, after
adjustments for weather and decoupling mechanisms, primarily due to colder weather
benefits in the second quarter of 2010 when weather normalization was not in effect,
customer growth and the rate recovery of higher income tax expenses related to an increase
in Oregon tax rates and the accelerated amortization of regulatory tax assets;
a $14.3 million decrease in utility operating expenses primarily due to lower property tax,
payroll, bad debt, and employee benefit costs; and
a $3.4 million increase in other income primarily due to higher interest income from utility
deferred regulatory account balances and interest income from a utility property tax refund,
partially offset by a decrease in the non-utility gains from company-owned life insurance.
2009 compared to 2008:
Factors contributing to increased earnings were:
•
•
•
a $20.6 million increase in utility margin from our regulatory share of gas cost savings,
reflecting a contribution to margin of $15.1 million in 2009 compared to a reduction to
margin of $5.5 million in 2008;
a $4.1 million increase in utility margin from the regulatory adjustment for income taxes
paid; and
a $1.3 million increase in gas storage margin from higher optimization revenues.
Partially offsetting the above factors were:
•
•
•
a $13.7 million increase in operations and maintenance expense primarily due to higher
utility expenses for pensions, bonuses, health care benefits and employee severance;
a $6.0 million increase in income tax expense related to higher taxable income and a higher
state income tax rate; and
a $2.1 million decrease in utility margin from industrial customers, reflecting weak
economic conditions and a decrease in depreciation rates.
Dividends paid on our common stock were $1.68 per share in 2010, compared to $1.60 per
share in 2009 and $1.52 per share in 2008. The Board of Directors declared a quarterly dividend on our
common stock of 43.5 cents per share, payable on February 15, 2011, increasing the indicated annual
dividend rate to $1.74 per share.
Application of Critical Accounting Policies and Estimates
In preparing our financial statements using generally accepted accounting principles in the
United States of America (GAAP), management exercises judgment in the selection and application of
accounting principles, including making estimates and assumptions that affect reported amounts of
45
assets, liabilities, revenues, expenses and related disclosures in the financial statements. Management
considers our critical accounting policies to be those which are most important to the representation of
our financial condition and results of operations and which require management’s most difficult and
subjective or complex judgments, including accounting estimates that could result in materially
different amounts if we reported under different conditions or used different assumptions. Our most
critical estimates and judgments include accounting for:
•
•
•
•
•
•
regulatory cost recovery and amortizations;
revenue recognition;
derivative instruments and hedging activities;
pensions and postretirement benefits;
income taxes; and
environmental contingencies.
Management has discussed its current estimates and judgments used in the application of
critical accounting policies with the Audit Committee of the Board. Within the context of our critical
accounting policies and estimates, management is not aware of any reasonably likely events or
circumstances that would result in materially different amounts being reported. For a description of
recent accounting pronouncements that could have an impact on our financial condition, results of
operations or cash flows, see Note 2.
Regulatory Accounting
We are regulated by the OPUC and WUTC, which establish our utility rates and rules
governing utility services provided to customers, and, to a certain extent, set forth the accounting
treatment for certain regulatory transactions. In general, we use the same accounting principles as
non-regulated companies reporting under GAAP. However, authoritative guidance for regulated
operations (regulatory accounting) require different accounting treatment for regulated companies to
show the effects of such regulation. For example, we account for the cost of gas using a PGA deferral
and cost recovery mechanism, which is submitted for approval annually to the OPUC and WUTC (see
“Results of Operations—Regulatory Matters—Rate Mechanisms,” below). There are other expenses or
revenues that the OPUC or WUTC may require us to defer for recovery or refund in future
periods. Regulatory accounting requires us to account for these types of deferred expenses (or deferred
revenues) as regulatory assets (or regulatory liabilities) on the balance sheet. When we are allowed to
recover these expenses from, or required to refund them to, customers, we recognize the expense or
revenue on the income statement at the same time we realize the adjustment to amounts included in
utility rates charged to customers.
The conditions we must satisfy to adopt the accounting policies and practices of regulatory
accounting, which are applicable to regulated companies, include:
•
•
•
an independent regulator sets rates;
the regulator sets the rates to cover specific costs of delivering service; and
the service territory lacks competitive pressures to reduce rates below the rates set by the
regulator.
Because we meet all three conditions, we continue to apply regulatory accounting principles for
our utility operations. Future accounting changes, regulatory changes or changes in the competitive
environment could require us to discontinue the application of regulatory accounting for some or all of
46
our regulated businesses. This would require the write-off of those regulatory assets and liabilities that
would no longer be probable of recovery from or refund to customers. Based on current accounting,
regulatory and competitive conditions, we believe that it is reasonable to expect continued application
of regulatory accounting for our regulated activities, and that all of our regulatory assets and liabilities
at December 31, 2010 and 2009 are recoverable or refundable through future customer rates. The net
balance on regulatory asset and liability accounts as of December 31, 2010 and 2009 was $125.8
million and $51.2 million, respectively. See “Industry Regulation” in Note 2.
Revenue Recognition
Utility revenues, derived primarily from the sale and transportation of natural gas, are
recognized when gas is delivered to and received by the customer. Revenues are accrued for gas
delivered to customers, but not yet billed, based on estimates of gas deliveries from the last meter
reading date to month end (accrued unbilled revenues). Accrued unbilled revenues are primarily based
on a percentage estimate of our unbilled gas deliveries each month, which is dependent upon a number
of factors, some of which require management’s judgment. These factors include total gas receipts and
deliveries, customer meter reading dates, customer usage patterns and weather. Accrued unbilled
revenue estimates are reversed the following month when actual billings occur. Estimated unbilled
revenues at December 31, 2010 and 2009 were $64.8 million and $71.2 million, respectively. The
decrease in accrued unbilled revenues at year-end 2010 was primarily due to lower volumes in 2010
reflecting warmer weather in late December 2010 and lower customer rates. If the estimated
percentage of unbilled volume at December 31, 2010 was adjusted up or down by 1 percent, then our
unbilled revenues, net operating revenues and net income would have increased or decreased by an
estimated $2.4 million, $0.6 million and $0.3 million, respectively.
Utility revenues also include the recognition of a regulatory adjustment for income taxes
paid. This revenue reflects an OPUC rule whereby we are required to automatically implement a rate
refund or a rate surcharge to utility customers. This refund or surcharge is accrued based on the
estimated difference between income taxes paid and income taxes authorized to be collected in rates
(for further discussion, see “Results of Operations—Business Segments—Utility Operations—
Regulatory Adjustment for Income Taxes Paid,” below).
Non-utility revenues, derived primarily from our gas storage business segment, are recognized
upon delivery of service to customers. Revenues from our asset optimization partner are recognized as
earned based on multiple revenue elements, which is generally over the period of each optimization
deal except for a contract with a guaranteed amount which is amortized over the life of the contract.
Accounting for Derivative Instruments and Hedging Activities
Our gas acquisition and hedging policies set forth guidelines for using financial derivative
instruments to support prudent risk management strategies. These policies specifically prohibit the use
of derivatives for trading or speculative purposes. The accounting rules for determining whether a
contract meets the definition of a derivative instrument or qualifies for hedge accounting treatment are
complex. The contracts that meet the definition of a derivative instrument are recorded on our balance
sheet at fair value. If certain regulatory conditions are met, then the derivative instrument fair value is
recorded together with an offsetting entry to a regulatory asset or liability account pursuant to
regulatory accounting (see Note 2, “Industry Regulation”), and no unrealized gain or loss is recognized
in current income. The gain or loss from the fair value of a derivative instrument subject to regulatory
47
deferral is included in the recovery from, or refund to, utility customers in future periods (see
“Regulatory Accounting,” above). If a derivative contract is not subject to regulatory deferral, then the
accounting treatment for unrealized gains and losses is recorded in accordance with accounting
standards for derivatives and hedging (see Note 2, “Derivatives” and “Industry Regulation”) which is
either in current income or in accumulated other comprehensive income under common stock equity on
the balance sheet. Our derivative contracts outstanding at December 31, 2010 were measured at fair
value using models or other market accepted valuation methodologies derived from observable market
data. Our estimate of fair value may change significantly from period-to-period depending on market
conditions and prices. These changes may have an impact on our results of operations, but the impact
would largely be mitigated due to the majority of our derivatives activities being subject to regulatory
deferral treatment. For estimated fair values on unrealized gains and losses at December 31, 2010 and
2009, see Note 13.
Commodity-based derivative contracts entered into by the utility after our annual PGA filing
for the current gas contract period are subject to a regulatory incentive sharing mechanism in Oregon
(see “Results of Operations—Regulatory Matters—Rate Mechanisms—Purchased Gas Adjustment,”
below). The portion not deferred to a regulatory account pursuant to that sharing agreement is
recognized either in current income for contracts not qualifying for hedge accounting or in
accumulated other comprehensive income for contracts qualifying for hedge accounting.
Derivative contracts not qualifying for regulatory deferral are subject to a hedge effectiveness
test to determine the financial statement treatment of each specific derivative. As of December 31,
2010, all of our derivatives were effective economic hedges and either qualified or were expected to
qualify for regulatory deferral or hedge accounting treatment. We use the hypothetical derivative
method under accounting standards for derivatives and hedging to determine the hedge effectiveness
for our interest rate swaps and the dollar offset method for other derivative contracts under accounting
standards for derivatives and hedging. The effectiveness test applied to financial derivatives is
dependent on the type of derivative and its use.
The following table summarizes the amount of realized gains and losses from commodity price,
interest rate and currency hedge transactions for the last three years:
Thousands
Net gain (loss) on commodity-price swaps—utility
Net gain (loss) on commodity-price options—utility
Net gain (loss) on interest rate swap—utility
2010
2009
2008
$(60,362) $(172,089) $34,256
1,527
-
(5,809)
(10,096)
(610)
-
Subtotal on commodity—utility
Net gain (loss) on foreign currency forward purchases—utility
Total realized net gain (loss)
(60,972)
72
(187,994)
88
35,783
(728)
$(60,900) $(187,906) $35,055
Realized gains (losses) from commodity hedges and foreign currency forward purchase
contracts are recorded as reductions (increases) to the cost of gas and are included in the calculation of
annual PGA rate changes. Realized gains (losses) from interest rate hedges are recorded as reductions
(increases) to interest charges over the term of the underlying debt issuances. Unrealized gains and
losses from commodity hedges, foreign currency hedges and interest rate hedges, which reflect
quarterly mark-to-market valuations, are generally not recognized in current income or accumulated
other comprehensive income, but are recorded as regulatory liabilities or regulatory assets, and are
offset by a corresponding balance in derivative instruments (see Note 13).
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Accounting for Pensions and Postretirement Benefits
We maintain two qualified non-contributory defined benefit pension plans covering a majority
of our regular employees with more than one year of service, several non-qualified supplemental
pension plans for eligible executive officers and certain key employees and other postretirement
employee benefit plans. We also have a qualified defined contribution plan (Retirement K Savings
Plan) for all eligible employees. Only the two qualified defined benefit pension plans and Retirement K
Savings Plan have plan assets, which are held in a qualified trust to fund retirement benefits. Effective
January 1, 2007 and 2010, the qualified defined benefit retirement plans and postretirement benefits for
non-union employees and for union employees, respectively, were closed to new participants. These
plans were not available to employees at our NWN Gas Storage affiliate. Instead, non-union and union
employees hired or re-hired after December 31, 2006 and 2009, respectively, and our NWN Gas
Storage employees, are provided an enhanced Retirement K Savings Plan benefit. Also, effective
January 1, 2007 the postretirement Welfare Benefit Plan for Non-Bargaining Unit Employees was
closed to new participants after December 31, 2006.
Net periodic pension and postretirement benefit costs (retirement benefit costs) and projected
benefit obligations (benefit obligations) are determined in accordance with accounting standards for
compensation and retirement benefits using a number of key assumptions including discount rates, rate
of compensation increases, retirement ages, mortality rates and an expected long-term return on plan
assets (see Note 9). These key assumptions have a significant impact on the pension amounts recorded
and disclosed. Retirement benefit costs consist of service costs, interest costs, the amortization of
actuarial gains, losses and prior service costs, the expected returns on plan assets and, in part, on a
market-related valuation of assets, if applicable. The market-related asset valuation reflects differences
between expected returns and actual investment returns, which we recognize over a three-year period
or less from the year in which they occur, thereby reducing year-to-year volatility in retirement benefit
costs.
Accounting standards also require balance sheet recognition of the overfunded or underfunded
status of pension and postretirement benefit plans in accumulated other comprehensive income
(AOCI), net of tax, based on the fair value of plan assets compared to the actuarial value of future
benefit obligations. However, the retirement benefit costs relating to our qualified defined benefit
pension and postretirement benefit plans are generally recovered in utility rates which are set based on
accounting standards for pensions and postretirement benefits, and as such we received approval from
the OPUC pursuant to regulatory accounting to recognize the overfunded or underfunded status as a
regulatory asset or regulatory liability based on expected rate recovery, rather than including it as
AOCI under common equity (see “Regulatory Accounting”, above, and Note 2, “Industry
Regulation”). Also effective January 1, 2011 the OPUC has authorized the use of a pension balancing
account to allow differences between the annual pension cost allocated to operation and maintenance
expense and the amount recovered annually in rates per the 2003 general rate case to be recorded in a
regulatory asset account. The regulatory asset account will earn a carrying cost at the authorized cost of
capital rate set by the OPUC.
49
A number of factors are considered in developing pension and postretirement assumptions,
including evaluations of relevant discount rates, an evaluation of expected long-term investment
returns based on asset classes and target asset allocations, expected changes in salaries and wages,
analyses of past retirement plan experience and current market conditions and input from actuaries and
other consultants. For the December 31, 2010 measurement date, we reviewed and updated:
•
•
•
•
our pension and postretirement weighted-average discount rate assumptions from 6.01
percent to 5.49 percent and from 5.78 percent to 5.16 percent, respectively. The new rate
assumptions were determined for each plan based on a matching of the estimated cash flow,
which reflects the timing and amount of future benefit payments, to the Citigroup Above
Median Curve, which consists of high quality bonds rated AA- or higher by Standard &
Poor’s (S&P) or Aa3 or higher by Moody’s Investors Service (Moody’s);
our expected annual rate of future compensation increases remained unchanged at a range
of 3.25 to 5.0 percent;
our expected long-term return on qualified defined benefit plan assets remained unchanged
at 8.25 percent; and
other key assumptions as needed based on actual experience and actuarial
recommendations.
At December 31, 2010, our net pension liability (benefit obligations less market value of plan
assets) for the two qualified defined benefit plans increased $11.5 million compared to 2009. The
increase in our net pension liability is primarily due to the $29.3 million increase in our pension
obligation, which was partially offset by our $10 million cash contribution. The liability for
non-qualified plans increased $2.1 million and the liability for other postretirement benefits increased
$2.9 million in 2010.
We determine the expected long-term rate of return on plan assets by averaging the expected
earnings for the target asset portfolio. In developing our expected return, we evaluate an analysis of
historical actual performance and long-term return projections, which gives consideration to the current
asset mix and our target asset allocation. As of December 31, 2010, the actual annualized returns on
plan assets, net of management fees, for the past one-year, five-years, 10-years and since December
1980 were 13.2 percent, 3.4 percent, 4.5 percent and 10.3 percent, respectively.
We believe our assumptions to be appropriate based on plan design and an assessment of
market conditions. However, if our pension assumptions changed 0.25 percent, the retirement benefits
costs would change by $1.5 million and the benefit obligations would change by $10.3 million. If our
other post retirement obligations assumptions changed by 1 percent, then our health care benefit cost
would change by less than $0.1 million and the benefit obligation would change by $0.7 million.
Accounting for Income Taxes
We account for income taxes in accordance with accounting standards that require the
recognition of deferred tax assets and liabilities for the expected future tax consequences of temporary
differences between financial statement carrying amount and tax basis of assets and
liabilities. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to
taxable income in the years in which those temporary differences are expected to be recovered or
settled. At December 31, 2010 and 2009, our net long-term deferred tax liability totaled $373.4 million
and $300.9 million, respectively. After application of the federal statutory tax rate to book income,
judgment is required with respect to the timing and deductibility of expense in our tax returns. For state
50
income tax and local income taxes, judgment is also required with respect to the apportionment among
the various jurisdictions. A valuation allowance is recorded if we expect that it is “more likely than
not” that our deferred tax assets will not be realized. At December 31, 2010, we did not have a
valuation allowance due to our expectation that all of these assets will be realized.
These accounting standards also require the recognition of deferred income tax assets and
liabilities for temporary differences where regulators require us to flow through deferred income tax
benefits or expenses in the ratemaking process of the regulated utility (regulatory tax assets and
liabilities). This is consistent with the ratemaking policies of the OPUC and WUTC. Regulatory tax
assets and liabilities are recorded to the extent we believe they will be recoverable from, or refunded
to, customers in future rates. At December 31, 2010 and 2009, we had regulatory assets representing
differences between book and tax basis related to pre-1981 property of $72.3 million and $76.2
million, respectively, and recorded an offsetting deferred tax liability. We received authorization from
the OPUC and WUTC in 2009 to accelerate the recovery of these pre-1981 regulatory assets through
future utility rates. See Notes 2 and 10.
Uncertain tax positions are accounted for in accordance with accounting standards that require
management’s assessment of the expected treatment of a tax position taken in a filed tax return, or
planned to be taken in a future tax return, that has not been reflected in measuring income tax expense
for financial reporting purposes. Until such positions are sustained by the taxing authorities, we would
not recognize the tax benefits resulting from such positions and would report the tax effect as a liability
in the Company’s consolidated balance sheet. As of December 31, 2010, we had no uncertain tax
positions.
The Internal Revenue Service (IRS) is currently examining our 2006 through 2008 consolidated
federal income tax returns. The IRS completed its last examination of the 2002 through 2004 audit
cycle in the second quarter of 2006. Completion of the 2006 through 2008 federal income tax return
examination is expected during the first quarter of 2011. Currently we do not have any uncertain tax
positions that will have a material impact on our results of operations.
The Oregon Department of Revenue (ODOR) is also examining our 2006 through 2008
consolidated income tax returns. Completion of this examination is expected during the first quarter of
2011.
Interest and penalties, if any, related to income tax adjustments for prior years will be recorded
within income tax expense in the consolidated statements of income.
Contingencies
Loss contingencies are recorded as liabilities when it is probable that a liability has been
incurred and the amount of the loss is reasonably estimable in accordance with accounting standards
for contingencies. Estimates of loss contingencies, including estimates of legal costs when such costs
are probable of being incurred and are reasonably estimable, and related disclosures are updated when
new information becomes available. Estimating probable losses requires an analysis of uncertainties
that often depend upon judgments about potential actions by third parties. Accruals for loss
contingencies are recorded based on an analysis of potential results. When information is sufficient to
estimate only a range of potential liabilities, and no point within the range is more likely than any
other, we recognize an accrued liability at the low end of the range and disclose the range (see
“Contingent Liabilities,” below). It is possible, however, that the range of potential liabilities could be
51
significantly different than amounts currently accrued and disclosed, with the result that our financial
condition and results of operations could be materially affected by changes in the assumptions or
estimates related to these contingencies.
With respect to environmental liabilities and related costs we develop estimates based on a
review of information available from numerous sources, including completed studies and site specific
negotiations. Using sampling data, feasibility studies, existing technology and enacted laws and
regulations, we estimate that the total future expenditures for environmental investigation, monitoring
and remediation are $61.0 million as of December 31, 2010. It is our policy to accrue the full amount
of such liability when information is sufficient to reasonably estimate the amount of probable liability.
When information is not available to reasonably estimate the probable liability, or when only the range
of probable liabilities can be estimated and no amount within the range is more likely than another,
then it is our policy to accrue at the lower end of the range. Accordingly, due to numerous uncertainties
surrounding the course of environmental remediation and the preliminary nature of several site
investigations, in some cases, we may not be able to reasonably estimate the high end of the range of
possible loss. In those cases we have disclosed the nature of the potential loss and the fact that the high
end of the range cannot be reasonably estimated.
We will continue to seek recovery of such costs through insurance and through customer rates,
and we believe recovery of these costs is probable. If it is determined that both the insurance recovery
and future rate recovery of such costs are not probable, the costs will be charged to expense in the
period such determination is made. See Note 15.
Results of Operations
Regulatory Matters
Regulation and Rates
We are subject to regulation with respect to, among other matters, rates and systems of
accounts by the OPUC, the WUTC, FERC, and with respect to Gill Ranch, the CPUC. The OPUC and
WUTC and, with respect to Gill Ranch, the CPUC, also regulate our issuance of securities. In 2010,
approximately 90 percent of our utility gas volumes were delivered to, and utility operating revenues
were derived from, Oregon customers and the balance from Washington customers. Future earnings
and cash flows from utility operations will be determined largely by the Oregon and Washington
economies in general, and by the pace of growth in the residential and commercial markets in
particular, and by our ability to remain price competitive, control expenses, and obtain reasonable and
timely regulatory recovery for our utility gas costs, operating and maintenance costs and investments
made in utility plant.
General Rate Cases
Oregon. In our most recent general rate case in Oregon, which was effective in September
2003, the OPUC authorized rates to customers based on a return on common stock equity (ROE) of
10.2 percent. In 2007, in connection with the renewal of our conservation tariff and weather
normalization rate mechanism, the OPUC approved a stipulation that restricts us from filing a general
rate case with the OPUC prior to September 2011, subject to certain exceptions. Under the agreement,
we would be allowed to file a general rate case if an extraordinary event occurs or significant
investments are required on behalf of our customers and we are unable to reach agreement regarding
52
alternative forms of cost recovery outside of a general rate case. These exceptions might include
additional investments in our pipeline integrity management program. This agreement does not impact
our ability to file annual rate adjustments to reflect changes in gas purchase costs under our PGA
mechanism or our ability to collect or refund prior year’s gas cost deferrals. See “Rate Mechanisms—
Purchased Gas Adjustment,” below.
Washington. In our most recent general rate case in Washington, the WUTC authorized rates
to customers based on a ROE of 10.1 percent, which is included as part of an overall rate of return on
total invested capital of 8.4 percent. These customer rates went into effect on January 1, 2009, with
annual revenue requirements increased by $2.7 million, or 3 percent.
Federal. We are required under our Mist interstate storage certificate authority and rate
approval orders to file every five years either a petition for rate approval or a cost and revenue study to
change or justify maintaining the existing rates for our interstate storage services. Our most recent
filing of a cost and revenue study was in April 2008. As a result of that proceeding, the current
maximum cost-based rates for our interstate gas storage services were approved by FERC, with
maximum rates unchanged from prior levels approved by FERC in 2005. In addition, we made a filing
in December 2008 to obtain FERC approval to revise the depreciation rates associated with Mist assets
used to derive the cost-based interstate storage rates. These new depreciation rates were designed to
match the depreciation rates for the same type of assets approved under state regulation. We did not
make any changes to the previously approved maximum rates, and FERC approved the depreciation
rate filing in May 2009. We are required to make our next cost and revenue study filing at FERC on or
before December 11, 2013.
California. Gill Ranch is authorized by the CPUC to charge market-based rates for the
intrastate storage services offered to customers in California.
Rate Mechanisms
Purchased Gas Adjustment. Rate changes are established for the utility each year under PGA
mechanisms in Oregon and Washington to reflect changes in the expected cost of natural gas
commodity purchases, including contract gas purchase prices, gas prices hedged with financial
derivatives, gas inventory prices, interstate pipeline demand costs, the application of temporary rate
adjustments to amortize balances in deferred regulatory accounts and the removal of temporary rate
adjustments effective for the previous year.
In October 2010, the OPUC and WUTC approved PGA rate changes effective on November 1,
2010. The effect of these rate changes was to decrease the average monthly bills of Oregon and
Washington residential customers by 2 percent. This is our second consecutive year of rate decreases.
The OPUC and WUTC also approved rate decreases effective November 1, 2009 of 16 percent and 22
percent in Oregon and Washington, respectively.
Under the current PGA mechanism in Oregon, there is an incentive sharing provision whereby
we are required to select by August 1 of each year either an 80 percent deferral or a 90 percent deferral
of higher or lower actual gas costs compared to estimated PGA prices such that the impact on current
earnings from the incentive sharing is either 20 percent or 10 percent of the difference between actual
and estimated gas costs, respectively. In addition to the gas cost incentive sharing mechanism, we are
subject to an annual earnings review to determine if the utility is earning above its allowed ROE
threshold. If utility earnings exceed a specific ROE level, then 33 percent of the amount above that
53
level will be deferred for refund to customers. Under this provision, if we select the 80 percent deferral
option, then we retain all of our earnings up to 150 basis points above the currently authorized ROE. If
we select the 90 percent deferral option, then we retain all of our earnings up to 100 basis points above
the currently authorized ROE. We selected the 90 percent deferral option for both the 2009-2010 and
the 2010-2011 PGA years. The ROE threshold is subject to adjustment up or down annually based on
movements in long-term interest rates. In September 2010, we received the final report from the OPUC
on our 2009 earnings review, which indicated a utility regulated ROE of 11.2 percent. This is below
the allowed ROE threshold of 11.5 percent, and therefore no earnings were deferred for refund to
customers. Based upon utility results through December 31, 2010, we expect to refund approximately
$0.5 million to customers.
There has been no change to the Washington PGA mechanism under which we defer 100
percent of the higher or lower actual gas costs and pass that difference through to customers as an
adjustment to future rates. We do not have an earnings or gas cost sharing mechanism in Washington.
Conservation Tariff. In October 2002, the OPUC authorized the implementation of a
“conservation tariff” to adjust utility margin for changes in consumption patterns due to residential and
commercial customers’ conservation efforts. The conservation tariff is a decoupling mechanism that is
intended to break the link between utility earnings and the quantity of gas consumed by customers,
removing any financial incentive by the utility to discourage customers’ efforts to conserve energy. In
Washington, customer use is not covered by a conservation or decoupling tariff, and as such our utility
earnings are affected by increases and decreases in usage based on customers’ conservation
efforts. Washington customers account for about 10 percent of our utility volumes and revenues.
The Oregon conservation tariff includes two components: (1) an annual price elasticity
adjustment, which adjusts rates for increases or decreases from expected customer volumes due to
changes in commodity costs or changes in our general rates; and (2) a monthly conservation
adjustment, which adjusts margin revenues to account for the difference between actual and expected
customer volumes (also referred to as the decoupling adjustment). The margin adjustment resulting
from differences between actual and expected volumes under the decoupling component is recorded to
a deferral account, which is included in the next year’s annual PGA filing. Baseline consumption was
determined by customer consumption data used in the 2003 Oregon general rate case and is adjusted
annually for customer growth and the effect of the price elasticity adjustment discussed above. See
“Business Segments—Utility Operations,” below.
In 2005, an independent study to measure the effectiveness of Oregon’s conservation tariff
mechanism recommended continuation of the tariff with minor modifications, which tariff was
approved by the OPUC and extended through October 2012.
Weather Normalization. In Oregon, we have an OPUC approved weather normalization
mechanism. This mechanism is designed to help stabilize the collection of fixed costs by adjusting
residential and commercial customer billings based on temperature variances from average weather,
with rate decreases when the weather is colder than average and rate increases when the weather is
warmer than average. The mechanism is applied to residential and commercial customers’ bills
between December 1 and May 15 of each heating season. The mechanism adjusts the margin
component of customers’ rates to reflect average weather, which uses the 25-year average temperature
for each day of the billing period. Daily average temperatures and 25-year average temperatures are
based on a set point temperature of 59 degrees Fahrenheit for residential customers and 58 degrees
Fahrenheit for commercial customers (see “Business Segments—Utility Operations,” below). The
54
weather normalization mechanism for Oregon utility operations is approved through October 2012.
Customers in Oregon are allowed to opt out of the weather normalization mechanism, and as of
December 31, 2010, 9 percent had elected to opt out. We do not have a weather normalization
mechanism approved for our Washington customers, which account for about 10 percent of our utility
volumes and revenues.
Industrial Tariffs. The OPUC and WUTC have approved tariffs covering utility service to our
major industrial customers, including terms which are intended to give us certainty in the level of gas
supplies we need to acquire to serve this customer group. The terms include an annual election period,
special pricing provisions for out-of-cycle changes and a requirement that industrial customers under
our annual PGA tariff complete the term of their service election.
System Integrity Program. In 2004, the OPUC approved specific accounting treatment and
cost recovery for our transmission pipeline integrity management program, a program mandated by the
Pipeline Safety Improvement Act of 2002 and the related rules adopted by the U.S. Department of
Transportation’s Pipeline and Hazardous Materials Safety Administration (PHMSA). We record these
costs as either capital expenditures or regulatory assets, accumulate the costs over each 12-month
period, and recover the revenue requirement associated with the costs, subject to audit, through rate
changes effective with the annual PGA in Oregon.
Congress passed the Pipeline Inspection, Protection, Enforcement, and Safety Act in 2006
which included a legislative mandate for PHMSA to prescribe minimum standards for integrity
management programs for natural gas distribution pipelines. The PHMSA issued a proposed rule for
distribution integrity management programs in June 2008.
In February 2009, the OPUC approved a stipulated agreement to create a new, consolidated
system integrity program (SIP). The SIP integrates the company’s bare steel replacement, transmission
pipeline integrity management and distribution pipeline integrity management programs into a single
program. In December 2009, the PHMSA issued the final rule for distribution integrity management
programs. Our SIP costs are tracked into rates annually, with rate recovery after the first $3.3 million
of capital costs. An annual cap for expenditures has been set at $12 million, but extraordinary costs
above the cap may be approved with written consent of the OPUC staff and other interested parties and
approval of the OPUC. The SIP allows recovery of costs incurred in Oregon during the period from
October 2008 through October 2011, or until the effective date of new rates adopted in our next general
rate case. The company has initiated discussions with the OPUC and other interested parties to extend
the term of the SIP. We do not have any special accounting or rate treatment for SIP costs incurred in
the state of Washington.
In 2011 Congress is expected to pass legislation continuing PHMSA’s authority to oversee the
nation’s hazardous liquid and natural gas pipeline infrastructure. The pipeline safety legislation will
likely include mandates for additional pipeline safety requirements; however, it is not possible to
determine the materiality of possible new pipeline safety regulations at this time.
Regulatory Recovery for Environmental Costs. The OPUC has authorized us to defer
environmental costs associated with certain named sites and to accrue interest on environmental cost
balances, subject to an annual demonstration that we have maximized our insurance recovery or made
substantial progress in securing insurance recovery for unrecovered environmental expenses. These
authorizations have been extended through January 2010. We have filed a request for an extension of
55
this deferral and expect to receive this authorization during the first quarter of 2011. See Note 15. In
February 2011, we filed a request with the WUTC to defer environmental costs associated with
services provided to Washington customers.
Pension Deferral. In March 2010, we filed a request with the OPUC for authorization to defer
pension expenses above the amount set in rates, and to recover the amount through a balancing account
that would include the effects of anticipated higher and lower pension expenses in future years. The
OPUC approved the pension cost balancing account effective January 1, 2011, with accrued interest on
the account balance at the utility’s authorized rate of return. The estimated reduction to operation and
maintenance expense for 2011 is approximately $4 to $5 million. Future year deferrals will depend on
changes in plan assets and projected benefit liabilities using a number of key assumptions, as well as
our pension contributions. See “Application of Critical Accounting Policies and Estimates,” above.
Customer Refunds for Gas Storage Sharing. In June 2010, $11 million was credited to utility
customers from our regulatory incentive sharing mechanism related to gas storage and optimization
services of pipeline capacity and gas storage at Mist (see “Gas Storage,” below). In June 2009, we
credited $7.2 million to customers under the same regulatory mechanism.
Business Segments—Utility Operations
Our utility margin results are affected by customer growth and to a certain extent by changes in
weather and customer consumption patterns, with a significant portion of our earnings being derived
from natural gas sales to residential and commercial customers. In Oregon, we have a conservation
tariff that adjusts revenues to offset changes in margin resulting from increases or decreases in
residential and commercial customer consumption. We also have a weather normalization mechanism
in Oregon that adjusts customer bills up or down to offset changes in margin resulting from above- or
below-average temperatures during the winter heating season (see “Results of Operations—Regulatory
Matters—Rate Mechanisms,” above). Both mechanisms are designed to reduce the volatility of our
utility earnings.
2010 compared to 2009:
Our utility segment in 2010 earned $66.3 million, or $2.49 per share, compared to $66.0
million, or $2.48 per share in 2009. The major factors contributing to the change were reduced
operating expenses largely offset by lower utility margins, which consisted of a $13.5 million decrease
from the prior year’s gas cost incentive sharing, partially offset by a net $5 million increase in margin
from residential and commercial customers, including the effects of the weather normalization and
decoupling mechanisms and a $0.7 million increase in industrial margin. Total utility volumes sold and
delivered in 2010 decreased by 6 percent over last year due to the effects of warmer weather on
residential and commercial use and the lingering effects of a weak economy on commercial use. The
regulatory adjustment for income taxes paid also increased margin by $1.8 million compared to 2009.
Our weather normalization mechanism adjusted residential and commercial margins up by
$14.0 million for the year ended December 31, 2010 based on weather that was 2 percent warmer than
average, compared to a margin reduction of $15.2 million for the year ended December 31, 2009 when
weather was 3 percent colder than average. Our decoupling mechanism adjusted residential and
commercial margins up by $15.5 million in 2010, after adjusting for expected price elasticity impacts
from lower PGA prices effective November 1, 2009, compared to margin adjustments totaling $11.6
million in 2009.
56
2009 compared to 2008:
Our utility segment in 2009 earned $66.0 million, or $2.48 per share, compared to $58.7
million, or $2.21 per share in 2008. The major factor contributing to the increase in utility margin was
a $20.6 million increase in our gas cost incentive sharing from lower gas prices. Total utility volumes
sold and delivered in 2009 decreased by 10 percent compared to 2008 due to the effects of warmer
weather on residential and commercial use and the effects of a weak economy on commercial and
industrial use. Margin was reduced by $11.4 million in 2009 compared to 2008 due to a customer rate
decrease which corresponded to a decrease in depreciation rates and expense effective January 1,
2009. Excluding the impact of lower depreciation rates on revenues, our margin from residential and
commercial customers increased by $5.2 million in 2009, including the effects of the weather
normalization and decoupling mechanisms. Industrial margin declined $2.1 million, but would have
decreased by $1.3 million if the depreciation rate impact was excluded. The regulatory adjustment for
income taxes paid also increased margin by $4.1 million in 2009 compared to 2008, primarily due to
the cost of gas savings in 2009.
Our weather normalization mechanism adjusted residential and commercial margins down by
$15.2 million for the year ended December 31, 2009 based on weather that was 3 percent colder than
average, compared to a reduction of $15.3 million for the year ended December 31, 2008 when
weather was 7 percent colder than average. Our decoupling mechanism increased residential and
commercial margin by $11.6 million in 2009, after adjusting for expected price elasticity impacts from
higher PGA prices effective November 1, 2008, compared to a margin increase of $4.9 million in 2008.
57
The following table summarizes the composition of gas utility volumes and revenues for the
years ended December 31, 2010, 2009 and 2008:
Thousands, except degree day and
customer data
Utility volumes - therms:
Residential sales
Commercial sales
Industrial - firm sales
Industrial - firm transportation
Industrial - interruptible sales
Industrial - interruptible transportation
Total utility volumes sold and delivered
Utility operating revenues - dollars:
Residential sales
Commercial sales
Industrial - firm sales
Industrial - firm transportation
Industrial - interruptible sales
Industrial - interruptible transportation
Regulatory adjustment for income taxes paid(1)
Other revenues
Total utility operating revenues
Cost of gas sold
Revenue taxes
Utility margin
Utility margin: (2)
Residential sales
Commercial sales
Industrial - sales and transportation
Miscellaneous revenues
Gain (loss) from gas cost incentive sharing
Other margin adjustments
Margin before regulatory adjustments
Weather normalization adjustment
Decoupling adjustment
Regulatory adjustment for income taxes paid(1)
Utility margin
Customers - end of period:
Residential customers
Commercial customers
Industrial customers
Total number of customers - end of period
Actual degree days
2010
2009
2008
Favorable/(Unfavorable)
2010
vs. 2009
2009
vs. 2008
368,682
230,196
37,085
127,796
58,387
239,823
1,061,969
412,867
255,593
39,447
124,218
72,525
226,715
1,131,365
428,787
265,531
47,340
184,832
87,484
246,777
1,260,751
(44,185)
(25,397)
(2,362)
3,578
(14,138)
13,108
(69,396)
(15,920)
(9,938)
(7,893)
(60,614)
(14,959)
(20,062)
(129,386)
$ 456,174 $ 555,844 $ 566,840
298,943
46,579
6,370
68,978
7,918
1,760
21,784
1,019,172
656,504
25,072
$ 346,148 $ 357,005 $ 337,596
292,697
41,407
5,671
62,116
7,964
5,884
21,166
992,749
611,088
24,656
227,994
30,830
5,702
36,164
8,131
7,721
17,917
790,633
424,494
19,991
$ 197,045 $ 217,124 $ 224,683
90,402
29,771
6,381
(5,505)
436
346,168
(15,266)
4,934
1,760
$ 346,148 $ 357,005 $ 337,596
85,850
27,713
6,670
15,064
2,308
354,729
(15,236)
11,628
5,884
77,831
28,451
4,658
1,594
(647)
308,932
13,996
15,499
7,721
610,598
62,489
910
673,997
604,692
62,169
933
667,794
599,285
62,115
941
662,341
4,171
4,383
4,576
(64,703)
(10,577)
31
(25,952)
167
1,837
(3,249)
(202,116)
186,594
4,665
$ (99,670) $ (10,996)
(6,246)
(5,172)
(699)
(6,862)
46
4,124
(618)
(26,423)
45,416
416
$ (10,857) $ 19,409
$ (20,079) $
(8,019)
738
(2,012)
(13,470)
(2,955)
(45,797)
29,232
3,871
1,837
(7,559)
(4,552)
(2,058)
289
20,569
1,872
8,561
30
6,694
4,124
$ (10,857) $ 19,409
5,906
320
(23)
6,203
5,407
54
(8)
5,453
Percent colder (warmer) than average weather(3)
(2)%
3%
7%
(1) Regulatory adjustment for income taxes paid is described below.
(2) Amounts reported as margin for each category of customers are net of cost of gas sold and revenue taxes.
(3) Average weather represents the 25-year average degree days, as determined in our last Oregon general rate
case.
58
In June 2009, we refunded gas cost savings totaling $35.8 million to our Oregon and
Washington customers. The following non-GAAP table summarizes the impact of this refund on our
operating revenues, cost of gas sold and margin for the year ended December 31, 2009, along with a
comparison to the years ended December 31, 2010 and 2008. We believe this non-GAAP financial
calculation enables the reader of the financial statements to better understand our operating revenues,
cost of gas sold and utility margin performance from management’s perspective in addition to the
traditional GAAP presentation.
Thousands
Utility operating revenues:
Residential sales
Commercial sales
Industrial - firm sales
Industrial - firm transportation
Industrial - interruptible sales
Industrial - interruptible transportation
Regulatory adjustment for income taxes paid
Other revenues
Total utility operating revenues
Cost of gas sold
Revenue taxes
Utility margin
2009
As
2010
Reported Refund
$456,174
227,994
30,830
5,702
36,164
8,131
7,721
17,917
790,633
424,494
19,991
$555,844
292,697
41,407
5,671
62,116
7,964
5,884
21,166
992,749
611,088
24,656
$19,952
11,579
1,585
-
2,673
-
-
-
35,789
34,691
898
Excluding
Refund
(Non-
GAAP)
$ 575,796
304,276
42,992
5,671
64,789
7,964
5,884
21,166
1,028,538
645,779
25,554
2008
$ 566,840
298,943
46,579
6,370
68,978
7,918
1,760
21,784
1,019,172
656,504
25,072
$346,148
$357,005
$
200
$ 357,205
$ 337,596
The non-GAAP information disclosed above reconciles to the preceding table summarizing
utility margin for the years ended December 31, 2010, 2009 and 2008.
Residential and Commercial Sales
The primary factors that impact results of operations in the residential and commercial markets
are customer growth, seasonal weather patterns, energy prices, competition from other energy sources
and economic conditions in our service areas. Typically, 80 percent or more of our annual utility
operating revenues are derived from gas sales to weather-sensitive residential and commercial
customers. Although variations in temperatures between periods will affect volumes of gas sold to
these customers, the effect on margin and net income is significantly reduced due to our weather
normalization mechanism in Oregon where about 90 percent of our customers are served. For more
information on our weather mechanism, see “Regulatory Matters—Rate Mechanisms—Weather
Normalization,” above.
59
The primary changes that impacted margin from residential and commercial sales were as
follows:
2010 compared to 2009:
•
•
•
gas sales volumes were 10 percent lower, primarily reflecting 5 percent warmer weather,
conservation efforts and weak economic conditions;
utility operating revenues decreased $164.4 million or 19 percent primarily due to the 10
percent volume decline and customer rate decreases of 16 and 22 percent in Oregon and
Washington, respectively, effective November 1, 2009; and
utility margin increased $5 million or 2 percent primarily due to customer growth of 0.9
percent and colder weather in the spring of 2010 that was not offset by the Oregon weather
normalization mechanism.
2009 compared to 2008:
•
•
•
volumes were 4 percent lower, primarily reflecting 4 percent warmer weather,
conservation efforts and weak economic conditions;
utility operating revenues decreased $17.2 million or 2 percent primarily due to $31.5
million in customer refunds for gas cost savings, partially offset by customer rate increases
of 14 and 21 percent in Oregon and Washington, respectively, effective November 1, 2008,
and customer growth of 0.8 percent; and
utility margin decreased $5.4 million or 4 percent primarily due to lower volumes and
customer rate decreases related to new depreciation rates.
Industrial Sales and Transportation
Industrial sales and transportation revenues include the commodity cost component of gas sold
under sales service but not under transportation service. Therefore, industrial customers switching
between sales service and transportation service can cause swings in operating revenues but generally
our margins are unaffected because our rates do not mark up the cost of gas. As such, we believe
margin is a better measure of performance for the industrial sector. The primary changes that impacted
margin from industrial sales and transportation were as follows:
2010 compared to 2009:
volumes delivered to industrial customers increased 0.2 million therms; and
•
• margin increased $0.7 million, or 3 percent.
2009 compared to 2008:
•
volumes delivered to industrial customers decreased 104 million therms, or 18 percent,
reflecting reduced usage due to weak economic conditions; and
• margin decreased $2.1 million, or 7 percent, reflecting lower volumes and customer rate
decreases related to new depreciation rates, but that was partially offset by fixed charges not
affected by declining use.
Several industrial customers transferred from sales service to transportation service in 2010 and
2009. Changes in natural gas prices can result in industrial customers switching between sales and
60
transportation service. In such cases, our tariff allows us to charge the incremental cost of gas supply
incurred, if any, to serve those customers so that the cost does not adversely impact our margins or the
prices our residential and commercial customers pay.
Regulatory Adjustment for Income Taxes Paid
Oregon law requires regulated natural gas and electric utilities to annually review the amount of
income taxes collected in rates from utility operation and compare it to the amount the utility actually
pays to taxing authorities. Under this law, if we pay less in income taxes related to utility operations
than we collect from Oregon utility customers, or if our utility taxes paid are less than the taxes we
collect from Oregon utility customers, then we are required to refund the excess to our Oregon utility
customers. Conversely, if we pay more income taxes than we actually collect from Oregon utility
customers, then we are required to collect a surcharge from Oregon utility customers.
For the 2008 and 2009 tax years, the OPUC approved our tax filings to recover $0.2 million
and $5.1 million, respectively, through a surcharge to Oregon utility customers. It was agreed that the
2008 surcharge, plus accrued interest, would be collected over a one-year period beginning June 1,
2010. It was also agreed that the 2009 surcharge, plus accrued interest, would be collected over a
one-year period beginning June 1, 2011. For the 2010 tax year, we estimated the difference between
income taxes paid and the amounts collected in rates will result in a surcharge of $7.1 million
(excluding interest). The 2009 surcharge was primarily driven by gains from gas cost savings related to
our PGA incentive sharing mechanism. The 2010 surcharge was primarily driven by gas cost savings
related to our PGA incentive sharing as well as lower utility operating expenses and higher residential,
commercial and industrial margins.
Other Revenues
Other revenues include miscellaneous fee income as well as revenue adjustments reflecting
deferrals to, or amortizations from, regulatory asset or liability accounts, except for gas cost deferrals
which flow through cost of gas sold. Other revenues increased net operating revenues by $17.9 million
in 2010, compared to $21.1 million in 2009 and $21.8 million in 2008.
2010 compared to 2009:
Other revenues decreased $3.2 to $17.9 in 2010 primarily reflecting an increase in decoupling
amortization totaling $7.9 million, partially offset by a $4.0 million increase in the refund to utility
customers related to the gas storage regulatory sharing mechanism.
2009 compared to 2008:
Other revenues in 2009 were $0.7 million lower than in 2008 primarily reflecting a $6.3 million
decrease in the regulatory surcharge for income taxes paid and a $0.7 million decrease in curtailment
charges, partially offset by a $7.4 million refund to utility customers related to the gas storage
regulatory sharing mechanism.
Cost of Gas Sold
The cost of gas sold includes gas purchases, gas drawn from storage inventory, gains and losses
from commodity hedges, pipeline demand costs, seasonal demand cost balancing adjustments,
regulatory gas cost deferrals and company gas use. Our regulated utility does not generally earn a
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profit or incur a loss on gas commodity purchases. The OPUC and the WUTC require the natural gas
commodity cost to be billed to customers at the same cost incurred or expected to be incurred by the
utility. However, under the PGA mechanism in Oregon, our net income is affected by differences
between actual and expected purchased gas costs, which occur primarily because of market
fluctuations and volatility affecting unhedged gas purchases (see “Regulatory Matters—Rate
Mechanisms—Purchased Gas Adjustment,” above). We use natural gas derivatives, primarily fixed-
price commodity swaps, consistent with our financial derivatives policies to help manage our exposure
to rising gas prices. Gains and losses from financial hedge contracts are generally included in our PGA
prices and normally do not impact net income as the hedges are usually 100 percent passed through to
customers in annual rate changes, subject to a regulatory prudency review. However, utility gas hedges
entered into after the annual PGA filing in Oregon may impact net income to the extent of our share of
any gain or loss under the PGA. In Washington, 100 percent of the actual gas costs, including hedge
gains and losses allocated to Washington gas sales, are passed through in customer rates (see
“Application of Critical Accounting Policies and Estimates—Accounting for Derivative Instruments
and Hedging Activities,” and “Regulatory Matters—Rate Mechanisms—Purchased Gas Adjustment,”
above, and Note 15). The following summarizes the major factors that contributed to changes in cost of
gas sold:
2010 compared to 2009:
•
•
•
total cost of gas sold decreased $186.6 million, or 31 percent, due to an 6 percent decrease
in total sales volumes and a 22 percent decrease in the average cost of gas sold per therm;
the average gas cost collected through rates decreased from 78 cents per therm in 2009 to
61 cents per therm in 2010, primarily reflecting lower gas prices that were passed on
through PGA rate decreases effective November 1, 2009 and 2010; and
hedge losses totaling $61.0 million were realized and included in cost of gas sold for the
year ended December 31, 2010, compared to $187.9 million of hedge losses in the same
period of 2009.
2009 compared to 2008:
•
•
•
total cost of gas sold decreased $45.4 million, or 7 percent, primarily due to a 10 percent
decrease in total sales volumes and $34.7 million for gas cost savings refunded to
customers;
the average gas cost collected through rates decreased 1 percent from 79 cents per therm in
2008 to 78 cents per therm in 2009, primarily reflecting the reduction to cost of gas sold
from customer refunds in 2009, partially offset by our 14 to 21 percent PGA rate increases
effective November 1, 2008; and
net losses totaling $187.9 million were realized from our financial hedges and included in
cost of gas sold, compared to $35.1 million of net hedge gains in 2008.
In 2010, actual gas costs were slightly below those embedded in rates, while in 2009 they were
significantly lower and in 2008 they were higher. The effect on shareholders from the gas cost
incentive sharing mechanism was a contribution to margin of $1.6 million in 2010 and $15.1 million in
2009 compared to a margin loss of $5.5 million in 2008. For a discussion of our gas cost incentive
sharing mechanism, see “Regulatory Matters—Rate Mechanisms—Purchased Gas Adjustment,”
above.
62
Gas Storage
Our gas storage segment currently consists of the non-utility portion of our Mist underground
storage facility, non-utility asset optimization and start-up costs at Gill Ranch. For the year ended
December 31, 2010, we earned $6.1 million, or 23 cents per share, from our gas storage segment
compared to $8.9 million, or 34 cents per share, for the same period in 2009. This decrease is primarily
due to start-up costs at Gill Ranch.
We provide gas storage services to customers in the interstate and intrastate markets from our
Mist gas storage field in Oregon, primarily using storage capacity that has been developed in advance
of core utility customers’ requirements. Under a regulatory incentive sharing mechanism in Oregon,
we retain 80 percent of pre-tax income from our Mist gas storage services and from optimization
services when the costs of the capacity being used are not included in utility rates, and 33 percent of
pre-tax income from such storage and optimization services when the capacity being used is pipeline or
is included in utility rates. The remaining 20 percent and 67 percent, respectively, are credited to a
deferred regulatory account for credit to our core utility customers. We have a similar sharing
mechanism in Washington for pre-tax income derived from gas storage and optimization services.
We have a joint agreement with PG&E to develop, own and operate an underground natural gas
storage facility near Fresno, California. Our 75 percent undivided ownership interest in the project is
held by our wholly-owned subsidiary, Gill Ranch, which is also the sole operator of the project. The
construction of this facility began in January 2010, and a majority of the construction work was
completed by October 2010. Our portion of the initial development is designed to provide 15 Bcf of
gas storage capacity by the end of 2013 and a 75 percent undivided interest in approximately 27 miles
of gas transmission pipeline. Gill Ranch began operations during the fourth quarter of 2010. See
Note 4.
Other
Our other business segment consists of NNG Financial, an investment in PGH, and other
non-utility investments and business activities. NNG Financial had total assets of $1.1 million and $1.4
million as of December 31, 2010 and 2009, respectively, primarily reflecting a non-controlling
minority interest in the Kelso-Beaver pipeline. Our net equity investment in PGH as of December 31,
2010 and 2009 was $14.8 million and $14.1 million, respectively. Total earnings from our other
business segment as of December 31, 2010 and 2009 was net income of $0.3 million and $0.2 million,
respectively. See Note 4.
Consolidated Operations
Operations and Maintenance
Operations and maintenance expense was $121 million in 2010, compared to $127.1 million in
2009, a decrease of $6.1 million or 5 percent. The following summarizes the major factors that
contributed to changes in operations and maintenance expense:
2010 compared to 2009:
•
a $5.6 million decrease in utility payroll expense related to a reduced number of employees.
There was a reduction of 105 employees or 9 percent over the two year period beginning
January 2009;
63
•
•
•
•
a $2.4 million decrease in utility bad debt expense (see below for further discussion);
a $1.9 million decrease in pension expense, due to the increase in market value of plan
investments from contributions in 2009 and 2010;
a $1.5 million decrease in health care and other employee benefit expense due to reduced
employee count;
a $0.2 million decrease in damage claims in 2010.
Partially offsetting the above factors were:
•
•
a $4.9 million increase in gas storage expenses, primarily related to start-up costs including
salaries and benefits, power costs, legal fees and investment bank consulting costs; and
a $1.0 million increase for consulting and legal fees at the utility related to a successful
property tax appeal.
2009 compared to 2008:
•
•
•
•
•
an $8.0 million increase in pension expense primarily due to lower assumed discount rates
and a decrease in our plans’ funded status, which resulted from a significant decline in the
market value of assets during 2008;
a $5.3 million increase in employee labor and benefit expense due to higher health care
premiums and higher bonuses related to above-target operating results, which affect annual
incentive payments and compensation;
a $1.1 million charge related to our voluntary severance program involving workforce
reductions during the third and fourth quarters of 2009;
a $1.1 million increase in strategic initiatives including performance improvement and
corporate tax projects; and
a $1.0 million increase in utility bad debt expense (see discussion below).
Partially offsetting the above increases were:
•
•
a $2.1 million decrease in employee compensation expense related to reduced employee
count; and
a $0.6 million decrease in claims in 2009.
Our bad debt expense as a percent of revenues was 0.21 percent for the year ended
December 31, 2010, compared to 0.42 percent for the same period last year. The 2010 lower bad debt
expense ratio was partly due to improved collections and increased recoveries from delinquent account
balances. Credit risks are still somewhat high due to the weak economy and high unemployment rates,
but our credit exposure has improved as evidenced by a decrease in delinquent account balances over
last year. Lower customer usage from warmer than normal weather this past winter coupled with
customer conservation, lower gas prices and low income energy assistance funds have contributed to
our reduced credit exposure.
Health care costs have been trending higher, and it was recently reported that local and national
health care cost increases were expected to be between 10 and 12 percent in 2011. Based on recent
premium notices, we estimate that our employee health and welfare benefit costs for 2011 will increase
by approximately 5 percent, including potential changes imposed by health care reform.
64
In addition, our pension costs are expected to increase in 2011. However, effective January 1,
2011 the OPUC approved the deferral of utility pension expense above the amount recovered in rates,
which was set in our last general rate case. The pension expense deferral will be recorded to a
regulatory balancing account, and we expect it will result in a $4 to $5 million decrease in operations
and maintenance expense for 2011. For further explanation of the pension balancing account, see
“Regulatory Matters—Rate Mechanisms—Pension Deferral,” above.
General Taxes
General taxes, which are principally comprised of property and payroll taxes and regulatory
fees, decreased $4.4 million, or 16 percent, in 2010 compared to 2009, and increased $1.6 million, or 6
percent, in 2009 compared to 2008. The major factors that contributed to changes in general taxes are:
2010 compared to 2009:
•
a $5.2 million refund of property taxes received in 2010 pursuant to a favorable ruling from
the Oregon Supreme Court regarding taxation of utility gas inventory held for sale (see
below for further discussion), partially offset by an increase in property taxes related to a 2
percent increase in net utility plant balances.
2009 compared to 2008:
•
•
a $1.0 million or 5 percent increase in property taxes related to a 3 percent increase in net
utility plant balances; and
a $0.5 million increase in payroll taxes due to higher incentive compensation and employee
severance compensation in 2009.
Over the past several years, we had been involved in litigation with the Oregon Department of
Revenue over whether inventories held for sale were required to be taxed as personal property. In
January 2010, the Oregon Supreme Court unanimously ruled in our favor, stating that these inventories
were exempt from property tax. As a result of this ruling, we were entitled to a refund of approximately
$5.2 million, plus accrued interest, for property taxes paid on inventories beginning with the 2002-03
tax year. We recognized a net $6.1 million increase in pre-tax income in the first quarter of 2010,
which consisted of $5.2 million for the refund of property taxes, $1.9 million for accrued interest
income, and $1.0 million of increased operations and maintenance expense for legal and consulting
services. We received all of the property tax refunds.
Depreciation and Amortization
Total depreciation and amortization expense in 2010 increased by $2.3 million, or 4 percent, as
compared to a $9.3 million or 13 percent decrease in 2009 over 2008. The increased expense in 2010
was primarily related to Gill Ranch going into service in the fourth quarter of 2010 plus the additional
investments in utility plant for customer growth and system improvements. The decreased expense in
2009 was primarily related to the adoption of the new depreciation rates, which were approved by the
OPUC, WUTC and FERC effective January 1, 2009 (see “Regulatory Matters—Rate Mechanisms,”
above).
65
Other Income and Expense—Net
The following table provides details on other income and expense – net for the last three years:
Thousands
Gains from company-owned life insurance
Interest income
Income from equity investments
Net interest on deferred regulatory accounts
Gain on sale of investments
Other non-operating
Total other income and expense - net
2010 compared to 2009:
2010
2009
2008
$ 2,042
2,024
588
4,692
223
(2,467)
$ 3,416
211
1,329
2,051
45
(3,338)
$ 2,190
250
667
552
1,737
(1,650)
$ 7,102
$ 3,714
$ 3,746
Other income and expense—net increased $3.4 million, primarily due to $1.9 million of interest
income related to property tax refund plus a $2.6 million increase in interest from regulatory account
balances largely due to smaller balances in gas costs between 2010 and 2009, partially offset by a $1.4
million decrease in income from life insurance due to higher policy gains realized in 2009.
2009 compared to 2008:
Other income and expense—net decreased by less than $0.1 million in 2009 over 2008. The
decrease was primarily due to a net increase in other non-operating expense for higher business
development costs and other strategic planning expense in 2009, and from a gain on sale of an aircraft
realized in 2008. These were partially offset by increases in income from life insurance, income from
our equity investment in Palomar and interest income from deferred regulatory account balances.
Interest Expense—Net
Interest expense—net of amounts capitalized in 2009 increased by $1.9 million, or 5 percent,
compared to 2009, and increased in 2009 by $3.1 million, or 8 percent, compared to 2008. Increases in
interest expense over the last two years reflect the issuance of long-term debt during 2009, which
included $75 million of 5.37 percent medium term notes (MTN’s) issued in March and $50 million of
3.95 percent MTN’s issued in July, and higher short-term debt balances in 2010. Higher interest
expense also reflects a lower average interest rate used in calculating the allowance for funds used
during construction, which is referred to as AFUDC. AFUDC rates, comprised of short-term and long-
term capital costs as appropriate, were 0.6 percent in 2010, 1.0 percent in 2009 and 3.6 percent in 2008.
Income Tax Expense
The increase in income tax expense of $2.8 million or 6 percent, compared to 2009 was
primarily due to higher pre-tax consolidated earnings and an increase in our effective tax rate of 40.5
percent in 2010 compared to 38.3 percent in 2009. Income tax expense increased $6.0 million, or 15
percent, for the year ended December 31, 2009 compared to 2008, primarily due to higher pre-tax
consolidated earnings and a slightly higher effective tax rate of 38.3 percent in 2009 compared to 36.9
percent in 2008.
For the 2010 tax year, the higher effective tax rate was primarily the result of increased
amortization of our regulatory tax account on pre-1981 utility plant assets (see “Regulatory Matters—
Rate Mechanisms,” above) and a lower non-taxable gain on company-owned life insurance. For the
66
2009 tax year, the higher effective tax rate was primarily the result of an increase in the Oregon
corporate income tax rate (see below for further discussion), an increased amortization of our
regulatory tax asset account on pre-1981 plant assets, and an adjustment to deferred income taxes
attributed to our non-regulated business segments. For more information on our income taxes,
including a reconciliation between the statutory federal and state income tax rates and the effective
rate, see Note 2 and Note 10.
In July 2009, the governor of Oregon signed House Bill 3405 establishing increases in the state
income tax rate for corporations, and Oregon voters approved this legislation in January 2010. The
corporate income tax rate in Oregon increased from 6.6 percent to 7.9 percent for tax years 2009 and
2010 when taxable income is greater than $250,000. For tax years 2011 and 2012, the income tax rate
will decrease to 7.6 percent, and for years after 2012 the tax rate will return to 6.6 percent, except for
corporations with taxable income over $10 million the tax rate will remain at 7.6 percent. Following
existing accounting guidance on income taxes, we re-measured our deferred income tax assets and
liabilities, resulting in an adjustment to increase the balance by $3.6 million in 2009. Approximately $3.5
million of the adjustment was attributed to our utility operations. As we anticipate future recovery in
rates, we recorded a $5.8 million regulatory asset for the grossed up revenue requirement. With respect to
our non-utility business segments, a $0.1 million adjustment was charged to income tax expense in 2009.
On March 23, 2010, the Patient Protection and Affordable Care Act (the PPACA) was signed
into law, and on March 30, 2010 the Health Care and Education Reconciliation Act of 2010 was signed
into law. The PPACA changes the tax treatment of federal subsidies paid to sponsors of retiree health
benefit plans that provide a benefit that is at least actuarially equivalent to the benefits under Medicare
Part D. These subsidy payments become taxable in years beginning after December 31, 2012.
Accounting guidance on income taxes requires the impact of this tax law change to be immediately
recognized in the period that includes the enactment date. This provision of the PPACA did not have,
and is not expected to have, an impact on our financial condition, results of operations or cash flows as
we were not receiving federal subsidy payments under Medicare Part D.
Financial Condition
Capital Structure
One of our long-term goals is to maintain a strong consolidated capital structure, generally
consisting of 45 to 50 percent common stock equity and 50 to 55 percent long-term and short-term
debt. When additional capital is required, debt or equity securities are issued depending upon both the
target capital structure and market conditions. These sources also are used to fund long-term debt
redemption requirements and short-term commercial paper maturities (see “Liquidity and Capital
Resources,” below, and Notes 7 and 8). Achieving the target capital structure and maintaining
sufficient liquidity to meet operating requirements are necessary to maintain attractive credit ratings
and have access to capital markets at reasonable costs. Our consolidated capital structure was as
follows for the years ended December 31, 2010 and 2009:
Common stock equity
Long-term debt
Short-term debt, including current maturities of long-term debt
Total
67
December 31,
2010
44.7%
38.1%
17.2%
100%
2009
47.2%
43.0%
9.8%
100%
Liquidity and Capital Resources
At December 31, 2010, we had $3.5 million of cash and cash equivalents compared to $8.4
million at December 31, 2009. We also had $0.9 million in restricted cash invested at Gill Ranch as of
December 31, 2010, compared to $35.5 million as of December 31, 2009, which was being held as
collateral for equipment purchase contracts and construction loans. In order to maintain sufficient
liquidity during periods of volatile capital markets, at times we will maintain higher cash balances, add
short-term borrowing capacity, and pre-fund utility capital expenditures while long-term fixed rate
environments are attractive. Our short-term liquidity is supported by cash balances, internal cash flow
from operations, proceeds from the sale of commercial paper notes, committed multi-year credit
facilities, cash available from surrender value in company-owned life insurance policies, and proceeds
from the sale of long-term debt. We use long-term debt proceeds to finance utility capital expenditures,
refinance maturing short-term and long-term debt and provide for general corporate purposes. In
March 2009, we issued $75 million of secured MTNs with an interest rate of 5.37 percent and a
maturity date of February 1, 2020. In July 2009, we issued $50 million of secured MTNs with an
interest rate of 3.95 percent and a maturity date of July 15, 2014.
The capital markets in the last two years, including the commercial paper market, experienced
significant volatility and tight credit conditions, but conditions over the past 12 months improved as
reflected by tighter credit spreads and increased access to new financing for investment grade issuers.
With our current debt ratings (see “Credit Ratings,” below), we have been able to issue commercial
paper and MTNs at attractive rates and have not needed to borrow from our back-up credit facilities. In
the event that we are not able to issue new debt due to market conditions, we expect that our near term
liquidity needs can be met by using cash balances or drawing upon our committed credit facilities. We
also have a universal shelf registration filed with the Securities and Exchange Commission for the
issuance of secured and unsecured debt or equity securities, subject to market conditions and
regulatory approvals. We have OPUC approval to issue up to $175 million of additional MTNs under
the existing shelf registration, which was filed in January 2011.
In the event that our senior unsecured long-term debt credit ratings are downgraded, or our
outstanding derivative position exceeds a certain credit threshold, our counterparties under derivative
contracts could require us to post cash, a letter of credit or other form of collateral, which could expose
us to additional cash requirements and may trigger significant increases in short-term borrowings. If
the credit risk-related contingent features underlying these contracts were triggered on December 31,
2010, we could have been required to post $27.3 million of collateral to our counterparties, but that
assumes our long-term debt ratings were at non-investment grade levels (see Note 13 and “Credit
Ratings,” below).
Recent developments that may have an impact on our liquidity and capital resources include
pension contributions, tax benefits and environmental expenditures and insurance recoveries. With
respect to pension requirements, we expect to make additional contributions in 2011 and in future years
until we are fully funded under the Pension Protection Act rules (see “Pension Cost and Funding Status
of Qualified Retirement Plans,” below). With respect to federal income tax liabilities, an extension was
granted that allows us to take 50 percent bonus depreciation on a majority of our capital expenditures
in 2010, and 100 percent bonus depreciation on qualified expenditures during 2011, which will
significantly reduce our tax liability for the 2010 and 2011 tax years thereby providing cash flow
benefits in late 2010 and 2011 (see “Cash Flows—Operating Activities,” below). And with respect to
environmental liabilities, we expect to continue using cash resources to fund our environmental
68
liabilities, but we also anticipate recovering amounts through insurance or utility rates over the next
several years, although the amount and timing of these expenditures and recoveries is uncertain (see
Note 15).
In addition, Gill Ranch began commercial operations in October 2010. Although we anticipate
future operating cash flows, the amount and timing of these cash flows are uncertain.
In July 2010, the U.S. Congress passed and President Obama signed into law the “Wall Street
Reform and Consumer Protection Act.” The new legislation will require additional government
regulation of derivative and over-the-counter transactions, and could expand collateral requirements.
While we are currently evaluating the new legislation to determine its impact, if any, on our hedging
procedures, results of operations, financial position and liquidity, we do not expect to know the full
impact of the legislation until final regulations implementing the legislation are issued.
Based on several factors, including our current credit ratings, recent experience issuing
commercial paper, current cash reserves, committed credit facilities and other liquidity resources, and
our expected ability to issue long-term debt in the form of an MTN program under our universal shelf
registration, we believe our liquidity is sufficient to meet anticipated near-term cash requirements,
including all contractual obligations and investing and financing activities discussed below.
Dividend Policy
We have paid quarterly dividends on our common stock each year since the stock was first
issued to the public in 1951. Annual common stock dividend payments per share, adjusted for stock
splits, have increased each year since 1956. The amount and timing of dividends payable on our
common stock is within the sole discretion of our Board of Directors. Subject to Board approval, we
expect to continue paying quarterly cash dividends on common stock. However, the declarations and
amount of future dividends will depend upon our earnings, cash flows, financial condition and other
factors including Board approval.
Off-Balance Sheet Arrangements
Except for certain lease and purchase commitments (see “Contractual Obligations,” below), we
have no material off-balance sheet financing arrangements.
69
Contractual Obligations
The following table shows our contractual obligations at December 31, 2010 by maturity and
type of obligation.
Thousands
Payments Due in Years Ending December 31,
2015
2013
2011
2012
2014
Thereafter
Total
Commercial paper
Long-term debt maturities
Interest on long-term debt
Postretirement benefit payments (1)
Capital leases
Operating leases
Gas purchase contracts (2)
Gas pipeline commitments
Other purchase commitments (3)
$257,435 $
10,000
36,840
20,741
482
4,984
111,514
90,510
51,511
- $
40,000
34,518
21,198
330
4,937
19,310
56,610
3,284
- $
-
33,607
21,492
178
4,909
13,684
48,953
638
- $
- $
60,000
33,446
22,131
9
5,152
11,404
25,059
-
40,000
31,951
22,719
-
5,034
-
17,853
-
- $ 257,435
601,700
420,179
237,014
999
53,185
155,912
492,239
55,433
451,700
249,817
128,733
-
28,169
-
253,254
-
Total
$584,017 $180,187 $123,461 $157,201 $117,557 $1,111,673 $2,274,096
(1)
The majority of postretirement benefit payments are related to our qualified defined benefit
pension plans, which are funded by plan assets and future cash contributions. See Note 9.
(2) All gas purchase contracts use price formulas tied to monthly index prices. Commitment amounts
are based on index prices at December 31, 2010.
Excludes a noncash Gill Ranch agreement for $13.5 million of cushion gas.
(3)
Other purchase commitments primarily consist of remaining balances under existing purchase
orders. These and other contractual obligations are financed through cash from operations and from the
issuance of short-term debt, which is periodically refinanced through the sale of long-term debt or
equity securities.
At December 31, 2010, 607 of our utility employees were members of the Office and
Professional Employees International Union, Local No. 11. In July 2009, our union employees ratified
a new five-year labor agreement called the Joint Accord. The agreement included a scheduled 1
percent wage increase each year, with the potential for up to an additional 2 percent per year based on
wage inflation and other factors. The Joint Accord also maintains competitive health benefits while
limiting the cost increases for these benefits to the same level as the annual wage increases, and
provides increased job flexibility along with the ability for the Company to use short-term unpaid leave
to temporarily adjust the workforce without layoffs. The Joint Accord continues our defined benefit
retirement plan and post retiree medical for existing union employees as of December 31, 2009, but
closes the plan to new employees hired after December 31, 2009. The term of the new Joint Accord
extends to May 31, 2014, and thereafter from year to year unless either party serves notice of its intent
to negotiate modifications to the collective bargaining agreement.
Short-term Debt
Our primary source of utility short-term liquidity is from internal cash flows and the sale of
commercial paper. In addition to issuing commercial paper to meet working capital requirements,
including seasonal requirements to finance gas inventories and accounts receivable, short-term debt
may also be used to temporarily fund utility capital requirements. Commercial paper is periodically
refinanced through the sale of long-term debt or equity securities. Our outstanding commercial paper,
70
which is sold through two commercial banks under an issuing and paying agency agreement, is
supported by one or more unsecured revolving credit facilities (see “Credit Agreements,” below). Our
commercial paper program did not experience any liquidity disruptions as a result of the credit
problems that affected issuers of asset-backed commercial paper and certain other commercial paper
programs over the last several years. At December 31, 2010 and 2009, our utility had commercial
paper outstanding of $257.4 million and $69.8 million, respectively. The effective interest rate on the
utility’s commercial paper outstanding at December 31, 2010 and 2009 was 0.4 percent and 0.3
percent, respectively.
In March 2009, Gill Ranch entered into a cash collateralized credit facility for up to $40
million, which was extended through September 30, 2010. In June 2010, Gill Ranch repaid its $40
million bank loan outstanding using the proceeds from its cash collateralized account. The effective
interest rate on the Gill Ranch credit facility was 0.8 percent during 2010.
Credit Agreements
We have a syndicated multi-year credit agreement for unsecured revolving loans totaling $250
million, which may be extended for additional one-year periods subject to lender approval. All lenders
agreed to extend the original term for an additional one-year period through May 31, 2013. We also
have three bilateral credit agreements totaling $50 million in effect from November 30, 2010 through
March 31, 2011. All lenders under our syndicated and bilateral credit agreements are major financial
institutions with committed balances and investment grade credit ratings as of December 31, 2010 as
follows:
Lender rating, by category
AAA/Aaa
AA/Aa
A/A
BBB/Baa
Total
Loan Commitment Amounts in Thousands
Syndicated
Facility
$
-
230,000
20,000
-
$250,000
Bilateral
Facility
$
-
50,000
-
-
$50,000
Based on credit market conditions, it is possible that one or more lending commitments could
be unavailable to us if the lender defaulted due to lack of funds or insolvency. However, based on our
current assessment of our lenders’ creditworthiness, including a review of capital ratios, credit default
swap spreads and credit ratings, we believe the risk of lender default is minimal.
As discussed above, we extended commitments with all seven lenders under the syndicated
agreement, with commitments totaling $250 million, to May 31, 2013. The syndicated agreement also
allows us to request increases in the total commitment amount from time to time, up to a maximum
amount of $400 million, and to replace any lenders who decline to extend the maturity date of the
credit agreement. The syndicated agreement also permits the issuance of letters of credit in an
aggregate amount up to the applicable total borrowing commitment.
Any principal and unpaid interest owed on borrowings under the syndicated and bilateral
agreements are due and payable on or before the maturity date. There were no outstanding balances
under these credit agreements at December 31, 2010 and 2009. These agreements also require us to
maintain a consolidated indebtedness to total capitalization ratio of 70 percent or less. Failure to
71
comply with this covenant would entitle the lenders to terminate their lending commitments and
accelerate the maturity of all amounts outstanding. We were in compliance with this covenant at
December 31, 2010 and 2009, with consolidated indebtedness to total capitalization ratios of 55.4
percent and 52.8 percent, respectively.
The syndicated and bilateral agreements also require that we maintain credit ratings with
Standard & Poor’s (S&P) and Moody’s Investors Service (Moody’s) and notify the lenders of any
change in our senior unsecured debt ratings by such rating agencies. A change in our debt ratings by
S&P or by Moody’s is not an event of default, nor is the maintenance of a specific minimum level of
debt rating a condition of drawing upon the credit agreement. However, a change in our debt rating
below BBB- or Baa3 would require additional approval from the OPUC prior to issuance of debt, and
interest rates on any loans outstanding under the credit agreements are tied to debt ratings, which
would increase or decrease the cost of any loans under the credit agreements when ratings are changed
(see “Credit Ratings,” below).
All three lenders under the short-term credit agreements are existing lenders under our
syndicated credit agreement. The short-term credit agreements require us to comply with the terms and
conditions of the syndicated credit agreement and give the lenders under the short-term credit
agreements the same rights with respect to the short-term credit agreements that they have under the
syndicated credit agreement.
Credit Ratings
Our debt credit ratings are a factor in our liquidity, affecting our access to the capital markets,
including the commercial paper market. Our debt credit ratings also have an impact on the cost of
funds and the need to post collateral under derivative contracts. A change in our ratings below BBB-
by S&P or Baa3 by Moody’s would require additional approval from the OPUC prior to our issuing
additional long-term debt.
The following table summarizes our current debt ratings from S&P and Moody’s:
Commercial paper (short-term debt)
Senior secured (long-term debt)
Senior unsecured (long-term debt)
Corporate credit rating
Ratings outlook
S&P
A-1
A+
n/a
A+
Stable
Moody’s
P-1
A1
A3
n/a
Stable
The above credit ratings are dependent upon a number of factors, both qualitative and
quantitative, and are subject to change at any time. The disclosure of these credit ratings is not a
recommendation to buy, sell or hold NW Natural securities. Each rating should be evaluated
independently of any other rating.
72
Redemptions of Long-Term Debt
We redeemed MTN’s during 2010, 2009 and 2008 as follows:
Thousands (Years ended December 31)
Medium-Term Notes
6.50% Series B due 2008
6.65% Series B due 2027 (1)
4.11% Series B due 2010
7.45% Series B due 2010
Amounts Redeemed
2009
2010
2008
$
-
-
10,000
25,000
$
-
300
-
-
$5,000
-
-
-
$35,000
$ 300
$5,000
(1)
In November 2009, $0.3 million of our 6.65 percent secured MTNs due 2027 were redeemed pursuant to a
one-time put option. This one-time put option has now expired, and the $19.7 million remaining principal
outstanding is expected to be paid at maturity in November 2027.
Cash Flows
Operating Activities
2010 compared to 2009:
For the year ended December 31, 2010, cash flow from operating activities totaled $126.5
million compared to $240.3 million in 2009 and $34.7 million in 2008. The significant factors
contributing to changes in operating cash flow in 2010 compared to 2009 are as follows:
•
•
•
•
•
•
•
•
an increase of $39.6 million from deferred income taxes, primarily reflecting higher tax
benefits from bonus depreciation taken in 2010 related to Gill Ranch capital investments
placed in service;
an increase of $15.0 million from a smaller pension contribution in 2010 compared to 2009;
an increase of $10.1 million from the 2009 settlement of an interest rate hedge;
a decrease of $75 million from accrued taxes, primarily related to 2010 benefits that will be
refunded in 2011, and due to tax refunds received in 2009 related to a change in tax
accounting method for repairs and maintenance costs;
a decrease of $62.9 million from changes in deferred gas cost regulatory account which
reflects actual gas prices compared to estimated gas prices embedded in customer rates;
a decrease of $19.7 million from changes in receivables primarily due to higher balances at
the end of 2008, which benefitted cash flows during 2009;
a decrease of $14.5 million from changes in inventories primarily due to higher price of gas
in inventory at the end of 2008, which benefitted cash flows during 2009 as higher cost
inventories were recovered through utility rates; and
a decrease of $13.0 million in accounts payable due to decreased Gill Ranch construction
activity at the end of 2010 compared to the end of 2009.
In September 2010, Congress passed the Unemployment Insurance, Reauthorization and Job
Creation Act of 2010 (the Act) and the legislation was signed into law by President Obama. The Act
extends for one additional year the temporary bonus depreciation rules first enacted in the Economic
Stimulus Act of 2008 and subsequently renewed in the American Recovery and Reinvestment Act of
2009. Under the bonus depreciation provision, an additional first-year tax deduction is allowed for
73
depreciation equal to 50 percent of the adjusted basis of qualified property through September 8, 2010,
and 100 percent through December 31, 2011, in the year the property is placed in service, and the
remaining percentage recovered under the normal depreciation rules. The 50 percent depreciation
deduction in the first year is an acceleration of depreciation deductions that otherwise would have been
taken in the later years of an asset’s recovery period. As a result of this extension, we will recognize an
increase in our cash flow by reducing our current tax liabilities for the 2010 and 2011 tax years. Any
deductions in excess of income for federal income tax purposes will be carried back to the 2009 tax
year. As of December 31, 2010, we have a federal and state income tax receivable balance of $41.1
million, which we expect to realize in cash flows during 2011.
2009 compared to 2008:
In 2009, cash flow from net income and operating activity adjustments, excluding working
capital changes, increased $29.1 million compared to 2008. Working capital changes in 2009 increased
$176.5 million compared to the same period in 2008. The total change in cash flow from operating
activities was an increase of $205.6 million. The significant factors contributing to the operating cash
flow changes between 2009 and 2008 are as follows:
•
•
•
•
•
•
•
•
an increase of $82.1 million from deferred gas cost savings reflecting lower actual gas
prices compared to gas prices collected in customer rates in 2009, net of amounts already
refunded to customers (see below);
an increase of $72.0 million from decreases in accounts receivable and accrued unbilled
revenue primarily due to the collection of higher balances in accounts receivable and
accrued unbilled revenue balances at year end 2008;
an increase of $41.6 million from income tax refunds received from a change in tax
accounting method for certain repairs and maintenance costs (see below);
an increase of $31.2 million related to the net decrease in gas inventory balances due to the
higher price of gas injected into storage in 2008;
an increase of $25.7 million from accounts payable, reflecting lower gas prices at the end of
2009 compared to 2008;
a decrease of $25.0 million related to our pension contributions in 2009 to reduce our
unfunded liability;
a decrease of $13.4 million from deferred income taxes, reflecting the approved tax
deduction for repair and maintenance costs (see below); and
a decrease of $10.1 million related to the loss realized on the settlement of our interest rate
hedge in 2009.
In June and July of 2009, we refunded $35.8 million to our Oregon and Washington customers
for the customers’ share of accumulated gas cost savings from November 1, 2008 through March 31,
2009. This reduction in cash was part of the gas cost savings accumulated from lower gas prices during
the 2008-09 gas contract year. Additional savings for Oregon and Washington customers accumulated,
and these amounts were refunded to customers through lower rates starting November 1, 2009 and
November 1, 2010.
In December 2008, we filed an application with the IRS that requested a change in our tax
accounting method to expense routine repair and maintenance costs for gas pipelines that are currently
being capitalized and depreciated for book purposes. The IRS consented to our request in August 2009,
and we recognized a tax deduction of approximately $59 million on our 2008 tax return, which resulted
in a federal tax refund of approximately $21 million during the fourth quarter of 2009.
74
At December 31, 2008, we reported an estimated net operating loss (NOL) for federal and
Oregon income tax purposes of $19.2 million and $23.8 million, respectively, primarily due to the
effects of accelerated tax depreciation provided by the Economic Stimulus Act. As a result of the
change in our tax accounting method for repair and maintenance costs discussed above as well as our
increased pension contribution, our NOL for federal and Oregon income tax purposes was $89.0
million and $87.2 million on our 2008 federal and Oregon tax returns, respectively. The federal NOL
was carried back to 2006 for a refund of taxes paid in prior years, while the Oregon NOL has been
carried forward to reduce current and future taxable income. We anticipate that we will be able to use
all loss carryforwards in future years. The 2008 Oregon NOL was fully utilized in 2009.
We have lease and purchase commitments relating to our operating activities that are financed
with cash flows from operations. For information on cash flow requirements related to leases and other
purchase commitments, see “Contractual Obligations,” above and Note 15.
Investing Activities
Cash used in investing activities for the year ended December 31, 2010 totaled $212.9 million,
up from $162.1 million for the same period in 2009. Our capital expenditures were $248.5 million in
the year ended December 31, 2010, up from $135.1 million for the same period in 2009. Utility capital
expenditures decreased $14.6 million in 2010 primarily due to our automated meter reading project
that was completed in 2009, while our non-utility capital expenditures increased $128.1 million
primarily due to construction at Gill Ranch.
Cash used in investing activities during 2010 was partially offset by the release of restricted
cash, which had collateralized equipment purchase contracts and bank loans for Gill Ranch. Restricted
cash increased $65.1 million compared to 2009, due to settling our cash collateralized loan in June
2010.
In 2011, capital expenditures are estimated to be between $95 million and $105 million for the
utility, and between $5 million and $15 million for non-utility development projects that are currently
in process (see “Strategic Opportunities,” above). Over the five-year period 2011 through 2015, total
utility capital expenditures are estimated at between $400 and $500 million. The estimated level of
utility capital expenditures over the next five years reflects assumptions for customer growth, storage
development at Mist for the utility, technology investments and utility distribution improvements,
including requirements under the current Pipeline Safety programs. Most of the required funds are
expected to be internally generated over the five-year period, and any remaining funding will be
obtained through the issuance of long-term debt or equity securities, with short-term debt providing
liquidity and bridge financing.
Cumulatively at December 31, 2010, we have spent a total of $214.7 million in capital costs at
Gill Ranch, including $3.2 million of construction work-in-progress.
In 2011, Palomar expects to continue working on the planning and permitting phase of the east
segment of the proposed pipeline. The incremental cost to obtain the appropriate permits is estimated
to be $10 million, of which our ownership interest is 50 percent. The initial planning and permitting
costs are being financed with equity funds from us and our partner, GTN. Also, Northwest Pipeline has
contributed some funding toward planning and permitting costs in accordance with the terms of the
MOU. For more information, see Note 12 and “Strategic Opportunities—Pipeline Diversification,”
above.
75
Financing Activities
Cash provided by financing activities for the year ended December 31, 2010 totaled $81.4
million, up from cash used of $76.7 million for the same period in 2009. Our short-term debt balances
increased $155.4 million for the year ended December 31, 2010, compared to a decrease of $158.9
million for the same period in 2009, which was partially driven by our long-term debt issuances of
$125 million in 2009. We use long-term debt proceeds primarily to finance capital expenditures,
refinance short-term and long-term debt maturities as well as for general corporate purposes.
We have a repurchase program approved through May 2011 which provides authorization to
repurchase up to 2.8 million shares or up to $100 million. The purchases are made in the open market
or through privately negotiated transactions. No repurchases were made in 2010, 2009 or 2008 under
the program. Since the program’s inception, we have repurchased an aggregate 2.1 million shares of
common stock at a total cost of $83.3 million, at the average price of $39.19 per share (see Part II,
Item 5, “Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer
Purchases of Equity Securities,” above).
In 2010, we produced negative free cash flow of $131.1 million, compared to positive free cash
flow of $35.8 million in 2009 and negative free cash flow of $115.3 million in 2008. Free cash flow is
the amount of cash remaining after the payment of all cash expenses, capital expenditures (investment
activities) and dividends. Free cash flow is a non-GAAP financial measure, but we believe this
supplemental information enables the reader of the financial statements to better understand our cash
generating ability and to benefit from seeing cash flow results from management’s perspective in
addition to the traditional GAAP presentation. We monitor free cash flow as one measure of our return
on investments. Provided below is a reconciliation from cash provided by operations (GAAP basis) to
our non-GAAP free cash flow.
Thousands
Cash provided by operating activities
Cash used in investing activities
Cash dividend payments on common stock
Free cash flow
2010
2009
2008
$ 126,469
(212,871)
(44,652)
$ 240,335
(162,141)
(42,415)
$ 34,721
(109,825)
(40,178)
$(131,054) $ 35,779
$(115,282)
The free cash flow information presented above is not intended to be a substitute for, nor is it
meant to be a better measure of, cash flow results prepared in accordance with GAAP. In addition, the
non-GAAP measure we provide may be calculated differently by other companies that present a
similar non-GAAP financial measure for cash flow.
Pension Cost and Funding Status of Qualified Retirement Plans
Pension costs are determined in accordance with accounting standards for compensation and
retirement benefits (see “Application of Critical Accounting Policies and Estimates—Accounting for
Pensions and Postretirement Benefits,” above). Pension costs for our two qualified defined benefit
plans, which are allocated between operation expenses and capital expenditures based on employee
payroll distributions, totaled $11.4 million in 2010, a decrease of $3.2 million from 2009.
The fair market value of pension assets in these two plans increased to $219.0 million at
December 31, 2010 from $201.3 million at December 31, 2009. The increase was due to a positive
return on plan assets of $24.7 million and a $10.0 million employer contribution, partially offset by
benefit payments of $17.0 million.
76
We make contributions to company-sponsored qualified defined benefit pension plans based on
actuarial assumptions and estimates, tax regulations and funding requirements under federal law. Our
qualified defined benefit pension plans were underfunded by $95.4 million at December 31,
2010. In March 2010, we contributed $10 million to these plans, with a portion allocated to 2009 and
2010 plan years. We plan to make contributions during 2011 of approximately $22 million. For more
information on the funding status of our qualified retirement plans and other postretirement benefits,
see Note 9.
We also contribute to a multiemployer pension plan (Western States Plan) pursuant to our
collective bargaining agreement. We made contributions totaling $0.4 million to the Western States
Plan in both 2010 and 2009. See Note 9 for further discussion.
Ratios of Earnings to Fixed Charges
For the years ended December 31, 2010, 2009 and 2008, our ratios of earnings to fixed charges,
computed using the Securities and Exchange Commission method, were 3.73, 3.86, and 3.76,
respectively. For this purpose, earnings consist of net income before taxes plus fixed charges, and fixed
charges consist of interest on all indebtedness, the amortization of debt expense and discount or
premium and the estimated interest portion of rentals charged to income. See Exhibit 12.
Contingent Liabilities
Loss contingencies are recorded as liabilities when it is probable that a liability has been
incurred and the amount of the loss is reasonably estimable in accordance with accounting standards
for contingencies (see “Application of Critical Accounting Policies and Estimates,” above). At
December 31, 2010, we had a regulatory asset of $114.3 million for deferred environmental costs,
which includes $55.6 million for additional costs expected to be paid in the future and accrued interest
of $14 million. If it is determined that both the insurance recovery and future customer rate recovery of
such costs are not probable, then the costs will be charged to expense in the period such determination
is made. For further discussion of contingent liabilities, see Note 15.
New Accounting Pronouncements
For a description of recent accounting pronouncements that may have an impact on our
financial condition, results of operations or cash flows, see Note 2.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
We are exposed to various forms of market risk including commodity supply risk, commodity
price risk, interest rate risk, foreign currency risk, credit risk and weather risk. The following describes
our exposure to these risks.
Commodity Supply Risk
We enter into spot, short-term and long-term natural gas supply contracts, along with associated
pipeline transportation contracts, to manage our commodity supply risk. Historically, we have arranged
for physical delivery of an adequate supply of gas, including gas in our Mist storage facility, to meet
the expected requirements of our core utility customers. Our gas purchase contracts are primarily
index-based and subject to monthly re-pricing, a strategy that is intended to reflect market price trends
during the upcoming year.
77
Commodity Price and Storage Value Risk
Natural gas commodity prices and storage values are subject to market fluctuations due to
unpredictable factors including weather, pipeline transportation congestion, drilling technologies,
potential market speculation and other factors that affect short-term supply and demand. In addition to
managing storage positions through a combination of short- and long-term fixed price contracts,
commodity-price financial swap and option contracts (financial hedge contracts) are used to convert
certain natural gas supply contracts from floating prices to fixed or capped prices for utility gas
purchases. These financial hedge contracts are generally included in our annual PGA filing for
recovery, subject to a regulatory prudence review. We regularly monitor and manage the financial
exposure and liquidity risk of our storage positions and financial hedge contracts.
Interest Rate Risk
We are exposed to interest rate risk primarily associated with new debt financing needed to
fund capital requirements, including future contractual obligations and maturities of long-term and
short-term debt. Interest rate risk is primarily managed through the issuance of fixed-rate debt with
varying maturities. We may also enter into financial derivative instruments, including interest rate
swaps, options and other hedging instruments, to manage and mitigate interest rate exposure.
Foreign Currency Risk
The costs of certain natural gas commodity supplies and certain pipeline services purchased
from Canadian suppliers are subject to changes in the value of the Canadian currency in relation to the
U.S. currency. Foreign currency forward contracts are used to hedge against fluctuations in exchange
rates with respect to purchases of natural gas from Canadian suppliers. At December 31, 2010 and
2009, notional amounts under foreign currency forward contracts totaled $13.9 million and $6.6
million, respectively. As of December 31, 2010 , all foreign currency forward contracts mature within
one year. If all of the foreign currency forward contracts had been settled on December 31, 2010, a
gain of $0.1 million would have been realized (see Note 13).
Credit Risk
Credit exposure to suppliers. Certain suppliers that sell us gas have either relatively low
credit ratings or are not rated by major credit rating agencies. To manage this supply risk, we purchase
gas from a number of different suppliers at liquid exchange points. We evaluate and monitor suppliers’
creditworthiness and maintain the ability to require additional financial assurances, including deposits,
letters of credit or surety bonds, in case a supplier defaults. In the event of a supplier’s failure to deliver
contracted volumes of gas, the regulated utility would need to replace those volumes at prevailing
market prices, which may be higher or lower than the original transaction prices. We believe these
costs would be subject to the PGA sharing mechanism discussed above. Since most of our commodity
supply contracts are priced at the monthly market index price tied to liquid exchange points, and we
have significant storage flexibility, we believe that it is unlikely that a supplier default would have an
adverse effect on our financial condition or results of operations.
Credit exposure to financial derivative counterparties. Based on estimated fair value at
December 31, 2010, our overall credit exposure relating to commodity hedge contracts is considered to
be immaterial as it reflects amounts we owed to our financial derivative counterparties totaling $52.7
million. However, changes in natural gas prices could result in counterparties owing us money.
78
Therefore our financial derivatives policy requires counterparties to have at least an investment-grade
credit rating at the time the derivative instrument is entered into, and specific limits on the contract
amount and duration based on each counterparty’s credit rating. Due to potential changes in market
conditions and credit concerns, we continue to enforce strong credit requirements. We actively monitor
and manage our derivative credit exposure and place counterparties on hold for trading purposes or
require cash collateral, letters of credit or guarantees as circumstances warrant. As of December 31,
2010, we do not have any actual derivative credit risk exposure, which reflects amounts that financial
derivative counterparties owe to us.
The following table summarizes our overall credit exposure, based on estimated fair value, and
the corresponding counterparty credit ratings. The table uses credit ratings from S&P and Moody’s,
reflecting the higher of the S&P or Moody’s rating or a middle rating if the entity is split-rated with
more than one rating level difference:
Thousands
AAA/Aaa
AA/Aa
A/A
BBB/Baa
Total
Financial Derivative Position by Credit Rating
Unrealized Fair Value Gain (Loss)
2009
2010
$
-
(43,656)
(9,017)
-
$(52,673)
$
-
(15,792)
-
-
$(15,792)
In most cases, we also mitigate the credit risk of financial derivatives by having master netting
arrangements with our counterparties which provide for making or receiving net cash settlements.
Generally, transactions of the same type in the same currency that have a settlement on the same day
with a single counterparty are netted and a single payment is delivered or received depending on which
party is due funds.
Additionally we have master contracts in place with each of our derivative counterparties that
include provisions for posting or calling for collateral. Generally we can obtain cash or marketable
securities as collateral with one day’s notice. We use various collateral management strategies to
reduce liquidity risk. The collateral provisions vary by counterparty but are not expected to result in the
significant posting of collateral, if any. We have performed stress tests on the portfolio and concluded
that the liquidity risk from collateral calls is not material. Our derivative credit exposure is primarily
with investment grade counterparties rated AA-/Aa3 or higher. Contracts are diversified across
counterparties to reduce credit and liquidity risk.
Credit exposure to insurance companies for environmental damage claims. We regularly
monitor the financial condition of insurance companies who provide general liability insurance policy
coverage to NW Natural and its predecessors with respect to environmental damage claims. We have
filed claims for our environmental costs with a number of insurance companies. The majority of these
companies have credit ratings of A- or better from A.M. Best Co. (AM Best). AM Best is a global
independent credit rating agency who has provided quantitative and qualitative analysis of insurance
company balance sheet strength for over 100 years. AM Best uses a rating scale that ranges from A++
(“Superior” financial strength) to F (“In Liquidation”), with a rating of A- considered “Excellent.” A
strong credit rating from AM Best is not a guarantee that an insurance company will be able to meet its
contractual obligations. The remaining insurance companies who do not have credit ratings of A- or
79
better are expected to have sufficient funds in reserves to cover these claims. Our credit exposure to
insurance companies for environmental claims, which reflects amounts we believe are owed to us,
could be material. In the event we are unable to recover environmental expenses from these insurance
policies, we will seek recovery of unreimbursed amounts through customer rates.
Weather Risk
We are exposed to weather risk primarily from our regulated utility business. A large
percentage of our utility margin is volume driven, and current rates are based on an assumption of
average weather. In 2003, the OPUC approved a weather normalization mechanism for residential and
commercial customers. This mechanism affects customer bills between December 1 through May 15 of
each winter heating season, increasing or decreasing the margin component of customers’ rates to
reflect gas usage based on “average” weather using the 25-year average temperature for each day of
the billing period. The mechanism is intended to stabilize the recovery of our utility’s fixed costs and
reduce fluctuations in customers’ bills due to colder or warmer than average weather. Customers in
Oregon are allowed to opt out of the weather normalization mechanism. As of December 31, 2010,
approximately 9 percent of our Oregon customers had opted out. In addition to the Oregon customers
opting out, our Washington residential and commercial customers account for approximately 10
percent of our total customer base and are not covered by weather normalization. The combination of
Oregon and Washington customers not covered by a weather normalization mechanism is less than 20
percent of all residential and commercial customers.
80
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Table of Contents
1.
2.
3.
4.
5.
Management’s Report on Internal Control Over Financial Reporting . . . . . . . . . . . . . . . . .
Report of Independent Registered Public Accounting Firm . . . . . . . . . . . . . . . . . . . . . . . .
Consolidated Financial Statements:
Consolidated Statements of Income for the Years Ended December 31, 2010,
2009 and 2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Consolidated Balance Sheets at December 31, 2010 and 2009 . . . . . . . . . . . . . . . . . . . . . .
Page
82
83
84
85
Consolidated Statements of Shareholders’ Equity and Comprehensive Income for the
Years Ended December 31, 2010, 2009 and 2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
87
Consolidated Statements of Cash Flows for the Years Ended December 31, 2010,
2009 and 2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Notes to Consolidated Financial Statements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
88
89
Quarterly Financial Information (unaudited) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
129
Supplementary Data for the Years Ended December 31, 2010, 2009 and 2008:
Financial Statement Schedule
Schedule II—Valuation and Qualifying Accounts and Reserves . . . . . . . . . . . . . . . . . . . .
130
Supplemental Schedules Omitted
All other schedules are omitted because of the absence of the conditions under which they are
required or because the required information is included elsewhere in the financial statements
81
MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
Management is responsible for establishing and maintaining adequate internal control over
financial reporting as defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of
1934, as amended. Our internal control over financial reporting is designed to provide reasonable
assurance regarding the reliability of financial reporting and the preparation of financial statements for
external purposes in accordance with generally accepted accounting principles in the United States of
America (GAAP). Our internal control over financial reporting includes those policies and procedures
that:
(i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly
reflect the transactions and dispositions involving company assets;
(ii) provide reasonable assurance that transactions are recorded as necessary to permit the
preparation of financial statements in accordance with GAAP, and that receipts and expenditures
are being made only in accordance with authorizations of management and the Board of
Directors; and
(iii) provide reasonable assurance regarding prevention or timely detection of the
unauthorized acquisition, use or disposition of our assets that could have a material effect on the
financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or
detect misstatements or fraud. Also, projections of any evaluation of effectiveness to future periods are
subject to the risk that controls may become inadequate because of changes in conditions, or that the
degree of compliance with the policies or procedures may deteriorate.
Management assessed the effectiveness of our internal control over financial reporting as of
December 31, 2010. In making this assessment, management used the criteria set forth by the
Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control-
Integrated Framework.
Based on our assessment and those criteria, management has concluded that we maintained
effective internal control over financial reporting as of December 31, 2010.
The effectiveness of internal control over financial reporting as of December 31, 2010 has been
audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated
in their report which appears in this annual report.
/s/ Gregg S. Kantor
Gregg S. Kantor
President and Chief Executive Officer
/s/ David H. Anderson
David H. Anderson
Senior Vice President and Chief Financial Officer
February 25, 2011
82
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders of
Northwest Natural Gas Company:
In our opinion, the consolidated financial statements listed in the accompanying table of contents present fairly, in all
material respects, the financial position of Northwest Natural Gas Company and its subsidiaries at December 31,
2010 and 2009, and the results of their operations and their cash flows for each of the three years in the period
ended December 31, 2010 in conformity with accounting principles generally accepted in the United States of
America. In addition, in our opinion, the financial statement schedule listed in the accompanying table of
contents presents fairly, in all material respects, the information set forth therein when read in conjunction with the
related consolidated financial statements. Also in our opinion, the Company maintained, in all material respects,
effective internal control over financial reporting as of December 31, 2010, based on criteria established in Internal
Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission
(COSO). The Company’s management is responsible for these financial statements and financial statement schedule,
for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal
control over financial reporting, included in the accompanying Management’s Report on Internal Control over
Financial Reporting. Our responsibility is to express opinions on these financial statements, on the financial statement
schedule, and on the Company’s internal control over financial reporting based on our integrated audits. We conducted
our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those
standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial
statements are free of material misstatement and whether effective internal control over financial reporting was
maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and
significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of
internal control over financial reporting included obtaining an understanding of internal control over financial
reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating
effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures
as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our
opinions.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding
the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with
generally accepted accounting principles. A company’s internal control over financial reporting includes those policies
and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the
transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are
recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting
principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of
management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely
detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on
the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect
misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls
may become inadequate because of changes in conditions, or that the degree of compliance with the policies or
procedures may deteriorate.
/s/ PricewaterhouseCoopers LLP
Portland, Oregon
February 25, 2011
83
NORTHWEST NATURAL GAS COMPANY
CONSOLIDATED STATEMENTS OF INCOME
Thousands, except per share amounts (year ended December 31)
2010
2009
2008
Operating revenues:
Gross operating revenues
Less: Cost of sales
Revenue taxes
Net operating revenues
Operating expenses:
Operations and maintenance
General taxes
Depreciation and amortization
Total operating expenses
Income from operations
Other income and expense - net
Interest expense - net
Income before income taxes
Income tax expense
Net income
Average common shares outstanding:
Basic
Diluted
Earnings per share of common stock:
Basic
Diluted
Dividends declared per share of common stock
$812,106
424,534
19,991
$1,012,711
611,168
24,656
$1,037,855
656,568
25,072
367,581
376,887
356,215
120,980
23,872
65,124
209,976
157,605
7,102
42,578
122,129
49,462
127,104
28,253
62,814
218,171
158,716
3,714
40,637
121,793
46,671
113,360
26,660
72,159
212,179
144,036
3,746
37,579
110,203
40,678
$ 72,667
$
75,122
$
69,525
26,589
26,657
26,511
26,576
26,438
26,594
$
$
$
2.73
2.73
1.68
$
$
$
2.83
2.83
1.60
$
$
$
2.63
2.61
1.52
See Notes to Consolidated Financial Statements
84
NORTHWEST NATURAL GAS COMPANY
CONSOLIDATED BALANCE SHEETS
Thousands (December 31)
Assets:
Current assets:
Cash and cash equivalents
Restricted cash
Accounts receivable
Accrued unbilled revenue
Allowance for uncollectible accounts
Regulatory assets
Derivative instruments
Inventories:
Gas
Materials and supplies
Income taxes receivable
Other current assets
Total current assets
Non-current assets:
Property, plant and equipment
Less accumulated depreciation
Total property, plant and equipment - net
Regulatory assets
Derivative instruments
Other investments
Other non-current assets
Total non-current assets
Total assets
2010
2009
$
$
3,457
924
67,969
64,803
(2,950)
52,714
2,245
70,672
9,713
41,066
19,652
8,432
35,543
77,438
71,230
(3,125)
29,954
6,504
71,672
9,285
-
21,302
330,265
328,235
2,576,402
722,239
1,854,163
348,897
628
69,094
13,569
2,362,734
692,600
1,670,134
316,536
843
67,365
16,139
2,286,351
2,071,017
$2,616,616
$2,399,252
See Notes to Consolidated Financial Statements
85
NORTHWEST NATURAL GAS COMPANY
CONSOLIDATED BALANCE SHEETS
Thousands (December 31)
Capitalization and liabilities:
Capitalization:
Common stock - no par value; authorized 100,000 shares; issued and outstanding
26,668 and 26,533 at December 31, 2010 and 2009, respectively
Retained earnings
Accumulated other comprehensive income (loss)
Total common stock equity
Long-term debt
Total capitalization
Current liabilities:
Short-term debt
Current maturities of long-term debt
Accounts payable
Taxes accrued
Interest accrued
Regulatory liabilities
Derivative instruments
Other current liabilities
Total current liabilities
Deferred credits and other non-current liabilities:
Deferred tax liabilities
Regulatory liabilities
Pension and other postretirement benefit liabilities
Derivative instruments
Other non-current liabilities
Total deferred credits and other non-current liabilities
Commitments and contingencies (see Note 15)
Total capitalization and liabilities
2010
2009
$ 342,978
356,727
(6,604)
$ 337,361
328,712
(5,968)
693,101
591,700
660,105
601,700
1,284,801
1,261,805
257,435
10,000
93,243
10,579
5,182
17,828
38,437
35,457
468,161
373,409
258,031
144,250
17,022
70,942
863,654
-
102,000
35,000
123,729
21,037
5,435
46,628
19,643
39,097
392,569
300,898
248,622
127,687
3,193
64,478
744,878
-
$2,616,616
$2,399,252
See Notes to Consolidated Financial Statements
86
CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY AND
COMPREHENSIVE INCOME
Thousands
Balance at Dec. 31, 2007
Net Income
Change in unrealized loss from derivatives
Change in non-qualified employee benefit plan
liability, net of $731 of tax
Amortization of non-qualified employee benefit plan
liability, net of ($140) of tax
Restricted stock amortizations
Dividends paid on common stock
Tax benefits from employee stock option plan
Stock-based compensation
Issuance of common stock
Balance at Dec. 31, 2008
Net Income
Change in non-qualified employee benefit plan
liability, net of $1,273 of tax
Amortization of non-qualified employee benefit plan
liability, net of ($58) of tax
Restricted stock amortizations
Dividends paid on common stock
Tax benefits from employee stock option plan
Stock-based compensation
Issuance of common stock
Balance at Dec. 31, 2009
Net Income
Change in non-qualified employee benefit plan
liability, net of $674 of tax
Amortization of non-qualified employee benefit plan
liability, net of ($257) of tax
Dividends paid on common stock
Tax expense from employee stock option plan
Stock-based compensation
Issuance of common stock
Balance at Dec. 31, 2010
Common
Stock
Retained
Earnings
Accumulated
Other
Comprehensive
Income (Loss)
Total
Equity
Comprehensive
Income
$331,595 $266,658
69,525
-
-
-
$(3,502)
-
41
$594,751
69,525
41
$69,525
41
-
-
(1,145)
(1,145)
(1,145)
-
275
-
282
1,523
3,079
336,754
-
-
-
39
-
229
(776)
1,115
337,361
-
-
-
-
(40,178)
-
-
-
296,005
75,122
220
-
-
-
-
-
(4,386)
220
275
(40,178)
282
1,523
3,079
628,373
-
75,122
220
$68,641
$75,122
-
(1,936)
(1,936)
(1,936)
-
-
(42,415)
-
-
-
328,712
72,667
354
-
-
-
-
-
(5,968)
354
39
(42,415)
229
(776)
1,115
660,105
-
72,667
354
$73,540
$72,667
-
(1,027)
(1,027)
(1,027)
-
-
(125)
554
5,188
-
(44,652)
-
-
-
$342,978 $356,727
391
-
-
-
-
$(6,604)
391
(44,652)
(125)
554
5,188
$693,101
391
$72,031
See Notes to Consolidated Financial Statements
87
CONSOLIDATED STATEMENTS OF CASH FLOWS
Thousands (year ended December 31)
2010
2009
2008
Operating activities:
Net income
Adjustments to reconcile net income to cash provided by operations:
Depreciation and amortization
Undistributed earnings from equity investments
Non-cash expenses related to qualified defined benefit pension plans
Contributions to qualified defined benefit pension plans
Deferred environmental expenditures
Settlement of interest rate hedge
Other
Changes in assets and liabilities:
Receivables
Inventories
Taxes accrued
Accounts payable
Interest accrued
Deferred gas costs
Deferred tax liabilities
Other - net
$ 72,667
$ 75,122
$ 69,525
65,124
(588)
8,009
(10,000)
(7,826)
-
(2,265)
15,830
572
(51,524)
(11,846)
(253)
(26,090)
76,410
(1,751)
62,814
(1,329)
9,914
(25,000)
(10,069)
(10,096)
(3,461)
35,506
15,110
23,461
1,188
8,582
36,819
36,775
(15,001)
72,159
(667)
2,855
-
(8,179)
-
(2,190)
(36,493)
(16,123)
(21,493)
(24,540)
(42)
(45,291)
50,192
(4,992)
Cash provided by operating activities
126,469
240,335
34,721
Investing activities:
Capital expenditures
Restricted cash
Other
Cash used in investing activities
Financing activities:
Common stock issued - net
Long-term debt issued
Long-term debt retired
Change in short-term debt
Cash dividend payments on common stock
Other
Cash provided by (used in) financing activities
Increase (decrease) in cash and cash equivalents
Cash and cash equivalents - beginning of period
Cash and cash equivalents - end of period
Supplemental disclosure of cash flow information:
Interest paid
Income taxes paid
(248,505)
34,619
1,015
(135,124)
(30,524)
3,507
(103,998)
(5,006)
(821)
(212,871)
(162,141)
(109,825)
4,598
-
(35,000)
155,435
(44,652)
1,046
(375)
125,000
(300)
(158,851)
(42,415)
263
2,310
-
(5,000)
117,751
(40,178)
1,030
81,427
(76,678)
75,913
(4,975)
8,432
1,516
6,916
809
6,107
$
3,457
$
8,432
$
6,916
$ 41,037
$ 22,600
$ 36,762
$ 10,000
$ 37,669
$ 12,300
See Notes to Consolidated Financial Statements
88
NORTHWEST NATURAL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1.
Organization and Principles of Consolidation
The consolidated financial statements include the accounts of Northwest Natural Gas
Company (NW Natural), primarily consisting of our regulated gas distribution business and our gas
storage business, which includes our subsidiary Gill Ranch Storage, LLC (Gill Ranch), NW Natural
Gas Storage, LLC (NWN Gas Storage), a wholly-owned subsidiary of our subsidiary NW Natural
Energy, LLC, and other investments and business activities, which primarily consist of our wholly-
owned subsidiary NNG Financial Corporation (NNG Financial) and an equity investment in Palomar
Gas Holdings, LLC (PGH) that is developing a proposed natural gas transmission pipeline through its
wholly-owned subsidiary Palomar Gas Transmission LLC (Palomar) (see Note 4). Investments in
corporate joint ventures and partnerships in which we are not the primary beneficiary are accounted for
by the equity method or the cost method.
In this report, the term “utility” is used to describe our regulated gas distribution business, and
the term “non-utility” is used to describe our gas storage business and other non-utility investments and
business activities (see Note 4). Intercompany accounts and transactions have been eliminated, except
for transactions required to be included under regulatory accounting standards to reflect the effect of
such regulation.
Certain prior year balances in our consolidated financial statements have been combined or
reclassified to conform with the current presentation. These changes had no impact on our prior year’s
consolidated results of operations and no material impact on financial condition or cash flows.
2.
Summary of Significant Accounting Policies
Use of Estimates
The preparation of financial statements in conformity with generally accepted accounting
principles in the United States of America (U.S. GAAP) requires management to make estimates and
assumptions that affect reported amounts in the consolidated financial statements and accompanying
notes. Actual amounts could differ from those estimates, and changes would most likely be reported in
future periods. Management believes that the estimates and assumptions used are reasonable.
Industry Regulation
Our principal businesses are the distribution of natural gas, which is regulated by the Public
Utility Commission of Oregon (OPUC) and Washington Utilities and Transportation Commission
(WUTC), and gas storage services, which are regulated by the Federal Energy Regulatory Commission
(FERC), the California Public Utilities Commission (CPUC) and to a certain extent by the
OPUC. Accounting records and practices of our regulated businesses conform to the requirements and
uniform system of accounts prescribed by these regulatory authorities in accordance with U.S.
GAAP. Our businesses regulated by the OPUC, WUTC and FERC earn a reasonable return on invested
capital from approved cost-based rates, while our business regulated by the CPUC earns a return to the
extent we are able to charge competitive prices above our costs (i.e. market-based rates).
89
In applying regulatory accounting principles, we capitalize or defer certain costs and revenues
as regulatory assets and liabilities pursuant to orders of the OPUC or WUTC issued to provide for
recovery of revenues or expenses from, or refunds to, utility customers in future periods, including a
return or a carrying charge in most cases.
At December 31, 2010 and 2009, the amounts deferred as regulatory assets and liabilities were
as follows:
Thousands
Regulatory assets:
Unrealized loss on derivatives (1)
Pension and other postretirement benefit liabilities (2)
Other (3)
Total regulatory assets
Regulatory liabilities:
Gas costs payable
Unrealized gain on derivatives (1)
Other (3)
Total regulatory liabilities
Thousands
Regulatory assets:
Unrealized loss on derivatives (1)
Income tax asset
Pension and other postretirement benefit liabilities (2)
Environmental costs - paid (4)
Environmental costs - accrued but not yet paid (4)
Other (3)
Total regulatory assets
Regulatory liabilities:
Gas costs payable
Unrealized gain on derivatives (1)
Accrued asset removal costs
Other (3)
Total regulatory liabilities
Current
2010
2009
$ 38,437
10,988
3,289
$ 19,643
7,502
2,809
$ 52,714
$ 29,954
$ 15,583
2,245
-
$ 37,055
6,504
3,069
$ 17,828
$ 46,628
Non-Current
2010
2009
$ 17,022
72,341
118,248
58,728
55,583
26,975
$
3,193
76,240
109,932
46,204
59,844
21,123
$348,897
$316,536
$
2,297
628
252,941
2,165
$
6,915
843
238,757
2,107
$258,031
$248,622
(1) An unrealized gain or loss on derivatives does not earn a rate of return or a carrying charge. These amounts,
when realized at settlement, are recoverable through utility rates as part of the Purchased Gas Adjustment
mechanism.
(2) Certain pension and other postretirement benefit liabilities are approved for regulatory deferral. Such
amounts are recoverable in rates, including an interest component, when recognized in net periodic benefit
costs (see Note 9).
(3) Other primarily consists of deferrals and amortizations under other approved regulatory mechanisms. The
(4)
accounts being amortized typically earn a rate of return or carrying charge.
Environmental costs are related to those sites that are approved for regulatory deferral. We earn the
authorized rate of return as a carrying charge on amounts paid, whereas the amounts accrued but not yet
paid do not earn a rate of return or a carrying charge until expended.
90
The amortization period for our regulatory assets and liabilities ranges from less than one year
to an undeterminable period. Our regulatory liabilities for gas costs payable are generally amortized
over 12 months beginning each November 1 following the gas contract year during which the deferred
gas costs are realized. Similarly, most of our regulatory deferred accounts are amortized over 12
months. However, certain regulatory account balances, such as income taxes, environmental costs,
pension liabilities and accrued asset removal costs, are large and tend to be amortized over longer
periods once we have agreed upon an amortization period with the respective regulatory agency.
We believe that continued application of regulatory accounting for regulated activities is
appropriate and consistent with the current regulatory environment, and that all regulated assets and
liabilities at December 31, 2010 and 2009 will be recoverable or refundable through future rate making
decisions. We annually review all regulatory assets and liabilities for recoverability and more often if
circumstances warrant. If we should determine that all or a portion of these regulatory assets or
liabilities no longer meet the criteria for continued application of regulatory accounting, then we would
be required to write off the net unrecoverable balances against earnings.
New Accounting Standards
Adopted Standards
Variable Interest Entity. Effective January 1, 2010, we adopted the amended authoritative
guidance on variable interest entities (VIE). This guidance requires a continuing analysis to determine
whether an entity has a controlling financial interest and whether it is the primary beneficiary. As the
primary beneficiary with a controlling financial interest we would be required to consolidate the VIE in
our financial statements. The guidance defines the primary beneficiary as the entity having:
•
•
power to control the activities that most significantly impact performance; and
the obligation to absorb losses or right to receive benefits from the entity that could
potentially be significant to the VIE.
Although we do have an ownership interest in PGH, which is a VIE, we are not the primary
beneficiary and therefore not required to consolidate PGH in the accompanying financial statements.
The adoption of this standard has not had a material effect on our financial condition, results of
operations or cash flows. See Note 12 for further information.
Recent Accounting Pronouncements
Fair Value Disclosures. In January 2010, the Financial Accounting Standards Board issued
authoritative guidance on new fair value measurements and disclosures. This guidance requires
additional disclosures for fair value measurements that use significant assumptions not observable in
active markets (i.e. level 3 valuations) including a rollforward schedule. These changes are effective
for periods beginning after December 15, 2010; however, we elected to early adopt these disclosure
requirements, as shown in Note 9. The adoption of this standard did not have, and is not expected to
have, a material effect on our financial statement disclosures.
Plant and Property and Accrued Asset Removal Costs
Plant and property is stated at cost, including capitalized labor, materials and overhead (see
Note 11). In accordance with regulatory accounting, the cost of constructing long-lived utility plant and
91
gas storage assets generally includes an allowance for funds used during construction (AFUDC) or
capitalized interest. AFUDC represents the regulatory financing cost incurred when debt and equity
funds are used for construction (see “Allowance for Funds Used During Construction,” below). When
gas storage assets are expected to be subject to market-based rates, then the financing cost incurred
during construction includes capitalized interest in accordance with U.S. GAAP, not regulatory
financing cost under AFUDC.
Our provision for depreciation of utility property is computed under the straight-line method in
accordance with external engineering studies as approved by regulatory authorities. The weighted
average depreciation rate for utility plant in service was approximately 2.8 percent, 2.9 percent and 3.4
percent for the years ended December 31, 2010, 2009 and 2008, respectively, reflecting the
approximate average economic life of the property. This includes 2010 weighted average depreciation
rates for the following asset classes: 2.7 percent for transmission and distribution, 2.2 percent for utility
storage, 4.9 percent for general, and 5.7 percent for intangible and other.
In accordance with long-standing industry practice, we accrue for future asset removal costs on
many long-lived assets through a charge to depreciation expense allowed in rates and accumulate such
amounts in regulatory liabilities. At the time removal costs are incurred, accumulated depreciation is
charged with the costs of removal and the book cost of the asset. Our estimate of accumulated removal
costs is based on rates using approved depreciation studies. No gain or loss is recognized upon normal
retirement. In the rate setting process, the accrued asset removal costs are treated as a reduction to net
rate base.
Allowance for Funds Used During Construction
Certain additions to utility plant include AFUDC, which represents the net cost of borrowed
and equity funds used during construction and is calculated using actual current interest rates and
authorized rates for return on equity, if applicable. If borrowings are less than the total costs of
construction work in progress, then a composite rate of interest on all debt, shown as a reduction to
interest charges, and a return on equity funds, shown as other income, is used to compute the AFUDC.
While cash is not realized currently from AFUDC, it is realized in future years through increased
revenues from rate recovery resulting from the higher utility cost of service. Our composite AFUDC
rates were 0.6 percent in 2010, 1.0 percent in 2009 and 3.6 percent in 2008.
Cash and Cash Equivalents
For purposes of reporting cash flows, cash and cash equivalents include cash on hand plus
highly liquid investment accounts with maturity dates of three months or less. At December 31, 2010,
outstanding checks of approximately $1.6 million were included in accounts payable.
Revenue Recognition and Accrued Unbilled Revenues
Utility revenues, derived primarily from the sale and transportation of natural gas, are
recognized when gas is delivered to and received by the customer. Revenues include accruals for gas
delivered but not yet billed to customers based on estimates of deliveries from meter reading dates to
month end (accrued unbilled revenues). Accrued unbilled revenues are dependent upon a number of
factors that require management’s judgment, including total gas receipts and deliveries, customer use
by billing cycle and weather factors. Accrued unbilled revenues are reversed the following month
when actual billings occur. Our accrued unbilled revenues at December 31, 2010 and 2009 were $64.8
million and $71.2 million, respectively.
92
Utility operating revenues also include the recognition of a regulatory adjustment for income
taxes paid. This revenue adjustment reflects an OPUC rule whereby we are required to implement a
rate refund or a rate surcharge to utility customers. This refund or surcharge is accrued based on the
estimated difference between income taxes paid and income taxes authorized to be collected in rates
each tax year.
Non-utility revenues are derived primarily from the gas storage business segment. At Mist,
revenues are recognized upon delivery of services to customers. Revenues from our asset optimization
partner are recognized over the life of the optimization contract for the guaranteed amount, and
recognized as earned for amounts above the guaranteed amount. At Gill Ranch, firm services resulting
from short-term and long-term contracts are typically recognized in revenue ratably over the term of
the contract regardless of the actual storage capacity utilized. Hub service fees include interruptible and
park and loan services. Interruptible service offers gas storage service to customers under contracts or
rate schedules that allow for temporary interruptions to meet the needs of firm service customers. Park
and loan service offers customers the option to use gas with a promise to provide gas in the future or
store natural gas, usually for short-term durations. Hub service fees are recognized in the period the
natural gas moves across our header system. Optimization revenue is recognized according to our
profit sharing mechanism, which provides us with 80 percent of the pre-tax income from our
independent energy marketing company. See Note 4.
Accounts Receivable and Allowance for Uncollectible Accounts
Accounts receivable consist primarily of amounts due for natural gas sales and transportation
services to core utility customers, plus amounts due for gas storage services and other miscellaneous
receivables. With respect to these trade receivables, including accrued unbilled revenues, we establish
an allowance for uncollectible accounts (allowance) based on the aging of receivables, collection
experience of past due account balances including payment plans, and historical trends of write-offs as
a percent of revenues. With respect to large individual customer receivables, a specific allowance is
established and added to the general allowance when amounts are identified as unlikely to be partially
or fully recovered. Inactive accounts are written-off against the allowance after they are 120 days past
due or when deemed to be uncollectible. Differences between our estimated allowance and actual
write-offs will occur based on changes in general economic conditions, customer credit issues and the
level of natural gas prices. Each quarter the allowance for uncollectible accounts is adjusted, as
necessary, based on information currently available.
Inventories
Inventories, which consist primarily of natural gas in storage for the utility, are generally stated
at the lower of average cost or net realizable value. The regulatory treatment of utility gas inventories
provides for cost recovery in customer rates. Utility gas inventories that are injected into storage are
priced into inventory based on actual purchase costs. Utility gas inventories that are withdrawn from
inventory storage are charged to cost of gas during the current period at the weighted average cost of
inventory.
Gill Ranch gas inventories, excluding cushion gas, consist primarily of gas that we received as
fuel-in-kind from storage customers. Gill Ranch gas inventories are valued at the lower of average cost
or net realizable value. Cushion gas is recorded at original cost and classified as long-term assets.
93
Material and supplies inventories are stated at the lower of average cost or net realizable value.
Derivatives
In accordance with accounting for derivatives and hedges, we measure derivatives at fair value
and recognize them as either assets or liabilities on the balance sheet. Accounting for derivatives
requires that changes in the fair value be recognized currently in earnings unless specific hedge
accounting criteria are met. Accounting for derivatives and hedges provides an exception for contracts
intended for normal purchases and normal sales for which physical delivery is probable. In addition,
certain derivatives contracts are approved by regulatory authorities for recovery or refund through
customer rates. Accordingly, the changes in fair value of these contracts are deferred as regulatory
assets or liabilities pursuant to regulatory accounting principles. Derivative contracts entered into for
core utility customer requirements after the purchased gas adjustment (PGA) rate has been set are
subject to the PGA incentive sharing mechanism. Effective on November 1, 2008, Oregon approved a
PGA sharing mechanism under which we are required to select before each gas year, either an 80
percent deferral or 90 percent deferral of higher or lower gas costs such that the impact on current
earnings from the gas cost sharing is either 20 percent or 10 percent of gas cost differences compared
to PGA prices, respectively. For the PGA years in Oregon beginning November 1, 2010 and 2009, we
selected the 90 percent deferral of gas cost differences. For the PGA year in Oregon beginning
November 1, 2008, we selected the 80 percent deferral of gas cost differences. In Washington, 100
percent of our gas cost differences are deferred. See Note 13.
Our financial derivatives policies set forth the guidelines for using selected derivative products
to support prudent risk management strategies within designated parameters. Our objective for using
derivatives is to decrease the volatility of earnings and cash flows and to prevent speculative risk. The
use of derivatives is permitted only after the risk exposures have been identified, are determined to
exceed acceptable tolerance levels and are necessary to support normal business activities. We do not
enter into derivative instruments for trading purposes and we believe that any increase in market risk
created by holding derivatives should be offset by the exposures they modify.
Fair Value
In accordance with fair value accounting, we use the following fair value hierarchy for
determining inputs for our pension plan assets and our derivative fair value measurements:
• Level 1: Valuation is based upon quoted prices for identical instruments traded in active
markets;
• Level 2: Valuation is based upon quoted prices for similar instruments in active markets,
quoted prices for identical or similar instruments in markets that are not active, and model-
based valuation techniques for which all significant assumptions are observable in the
market; and
• Level 3: Valuation is generated from model-based techniques that use significant
assumptions not observable in the market. These unobservable assumptions reflect our own
estimates of assumptions that market participants would use in valuing the asset or liability.
When developing fair value measurements, it is our policy to use quoted market prices
whenever available, or to maximize the use of observable inputs and minimize the use of unobservable
inputs when quoted market prices are not available. Fair values are primarily developed using industry-
94
standard models that consider various inputs including: (a) quoted future prices for commodities;
(b) forward currency prices; (c) time value; (d) volatility factors; (e) current market and contractual
prices for underlying instruments; (f) market interest rates and yield curves; and (g) credit spreads, as
well as other relevant economic measures.
Revenue Taxes
We account for revenue-based taxes as a separate cost item collected from
customers. Therefore, revenue taxes are accounted for as a cost of sale and presented separately on the
income statement.
Income Tax Expense
NW Natural and its wholly-owned subsidiaries file consolidated federal and state income tax
returns. Current income taxes are allocated based on each entity’s respective taxable income or loss
and tax credits as if each entity filed a separate return. We account for income taxes in accordance with
accounting standards for income taxes. Accounting for income taxes requires recognition of deferred
tax liabilities and assets for the future tax consequences of events that have been included in the
consolidated financial statements or tax returns. Under this method, deferred tax liabilities and assets
are determined based on the difference between the financial statement and tax basis of assets and
liabilities using enacted tax rates in effect for the year in which the differences are expected to reverse
(see Note 10).
Accounting for income taxes also requires recognition of deferred income tax assets and
liabilities for temporary differences where regulators prohibit deferred income tax treatment for
ratemaking purposes. We have recorded a deferred tax liability equivalent of $72.3 million and $76.2
million at December 31, 2010 and 2009, respectively, to recognize future taxes payable resulting from
transactions that have previously been reflected in the financial statements for these temporary
differences. Regulatory assets or liabilities corresponding to such additional deferred income tax assets
or liabilities may be recorded to the extent we believe they will be recoverable from or payable to
customers through the ratemaking process. Pursuant to regulatory accounting principles, a
corresponding regulatory asset has been recorded which represents the probable future revenue that
will result from inclusion in rates charged to customers of taxes which will be paid in the future. The
probable future revenue to be recorded takes into consideration the additional future taxes which will
be generated by that revenue. Amounts applicable to income taxes due from customers primarily
represent differences between the book and tax basis of net utility plant in service and actual removal
costs incurred.
Deferred investment tax credits on utility plant additions, which reduce income taxes payable,
are deferred for financial statement purposes and amortized over the life of the related plant or lease.
Subsequent Events
We monitor significant events occurring after the balance sheet date and prior to the issuance
of the financial statements to determine the impacts, if any, of events on the financial statements to be
issued. All subsequent events of which we are aware were evaluated through the filing date of this
Form 10-K. For subsequent events see Note 16.
95
3.
Earnings Per Share
Basic earnings per share are computed using the weighted average number of common shares
outstanding during each period presented. Diluted earnings per share are computed using the weighted
average number of common shares outstanding plus the potential effects of the assumed exercise of
stock options and the payment of estimated stock awards from other stock-based compensation plans
that are outstanding at the end of each period presented. Diluted earnings per share are calculated as
follows:
Thousands, except per share amounts
Net income
Average common shares outstanding - basic
Additional shares for stock-based compensation plans
Average common shares outstanding - diluted
Earnings per share of common stock - basic
Earnings per share of common stock - diluted
2010
2009
2008
$72,667
$75,122
$69,525
26,589
68
26,657
26,511
65
26,576
26,438
156
26,594
$
$
2.73
2.73
$
$
2.83
2.83
$
$
2.63
2.61
For the years ended December 31, 2010, 2009 and 2008, 743 shares, 2,142 shares and 1,248
shares, respectively, were excluded from the calculation of diluted earnings per share because the
effect of these additional shares on the net income for these periods would have been antidilutive.
4.
Segment Information
We operate in two primary reportable business segments, local gas distribution and gas
storage. We also have other investments and business activities not specifically related to one of these
two reporting segments, which we aggregate and report as “other.” We refer to our local gas
distribution business as the “utility,” and our “gas storage” and “other” business segments as “non-
utility.” Our “gas storage” segment includes Gill Ranch, parts of NWN Energy and its wholly-owned
subsidiary NWN Gas Storage, and the non-utility portion of gas storage services related to our Mist
underground storage facility in Oregon (Mist). Our “other” segment includes NNG Financial and parts
of NWN Energy, including an equity investment in PGH which is developing the Palomar pipeline
project (see Other, below).
Local Gas Distribution
Our local gas distribution segment is a regulated utility principally engaged in the purchase,
sale and delivery of natural gas, including related services to customers in Oregon and southwest
Washington. As a regulated utility, we are responsible for building and maintaining a safe and reliable
pipeline distribution system, purchasing sufficient gas supplies from producers and marketers,
contracting for firm and interruptible transportation of gas over interstate pipelines to bring gas from
the supply basins into our service territory, and re-selling the gas to customers subject to rates, terms
and conditions approved by the OPUC or WUTC. Gas distribution also includes taking customer-
owned gas and transporting it from interstate pipeline connections, or city gates, to the customers’
end-use facilities for a fee, also approved by the OPUC or WUTC. Approximately 90 percent of our
customers are located in Oregon and 10 percent in Washington. On an annual basis, residential and
commercial customers typically account for 50 to 60 percent of our utility’s total volumes delivered
and 80 to 90 percent of our utility’s margin, while industrial customers account for 40 to 50 percent of
96
volumes and 5 to 15 percent of margin. The remaining 10 percent or less of margin is derived from
miscellaneous services, gains or losses from gas cost sharing and other regulatory charges.
Industrial customers we serve include: pulp, paper and other forest products; the manufacture
of electronic, electrochemical and electrometallurgical products; the processing of farm and food
products; the production of various mineral products; metal fabrication and casting; the production of
machine tools, machinery and textiles; the manufacture of asphalt, concrete and rubber; printing and
publishing; nurseries; government and educational institutions; and electric generation. No individual
customer or industry group accounts for a significant portion of our utility revenues or margins.
Gas Storage
Our gas storage business segment includes natural gas storage services provided to customers
from our two underground natural gas storage facilities, our Gill Ranch gas storage facility, which
commenced commercial operations in October 2010, and the non-utility portion of the Mist gas storage
facility near Mist, Oregon. In addition to earning revenue from customer storage contracts, we also use
an independent energy marketing company to provide asset optimization services for utility and
non-utility capacity under a contractual arrangement, the results of which are included in this business
segment. For each of the years ended December 31, 2010, 2009 and 2008, this business segment
derived a majority of its revenues from asset optimization services and from multi-year gas storage
contracts.
Mist Gas Storage Facility. Our total Mist gas storage assets, excluding amounts allocated to
our utility, were $58.9 million in 2010 and $58.4 million in 2009. Results for the gas storage segment
also include revenues, net of amounts shared with core utility customers, from the optimization of our
utility assets when not needed to serve core utility customers. In Oregon, the gas storage segment
retains 80 percent of the pre-tax income from these services when the costs of the capacity have not
been included in utility rates, or 33 percent of the pre-tax income when the costs have been included in
utility rates. The remaining 20 percent and 67 percent, respectively, are credited to a deferred
regulatory account for crediting back to core utility customers. We have a similar sharing mechanism
in Washington for revenue derived from storage and third party optimization.
Gill Ranch Gas Storage Facility. We have a joint project agreement with Pacific Gas and
Electric Company (PG&E) to own and operate the Gill Ranch underground natural gas storage facility
near Fresno, California. Gill Ranch has a 75 percent undivided ownership interest in the project. The
construction of this facility began in January 2010 and a majority of the construction work was
complete by October 2010.
Gill Ranch is offering storage services to the California market at market-based rates, subject
to CPUC regulation including, but not limited to, service terms and conditions, tariff regulations, and
security issuances. As of December 31, 2010 and 2009, total assets at Gill Ranch were $225.2 million
and $116.3 million, respectively, and for the years then ended Gill Ranch had a net loss of $2.9 million
and $0.3 million, respectively. In 2010, Gill Ranch expenses primarily reflect start-up costs,
depreciation, and power costs related to gas injection. Gill Ranch has a 28 year contract for cushion gas
for our facility. This $13.5 million liability is included in non-current other liabilities on our balance
sheet.
97
Other
We have non-utility investments and other business activities which are aggregated and
reported as a business segment called “other.” Although in the aggregate these investments and
activities are not material, we identify and report them as a stand-alone segment based on our current
organizational structure and decision-making process because these business investments and activities
are not specifically related to our utility or gas storage segments. This segment primarily consists of an
equity method investment in a joint venture to build and operate an interstate gas transmission pipeline
in Oregon (Palomar) and other pipeline assets in NNG Financial. For more on information on Palomar,
see Note 12. This segment also includes some operating and non-operating revenues and expenses of
the parent company that cannot be allocated to utility operations.
In 2008, we sold our investment in a Boeing 737-300 aircraft for approximately $6.8 million
total including accrued rents. We purchased the aircraft in 1987 and leased it to Continental Airlines
for the entire time it was owned by NW Natural. As a result of the sale, we recognized an after-tax gain
of $1.1 million in 2008.
NNG Financial holds certain non-utility financial investments, but its assets primarily consist
of an active, wholly-owned subsidiary which owns a 10 percent interest in an 18-mile interstate natural
gas pipeline. NNG Financial’s total assets were $1.1 million and $1.4 million at December 31, 2010
and 2009, respectively.
Segment Information Summary
The following table presents summary financial information about the reportable segments for
the years ended 2010, 2009 and 2008. Inter-segment transactions are insignificant.
Thousands
2010
Net operating revenues
Depreciation and amortization
Income from operations
Net income
Total assets at December 31, 2010
2009
Net operating revenues
Depreciation and amortization
Income from operations
Net income
Total assets at December 31, 2009
2008
Net operating revenues
Depreciation and amortization
Income from operations
Net income
Utility
Gas Storage
Other
Total
$ 346,148
62,661
145,688
66,262
2,310,388
$ 357,005
61,472
142,228
65,960
2,205,313
$ 21,249
2,463
11,855
6,110
282,945
$ 19,738
1,342
16,442
8,923
173,648
$
184
-
62
295
23,283
$ 367,581
65,124
157,605
72,667
2,616,616
$
144
-
46
239
20,291
$ 376,887
62,814
158,716
75,122
2,399,252
$ 337,596
70,690
128,957
58,739
$ 18,459
1,469
14,943
8,363
$
160
-
136
2,423
$ 356,215
72,159
144,036
69,525
98
5.
Capital Stock
Common Stock
As of December 31, 2010 and 2009, our common shares authorized were 100,000,000.
As of December 31, 2010, we had reserved for issuances 171,259 shares of common stock
under the Employee Stock Purchase Plan (ESPP), 386,188 shares under our Dividend Reinvestment
and Direct Stock Purchase Plan and 1,184,060 shares under our Restated Stock Option Plan (Restated
SOP).
Stock Repurchase Program
We have a share repurchase program for our common stock under which we purchase shares
on the open market or through privately negotiated transactions. We currently have Board
authorization through May 2011 to repurchase up to an aggregate of 2.8 million shares, or up to $100.0
million. No shares of common stock were repurchased pursuant to this program in 2010, 2009 or
2008. Since inception in 2000, a total of 2.1 million shares have been repurchased at a total cost of
$83.3 million.
Summary of Changes in Common Stock
The following table shows the changes in the number of shares of our common stock issued
and outstanding for the years 2010, 2009 and 2008:
Balance, December 31, 2007
Sales to employees
Exercise of stock options - net
Balance, December 31, 2008
Sales to employees
Exercise of stock options - net
Balance, December 31, 2009
Sales to employees
Exercise of stock options - net
Balance, December 31, 2010
6.
Stock-Based Compensation
Shares
26,407,348
19,500
74,340
26,501,188
8,615
23,225
26,533,028
23,659
111,525
26,668,212
We have several stock-based compensation plans, including a Long-Term Incentive Plan
(LTIP), a Restated SOP and an ESPP. These plans are designed to promote stock ownership in NW
Natural by employees and officers.
Long-Term Incentive Plan
The LTIP is intended to provide a flexible, competitive compensation program for eligible
officers and key employees. An aggregate of 500,000 shares of common stock was authorized for
grants under the LTIP as stock bonus, restricted stock or performance-based stock awards. Shares
awarded under the LTIP may be purchased on the open market.
99
At December 31, 2010, 270,204 shares of common stock were available for award under the
LTIP, assuming that performance based grants currently outstanding are awarded at the target
level. The LTIP stock awards are compensatory awards for which compensation expense is recognized
based on the fair value of performance-based stock awards, or a pro rata amortization over the vesting
period for the outstanding awards of restricted stock.
Performance-based Stock Awards. Since the LTIP’s inception in 2001, performance-based
stock awards have been granted annually based on three-year performance periods. At December 31,
2010, certain performance-based stock award measures had been achieved for the 2008-10 award
period. Accordingly, participants are estimated to receive 8,007 shares of common stock and a
dividend equivalent cash payment equal to the number of shares of common stock received on the
award payout multiplied by the aggregate cash dividends paid per share during the performance period.
At December 31, 2009 and 2008, we awarded 12,755 and 48,351 shares of common stock net of tax,
respectively, for the 2007-09 and 2006-08 award periods, plus a dividend equivalent cash payment
equal to the number of shares of common stock received on the award payout multiplied by the
aggregate cash dividends paid per share during the performance period. During 2010, we expensed
$0.2 million related to the 2008-10 performance-based stock award, and on a cumulative basis we
accrued a total of $0.7 million related to the 2008-10 performance period. In 2009 and 2008, we
expensed $0.5 million for both the 2007-09 and 2006-08 performance-based stock award periods, and
on a cumulative basis we accrued a total of $1.5 million and $2.0 million, respectively, related to the
2007-09 and 2006-08 performance periods.
At December 31, 2010, the aggregate number of performance-based shares granted and
outstanding at the threshold, target and maximum levels were as follows:
Year
Awarded
2009
2010
Performance
Period
2009-11
2010-12
Total
Performance Share Awards Outstanding
Threshold
7,410
7,885
15,295
Target
39,000
41,500
80,500
Maximum
78,000
83,000
161,000
The threshold level estimates future payout assuming the minimum award payable is achieved
for each component of the formula in the LTIP. For each of these performance periods, awards will be
based on total shareholder return relative to a peer group of gas distribution companies over the three-
year performance period and on performance results achieved relative to specific core and non-core
strategies. Compensation expense is recognized in accordance with accounting for stock compensation,
based on performance levels achieved and an estimated fair value using a Black-Scholes or binomial
model. The weighted-average per share grant date fair value of unvested shares at December 31, 2010
and 2009 was $23.10 and $19.40, respectively. The weighted-average per share grant date fair value of
shares vested during the year was $19.38 and granted during the year was $25.58. In 2010, 2009 and
2008 under these LTIP grants we accrued and expensed $0.6 million and $0.5 million, $1.0 million and
$0.9 million, and $2.7 million and $2.3 million, respectively.
Restated Stock Option Plan
A total of 2,400,000 shares of common stock were reserved for issuance under the Restated
SOP. Options under the Restated SOP may be granted only to officers and key employees designated
by a committee of our Board of Directors. All options are granted at an option price equal to the
100
closing market price on the date of grant and may be exercised for a period up to 10 years and 7 days
from the date of grant. Option holders may exchange shares they have owned for at least six months, at
the current market price, to purchase shares at the option price.
The fair value of each stock option is estimated on the grant date using the Black-Scholes
option pricing model with the following weighted average assumptions and outcomes:
Risk-free interest rate
Expected life (in years)
Expected market price volatility factor
Expected dividend yield
Forfeiture rate
Weighted average grant date fair value
February
2010
February
2009
September
2008
February
2008
February
2007
2.3%
4.7
23.2%
3.8%
3.2%
$ 6.36
2.0%
4.7
22.5%
3.8%
3.7%
$ 5.46
3.0%
4.7
18.4%
2.9%
3.9%
$ 7.05
2.8%
4.7
18.4%
3.5%
3.8%
$ 5.34
4.7%
6.2
17.2%
3.2%
4.4%
$ 7.66
The expected life of our grants was calculated based on our actual experience with previously
exercised option grants. The risk-free interest rate was based on the implied yield currently available
on U.S. Treasury zero-coupon issues with a life equal to the expected life of the options. Historical data
was used to estimate the volatility factor, measured on a daily basis, for a period equal to the duration
of the expected life of the option awards. The dividend yield was based on management’s current
estimate for future dividend payouts at the time of grant. We expense the total cost of stock option
awards granted to retirement eligible employees at the date of grant in accordance with stock option
accounting guidance and the retirement vesting provisions of our option agreements.
Information regarding the Restated SOP activity for the three years ended December 31, 2010
is summarized as follows:
Price per Share
Balance outstanding, Dec. 31, 2007
Granted
Exercised
Forfeited
Balance outstanding, Dec. 31, 2008
Granted
Exercised
Balance outstanding, Dec. 31, 2009
Granted
Exercised
Forfeited
Option
Shares
Range
$20.25 - 44.48
357,750
119,050
43.29 - 51.09
(74,340) 20.25 - 44.48
(6,050) 26.30 - 44.48
396,410
111,750
(23,225) 20.25 - 34.95
20.25 - 51.09
41.15
26.30 - 51.09
44.25
484,935
119,750
(111,525) 26.30 - 44.48
(2,700) 41.15 - 44.25
Weighted -
Average
Exercise Price
Intrinsic
Value
(In millions)
$
$35.36
43.62
30.70
41.56
38.62
41.15
30.92
39.57
44.25
39.01
43.00
4.8
n/a
1.3
n/a
2.3
n/a
0.3
2.7
n/a
0.9
n/a
2.8
Balance outstanding, Dec. 31, 2010
490,460
$26.30 - 51.09
$40.82
$
Shares available for grant
Dec. 31, 2008
Dec. 31, 2009
Dec. 31, 2010
922,400
810,650
693,600
101
In the year ended December 31, 2010, cash of $5.2 million was received for option shares
exercised and a $0.1 million related tax benefit was realized. For the 12 months ended December 31,
2010, 2009 and 2008, the total fair value of options that vested was $0.5 million, $0.4 million and $0.3
million, respectively.
The following table summarizes additional information about stock options outstanding and
exercisable at December 31, 2010:
Outstanding
Exercisable
Range of Exercise
Prices
$26.30 - 51.09
Stock
Options
490,460
Weighted-
Average
Remaining
Life in Years
Aggregate
Intrinsic
Value
(In millions)
Weighted-
Average
Exercise
Price
Weighted-
Average
Remaining
Life in Years
Stock
Options
7.02
239,361
$2.0
$38.30
5.61
As of December 31, 2010, there was $0.9 million of unrecognized compensation cost related to
the unvested portion of outstanding stock option awards expected to be recognized over a period
extending through 2013.
Employee Stock Purchase Plan
The ESPP allows employees to purchase common stock at 85 percent of the closing price on
the trading day immediately preceding the initial offering date, which is set annually. Each eligible
employee may purchase up to $24,000 worth of stock through payroll deductions over a 12-month
period.
In accordance with accounting for stock compensation, stock-based compensation expense is
recognized as operations and maintenance expense or is capitalized as part of construction
overhead. The following table summarizes the financial statement impact of stock-based compensation
under our LTIP, Restated SOP and ESPP:
Thousands
2010
2009
2008
Operations and maintenance expense, for stock-based compensation
Income tax benefit
$1,032
(418)
$1,434
(559)
$1,598
(623)
Net stock-based compensation effect on net income
Amounts capitalized for stock-based compensation
$ 614
$ 875
$ 975
$ 182
$ 229
$ 282
7.
Cost and Fair Value Basis of Long-Term Debt
Cost of Long-Term Debt
The issuance of first mortgage debt, including secured medium-term notes (MTNs), under the
Mortgage and Deed of Trust (Mortgage) is limited by eligible property, adjusted net earnings and other
provisions of the Mortgage. The Mortgage constitutes a first mortgage lien on substantially all of our
utility property.
102
The maturities on the long-term debt outstanding for each of the 12-month periods through
December 31, 2015 amount to: $10 million in 2011; $40 million in 2012; none in 2013; $60 million in
2014; and $40 million in 2015.
Thousands
Medium-Term Notes
First Mortgage Bonds:
4.11 % Series B due 2010
7.45 % Series B due 2010
6.665% Series B due 2011
7.13 % Series B due 2012
8.26 % Series B due 2014
3.95 % Series B due 2014 (1)
4.70 % Series B due 2015
5.15 % Series B due 2016
7.00 % Series B due 2017
6.60 % Series B due 2018
8.31 % Series B due 2019
7.63 % Series B due 2019
5.37 % Series B due 2020 (2)
9.05 % Series A due 2021
5.62 % Series B due 2023
7.72 % Series B due 2025
6.52 % Series B due 2025
7.05 % Series B due 2026
7.00 % Series B due 2027
6.65 % Series B due 2027 (3)
6.65 % Series B due 2028
7.74 % Series B due 2030
7.85 % Series B due 2030
5.82 % Series B due 2032
5.66 % Series B due 2033
5.25 % Series B due 2035
Less current maturities of long-term debt
Total long-term debt
2010
2009
2008
$
-
-
10,000
40,000
10,000
50,000
40,000
25,000
40,000
22,000
10,000
20,000
75,000
10,000
40,000
20,000
10,000
20,000
20,000
19,700
10,000
20,000
10,000
30,000
40,000
10,000
601,700
10,000
$ 10,000
25,000
10,000
40,000
10,000
50,000
40,000
25,000
40,000
22,000
10,000
20,000
75,000
10,000
40,000
20,000
10,000
20,000
20,000
19,700
10,000
20,000
10,000
30,000
40,000
10,000
636,700
35,000
$ 10,000
25,000
10,000
40,000
10,000
-
40,000
25,000
40,000
22,000
10,000
20,000
-
10,000
40,000
20,000
10,000
20,000
20,000
20,000
10,000
20,000
10,000
30,000
40,000
10,000
512,000
-
$591,700
$601,700
$512,000
(1)
(2)
(3)
Issued in July 2009
Issued in March 2009
In November 2009 one investor in our 6.65 percent secured MTNs due 2027 exercised its right
under a one-time put option to redeem $0.3 million of the $20 million outstanding. This one-time
put option has now expired, and the remaining $19.7 million remaining principal outstanding is
expected to be redeemed at maturity in November 2027.
In March 2009, we issued $75 million of 5.37 percent secured MTNs due February 1, 2020,
and in July 2009, we issued another $50 million of secured MTNs with an interest rate of 3.95 percent
and a maturity of July 15, 2014. Proceeds from these MTNs were used to fund utility capital
expenditures, to redeem utility short-term debt, and to provide utility working capital for general
corporate purposes.
103
Fair Value of Long-Term Debt
The following table provides an estimate of the fair value of our long-term debt including
current maturities of long-term debt, using market prices in effect on the valuation date. Because our
debt outstanding does not trade in active markets, we used interest rates for outstanding debt issues that
actively trade and have similar credit ratings, terms and remaining maturities to estimate fair value for
our long-term debt issues.
Thousands
Carrying amount
Estimated fair value
8.
Short-term Debt and Credit Facilities
December 31,
2010
2009
$601,700
$690,126
$636,700
$707,755
Our primary source of short-term funds is from the sale of commercial paper and bank
loans. In addition to issuing commercial paper to meet seasonal working capital requirements,
including the financing of gas purchases, gas inventories and accounts receivable, short-term debt is
used temporarily to fund capital requirements. Commercial paper and bank loans are periodically
refinanced through the sale of long-term debt or equity securities. Our commercial paper program is
supported by one or more committed credit facilities. Bank loans at Gill Ranch were supported by cash
collateral. At December 31, 2010 and 2009, the amounts and average interest rates of commercial
paper debt outstanding were $257.4 million at 0.4 percent and $69.8 million at 0.3 percent,
respectively.
In March 2009, Gill Ranch entered into a cash collateralized credit facility for up to $40
million. As of December 31, 2009, Gill Ranch had $32.2 million of borrowings outstanding included
under short-term debt on the balance sheet, with a corresponding cash collateral amount included under
restricted cash—current on the balance sheet. The effective interest rate on Gill Ranch’s credit facility
was 0.8 percent. In June 2010, Gill Ranch settled its $40 million bank loan outstanding using proceeds
from its cash collateralized account.
We have a multi-year $250 million syndicated credit agreement, pursuant to which we may
extend commitments for additional one-year periods subject to lender approval. We extended
commitments under this syndicated agreement to May 31, 2013. The syndicated agreement allows us
to request increases in the total commitment amount from time to time, up to a maximum amount of
$400 million, and to replace any lenders who decline to extend the terms of the agreement. The
syndicated agreement also permits the issuance of letters of credit in an aggregate amount up to the
applicable total borrowing commitment. Any principal and unpaid interest owed on borrowings under
the syndicated agreement are due and payable on or before the expiration date, which is May 31,
2013. Additionally, we have three committed bilateral bank lines of credit totaling $50 million in effect
as of November 30, 2010. These will expire March 31, 2011. There were no outstanding balances
under the syndicated agreement and no letters of credit issued or outstanding at December 31, 2010
and 2009.
The syndicated agreement requires that we maintain credit ratings with Standard & Poor’s
(S&P) and Moody’s Investors Service, Inc. (Moody’s) and notify the lenders of any change in our
senior unsecured debt ratings by such rating agencies. A change in our debt ratings is not an event of
default, nor is the maintenance of a specific minimum level of debt rating a condition of drawing upon
104
the credit facility. However, interest rates on any loans outstanding under the credit facility are tied to
debt ratings, which would increase or decrease the cost of any loans under the credit facility when
ratings are changed.
The syndicated agreement also requires us to maintain a consolidated indebtedness to total
capitalization ratio of 70 percent or less. Failure to comply with this covenant would entitle the lenders
to terminate their lending commitments and accelerate the maturity of all amounts outstanding. We
were in compliance with this covenant at December 31, 2010 and 2009.
There were no outstanding balances under the short-term credit agreements as of December 31,
2010. All three lenders under the short-term credit agreements are existing lenders under our
syndicated agreement. The short-term credit agreements require us to comply with the terms and
conditions of the syndicated agreement and give the lenders under the short-term credit agreements the
same rights with respect to the short-term credit agreements that they have under the syndicated
agreement. We were in compliance with these covenants at December 31, 2010.
9.
Pension and Other Postretirement Benefits
We maintain two qualified non-contributory defined benefit pension plans covering a majority
of our regular employees with more than one year of service, several non-qualified supplemental
pension plans for eligible executive officers and certain key employees and other postretirement
employee benefit plans. We also have a qualified defined contribution plan (Retirement K Savings
Plan) for all eligible employees. Only the two qualified defined benefit pension plans and Retirement K
Savings Plan have plan assets, which are held in a qualified trust to fund retirement benefits. Effective
January 1, 2007 and 2010, the qualified defined benefit retirement plans and postretirement benefits for
non-union employees and for union employees, respectively, were closed to new participants. These
plans were not available employees of our NWN Gas Storage subsidiary. Instead, non-union and union
employees hired or re-hired after December 31, 2006 and 2009, respectively, and our NWN Gas
Storage employees are provided an enhanced Retirement K Savings Plan benefit. Also, effective
January 1, 2007, the postretirement Welfare Benefit Plan for Non-Bargaining Unit Employees was
closed to new participants after December 31, 2006.
105
The following table provides a reconciliation of the changes in benefit obligations and fair
value of plan assets, as applicable, for the pension and other postretirement benefit plans for the years
ended December 31, 2010, 2009, and 2008, and a summary of the funded status and amounts
recognized in the consolidated balance sheets using measurement dates as of December 31, 2010, 2009
and 2008:
Thousands
Reconciliation of change in benefit
obligation:
Obligation at January 1
Service cost
Interest cost
Net actuarial (gain) or loss
Benefits paid
Plan amendments
Change in assumptions
Liability transfer
Postretirement Benefit Plans
Pension Benefits
2009
2010
2008
2010
Other Benefits
2009
2008
$ 307,991 $ 281,127 $ 260,561 $ 24,741 $ 23,863 $ 22,186
521
1,403
173
(1,259)
-
839
-
6,402
17,948
9,319
(17,149)
(3,921)
14,265
-
6,141
17,373
4,291
(16,247)
5
9,146
(143)
6,688
18,029
762
(18,645)
-
24,513
-
522
1,568
(883)
(1,428)
-
1,099
-
588
1,436
670
(1,476)
-
1,717
-
Obligation at December 31
$ 339,338 $ 307,991 $ 281,127 $ 27,676 $ 24,741 $ 23,863
Reconciliation of change in plan assets:
Fair value of plan assets at January 1
Actual return on plan assets
Employer contributions
Benefits paid
Fair value of plan assets at
December 31
$ 201,312 $ 163,115 $ 241,418 $
28,641
26,705
(17,149)
(63,267)
1,211
(16,247)
24,651
11,696
(18,645)
- $
-
1,476
(1,476)
- $
-
1,428
(1,428)
-
-
1,259
(1,259)
$ 219,014 $ 201,312 $ 163,115 $
- $
- $
-
Funded status at December 31
$(120,324) $(106,679) $(118,012) $(27,676) $(24,741) $(23,863)
Our qualified defined benefit pension plans had an aggregate projected benefit obligation of $
314.5 million, $285.2 million and $261.5 million at December 31, 2010, 2009, and 2008, respectively,
and the fair value of plan assets was $ 219.0 million, $201.3 million and $163.1 million,
respectively. Changes in valuation assumptions impact our projected benefit obligations. Benefit
obligations at December 31, 2010 increased $17.9 million due to a decrease in our discount rate
assumptions and increased by $6.5 million due to changes in other assumptions. The projected benefit
obligations at December 31, 2009 increased $19.1 million over the prior year due to a decrease in our
discount rate assumptions and increased by $4.2 million due to changes in other assumptions.
106
The following table provides amounts amortized from accumulated other comprehensive
income (AOCI) or regulatory assets to net periodic benefit cost during 2010, 2009, and 2008:
Thousands
Net periodic benefit costs:
Actuarial loss
Prior service cost
Transition obligation
Total
Regulatory Asset Amortization
Pension Benefits
2009
2010
2008
Other Postretirement Benefits
2009
2010
2008
AOCI Amortization
Pension Benefits
2009
2010
2008
$6,740
230
-
$6,189
1,260
-
$
-
1,290
-
$6,970
$7,449
$1,290
$131
197
411
$739
$ 17
197
411
$625
$
-
197
411
$608
$707
(43)
-
$449
(37)
-
$398
(37)
-
$664
$412
$361
In 2011, an estimated $11.0 million will be amortized from regulatory assets to net periodic
benefit costs, consisting of $10.2 million of actuarial losses, $0.4 million of prior service cost and $0.4
million transition obligation, and $0.9 million will be amortized to AOCI, consisting of $0.8 million of
actuarial losses and $0.1 million of prior service cost.
An assumed discount rate was determined independently for each pension plan and other
postretirement benefit plan based on the Citigroup Above Median Curve (discount rate curve) using
high quality bonds (i.e. rated AA- or higher by S&P or Aa3 or higher by Moody’s). The discount rate
curve was then applied to match the estimated cash flows in each plan to reflect the timing and amount
of expected future benefit payments for these plans.
The assumption for expected long-term rate of return on plan assets was developed as a
weighted average of the expected earnings for the target asset portfolio. In developing the expected
long-term rate of return assumption, consideration was given to the historical performance of each
asset class in which the plans’ assets are invested and the target asset allocation for plan assets.
Our investment strategy and policies for the qualified pension plan assets held in the
Retirement Trust Fund were approved by our retirement committee, which is composed of senior
management employees with the assistance of an investment consultant. The policies set forth the
guidelines and objectives governing the investment of plan assets. Plan assets are invested for total
return with appropriate consideration for liquidity and portfolio risk. All investments are expected to
satisfy the requirements of the rule of prudent investments as set forth under the Employee Retirement
Income Security Act of 1974. The approved asset classes include cash and short-term investments,
fixed income, common stock and convertible securities, absolute and real return strategies, real estate
and investments in our common stock. Plan assets may be invested in separately managed accounts or
in commingled or mutual funds. Investment re-balancing takes place periodically as needed, or when
significant cash flows occur, in order to maintain the allocation of assets within the stated target
ranges. Our expected long-term rate of return is based upon historical index returns by asset class,
adjusted by a factor based on our historical return experience, diversified asset allocation and active
portfolio management by professional investment managers. The Retirement Trust Fund is not
currently invested in any NW Natural securities.
107
Our pension plan asset allocation at December 31, 2010 and 2009, and the target allocation and
expected long-term rate of return by asset category, are as follows:
Asset Category
US Large Cap Equity
US Small/Mid Cap Equity
Non-US Equity
Emerging Markets
Fixed Income
Real Estate
Absolute Return Strategy
Real Return Strategy
Cash and cash equivalents
Weighted Average
Percentage of
Plan Assets
Dec. 31,
2010
2009
5.2%
17.0% 17.5%
12.7% 13.8%
17.9% 19.4%
0.5%
16.6% 18.2%
6.5%
6.8%
14.8% 15.0%
6.8%
7.1%
2.3%
1.9%
Target
Allocation
Expected Long-term
Rate of Return
18%
12%
18%
5%
17%
8%
15%
7%
0%
8.25%
9.25%
8.85%
10.50%
5.25%
7.00%
8.00%
7.00%
-
8.25%
Our non-qualified supplemental defined benefit pension benefit obligations were $
24.9 million, $22.8 million and $19.6 million at December 31, 2010, 2009 and 2008,
respectively. These plans are not subject to regulatory deferral and the changes in actuarial gains and
losses, prior service costs and transition assets or obligations are recognized in AOCI under common
stock equity, net of tax, until they are amortized as a component of net periodic benefit cost. Although
these are unfunded plans with no plan assets due to their nature as non-qualified plans, we indirectly
fund a portion of our obligations with company- and trust-owned life insurance.
Our plans for providing postretirement benefits other than pensions also are unfunded plans,
but are subject to regulatory deferral. The gains and losses, prior service costs and transition assets or
obligations for these plans were recognized as a regulatory asset. The accumulated postretirement
benefit obligation for those plans was $ 27.7 million, $24.7 million and $23.9 million at December 31,
2010, 2009 and 2008, respectively.
Net periodic benefit cost consists of service costs, interest costs, the amortization of actuarial
gains and losses, the expected returns on plan assets and, in part, on a market-related valuation of
assets. The market-related valuation reflects differences between expected returns and actual
investment returns, which are recognized over a three-year period or less from the year in which they
occur, thereby reducing year-to-year net periodic benefit cost volatility.
108
The following tables provide the components of net periodic benefit cost for the qualified and
non-qualified pension and other postretirement benefit plans for the years ended December 31, 2010,
2009 and 2008 and the assumptions used in measuring these costs and benefit obligations:
Thousands
Pension Benefits
2009
2010
2008
Other Postretirement
Benefits
2009
2010
2008
$
Service cost
Interest cost
Expected return on plan assets
Amortization of transition obligations
Amortization of prior service costs
Amortization of net actuarial loss
6,688 $
18,029
(18,207)
-
187
7,447
6,402 $
17,948
(15,696)
-
1,223
6,810
6,141 $
17,373
(19,087)
19
1,253
385
588 $
522 $
1,436
-
411
197
131
1,568
-
411
197
-
521
1,403
-
411
197
-
Net periodic benefit cost
$
14,144 $
16,687 $
6,084 $ 2,763 $ 2,698 $ 2,532
Assumptions for net periodic benefit
cost:
Weighted-average discount rate
Rate of increase in compensation
Expected long-term rate of return
Assumptions for funded status:
Weighted-average discount rate
Rate of increase in compensation
Expected long-term rate of return
6.01%
6.60%
3.25-5.0% 3.25-5.0% 3.5-5.0%
8.25%
8.25%
8.25%
6.79% 5.78% 7.12% 6.56%
n/a
n/a
n/a
n/a
n/a
n/a
5.49%
6.01%
3.25-5.0% 3.25-5.0% 3.5-5.0%
8.25%
8.25%
8.25%
6.60% 5.16% 5.78% 7.12%
n/a
n/a
n/a
n/a
n/a
n/a
The assumed annual increase in health care cost trend rates used in measuring other
postretirement benefits as of December 31, 2010 were 8.5 percent for medical and 10.5 percent for
prescription drugs. Medical costs and prescription drugs are assumed to decrease gradually each year
to a rate of 5.0 percent by 2021.
We believe our pension assumptions to be appropriate based on plan design and an assessment
of market conditions. However, the following shows the sensitivity of our retirement benefit costs and
benefit obligations to future changes in certain actuarial assumptions:
Thousands, except percent
Discount rate:
Qualified defined benefit plans
Non-qualified plans
Other postretirement benefits
Expected long-term return on plan assets:
Qualified defined benefit plans
Change in
Assumption
(0.25%)
(0.25%)
Impact on 2010
Retirement
Benefit Costs
Impact on Retirement
Benefit Obligations
at Dec. 31, 2010
$850
8
42
552
$9,623
42
647
N/A
Assumed health care cost trend rates can have a significant effect on the amounts reported for
the health care plans. A one percentage point change in assumed health care cost trend rates would
have the following effects:
Thousands
Effect on net periodic postretirement health care benefit cost
Effect on the accumulated postretirement benefit obligation
109
1%
Increase
$ 64
$688
1%
Decrease
$ (57)
$(622)
The impact of a change in retirement benefit costs on operating results would be less than the
amounts shown above because only between 60 and 70 percent of our pension costs is charged to
operations and maintenance expense. The remaining 30 to 40 percent is capitalized to construction
accounts as payroll overhead and included in utility plant, which is amortized to expense over the
useful life of the asset placed into service.
The following table provides information regarding employer contributions and benefit
payments for the two qualified pension plans, non-qualified pension plans and other postretirement
benefit plans for the years ended December 31, 2010 and 2009, and estimated future contributions and
payments:
Thousands
Employer Contributions
Pension Benefits
Other Benefits
2009
2010
2011 (estimated)
Benefit Payments
2008
2009
2010
Estimated Future Payments
2011
2012
2013
2014
2015
2016-2020
$ 27,137
12,088
23,668
16,247
17,149
18,645
18,632
19,120
19,396
19,962
20,560
117,507
$ 1,428
1,476
2,109
1,259
1,428
1,476
2,109
2,078
2,096
2,169
2,159
11,226
We make contributions to our qualified defined benefit pension plans based on actuarial
assumptions and estimates, tax regulations and funding requirements under federal law. The Pension
Protection Act of 2006 (the Act) established new funding requirements for defined benefit plans. The
Act establishes a 100 percent funding target for plan years beginning after December 31,
2008. However, a delayed effective date of 2011 may apply if the pension plan meets the funding
targets, as measured under the Act, of 94 percent in 2009 and 96 percent in 2010. Our qualified defined
benefit pension plans are currently underfunded by $95.4 million at December 31, 2010, and we expect
to make contributions during 2011 of approximately $22 million.
The Retirement K Savings Plan provided to our employees is a qualified defined contribution
plan under Internal Revenue Code Section 401(k). The supplemental deferred compensation plans for
eligible officers and senior managers are non-qualified plans. These plans are designed to enhance the
retirement savings of employees and to assist them in strengthening their financial security by
providing an incentive to save and invest regularly. Our contributions to these plans totaled $2.1
million in 2010, 2009 and 2008. The Retirement K Savings Plan includes an Employee Stock
Ownership Plan. In addition, we make contributions on behalf of each union employee to the Western
States Office and Professional Employees Pension Fund, a multi-employer plan. Our contributions to
the Western States Plan amounted to $0.4 million in 2010, 2009 and 2008.
110
Fair Value
Following is a description of the valuation methodologies used for assets measured at fair
value. In cases where the pension plan is invested through a collective trust fund or mutual fund, our
custodian uses the fund’s market value. The custodian also provides the market values for investments
directly owned.
U.S. large cap equity: These are level 1 assets valued at the closing price reported on the
active market on which the individual security is traded. This asset class includes investments
primarily in U.S. common stocks.
U.S. small/mid cap equity: These are level 2 assets valued based on information provided by
the plan’s investment custodians. The financial statements of the commingled fund are audited
annually by independent accountants. Values for such funds are stated at estimated fair values, which
have been determined based on the unit values of the funds. Unit values are determined by the bank
sponsoring such funds by dividing the fund’s net assets at fair value by its units outstanding at the
valuation date. This asset class includes investments primarily in U.S. common stocks.
Non-U.S. equity: These are level 1 and 2 assets. Level 1 assets are valued at the closing price
reported on the active market on which the individual security is traded. Level 2 assets are valued
based on information provided by the plan’s investment custodians. The financial statements of the
commingled fund are audited annually by independent accountants. Values for such funds are stated at
estimated fair values, which have been determined based on the unit values of the funds. Unit values
are determined by the bank sponsoring such funds by dividing the fund’s net assets at fair value by its
units outstanding at the valuation date. This asset class includes investments primarily in foreign equity
common stocks.
Emerging market equity: These are level 1 assets valued at the net asset value of the shares
held by the plan at the valuation date. This asset class includes investments primarily in common
stocks in emerging markets.
Fixed income: These are level 1 assets valued at the net asset value of the shares held by the
plan at the valuation date. This asset class includes investments primarily in investment grade debt and
fixed income securities.
Real estate funds: These are level 3 assets valued based on the interest held by the plan, for
which fair values of the underlying investments are subject to appraisal as directed by the funds’
management. This asset class includes a real estate fund that invests directly in real estate. The
underlying properties held in the funds are appraised utilizing the following approaches: the cost
approach (the current cost of replacing the real estate less deterioration and functional and economic
obsolescence); the income approach (the ability of the underlying properties to generate net rental
income); and the comparable sales approach (recent sales of comparable real estate in the same
market). The plan’s ability to redeem these investments is subject to certain restrictions and cash
availability.
Absolute return strategy: These are level 2 assets valued based on information provided by
the plan’s investment custodians. The financial statements of the partnerships are audited annually by
independent accountants, with the value of the underlying investments based on the estimated fair
value of the various holdings in the portfolio as reported in the financial statements at net asset
111
value. This asset class includes a hedge fund of funds. Our investment normally provides for a
quarterly distribution subject to 95 days advance notice of withdrawal. Currently there are no
restrictions on withdrawal requests, and as of December 31, 2010 we have not submitted a withdrawal
request.
Real return strategy: These are level 1 assets valued at the net asset value of the shares held
by the plan at the valuation date. This asset class includes an investment in a broad range of assets and
strategies primarily including fixed income and equity securities, along with commodities.
Cash and cash equivalents: These are level 2 assets valued at the net asset value of the shares
held by the plan at the valuation date. This asset class primarily includes a money market mutual fund.
The preceding valuation methods may produce a fair value calculation that is not indicative of
net realizable value or reflective of future fair values. Furthermore, although we believe these valuation
methods are appropriate and consistent with other market participants, the use of different
methodologies or assumptions to determine the fair value of certain financial instruments could result
in a different fair value measurement at the reporting date.
Investment securities are exposed to various financial risks including interest rate, market and
credit risks. Due to the level of risk associated with certain investment securities, it is reasonably
possible that changes in the values of our investment securities will occur in the near term and that
such changes could materially affect our investment account balances and the amounts reported as plan
assets available for benefits payments.
112
The following table presents the fair value of plan assets, including outstanding receivables
and liabilities, of the Retirement Trust Fund as of December 31, 2010 and 2009:
Investments, in thousands
U.S. large cap equity
U.S. small/mid cap equity
Non-U.S. equity
Emerging markets equity
Fixed income
Real estate
Absolute return strategy
Real return strategy
Cash and cash equivalents
Total investments
Investments, in thousands
U.S. large cap equity
U.S. small/mid cap equity
Non-U.S. equity
Emerging markets equity
Fixed income
Real estate
Absolute return strategy
Real return strategy
Cash and cash equivalents
Total investments
Receivables
Accrued interest and dividend income
Due from broker for securities sold
Total receivables
Liabilities
Due to broker for securities purchased
Total investment in retirement trust
Level 1
$ 37,231
-
24,630
11,476
36,429
-
-
15,452
-
December 31, 2010
Level 2 Level 3
$
-
27,864
14,549
-
-
-
32,378
-
3,629
$
-
-
-
-
-
14,721
-
-
-
Total
$ 37,231
27,864
39,179
11,476
36,429
14,721
32,378
15,452
3,629
$125,218
$78,420
$14,721
$218,359
Level 1
$ 35,266
-
25,395
1,021
36,682
-
-
13,592
-
December 31, 2009
Level 2 Level 3
$
-
27,953
13,456
-
-
-
30,097
-
4,614
$
-
-
-
-
-
12,936
-
-
-
Total
$ 35,266
27,953
38,851
1,021
36,682
12,936
30,097
13,592
4,614
$111,956
$76,120
$12,936
$201,012
December 31,
2010
2009
249
448
697
$
$
200
400
600
42
$
300
$
$
$
$219,014
$201,312
113
Level 3 Investments
The following table presents the beginning balance, activity and ending balance of Level 3
investments that have their fair values established using significant unobservable inputs as of
December 31, 2010:
Thousands
January 1, 2010 balance
Total gains or (losses)
Included in earnings (or changes in net assets)
Purchases, sales, issuances and settlements
December 31, 2010 balance
10.
Income Tax
Level 3 Assets
Real estate Funds
$12,936
1,785
$14,721
A reconciliation between income taxes calculated at the statutory federal tax rate and the
provision for income taxes reflected in the consolidated financial statements is as follows:
Thousands, except percentages
Income taxes at federal statutory rate
Increase (decrease):
Current state income tax, net of federal tax benefit
Amortization of investment and energy tax credits
Differences required to be flowed-through by regulatory
commissions
Gains on company and trust-owned life insurance
Other - net
Total provision for income taxes
Federal statutory tax rate
Increase (decrease):
Current state income tax, net of federal tax benefit
Amortization of investment and energy tax credits
Differences required to be flowed-through by regulatory
commissions
Gains on company and trust-owned life insurance
Other - net
Effective tax rate
2010
2009
2008
$42,745
$42,627
$38,571
5,803
(525)
1,647
(715)
507
5,568
(593)
4,100
(646)
(116)
(1,195)
380
(704)
(767)
124
$49,462
$46,671
$40,678
35.0%
35.0%
35.0%
4.8%
-0.4%
1.3%
-0.6%
0.4%
40.5%
4.6%
-0.5%
-0.1%
-1.0%
0.3%
38.3%
3.7%
-0.6%
-0.6%
-0.7%
0.1%
36.9%
114
The provision (benefit) for current and deferred income taxes consists of the following:
Thousands
Current
Federal
State
Deferred
Federal
State
Total provision for income taxes
Total income taxes paid
2010
2009
2008
$(28,592) $ 6,221
2,300
8,521
1,441
(27,151)
$ (7,970)
(437)
(8,407)
69,159
7,454
76,613
$ 49,462
31,937
6,213
38,150
$46,671
42,862
6,223
49,085
$40,678
$ 22,600
$10,000
$12,300
The following table summarizes the total provision (benefit) for income taxes for the regulated
utility and non-utility business segments for the three years ended December 31:
Thousands
Regulated utility:
Current
Deferred
Deferred investment and energy tax credits
Non-utility business segments:
Current
Deferred
Total provision for income taxes
2010
2009
2008
$ (1,464) $
47,741
(525)
45,752
871
40,829
(593)
41,107
$(13,034)
48,790
(646)
35,110
(25,687)
29,397
3,710
$ 49,462
7,650
(2,086)
5,564
$46,671
4,627
941
5,568
$ 40,678
The following table summarizes the tax effect of significant items comprising our deferred
income tax accounts for the two years ended December 31:
Thousands
Deferred tax liabilities:
Plant and property
Regulatory adjustment for income taxes paid
Regulatory income tax assets
Regulatory liabilities
Non-regulated deferred tax liabilities
Total
Deferred tax assets:
Regulatory assets
Unfunded pension and postretirement obligations
Non-regulated deferred tax assets
Alternative minimum tax credit carryforward
Loss and credit carryforwards
Total
Deferred income tax liabilities - net
Deferred investment tax credits
Deferred income taxes and investment tax credits
115
2010
2009
$255,471
5,272
68,822
23,159
34,544
$387,268
$231,768
2,169
72,721
13,506
-
$320,164
(1,402)
(4,342)
(772)
(1,702)
(7,071)
(15,289)
371,979
1,430
$373,409
(14,436)
(3,925)
(2,860)
-
-
(21,221)
298,943
1,955
$300,898
We have determined that we are more likely than not to realize all recorded deferred tax assets
as of December 31, 2010.
The following is a reconciliation of the change in our deferred tax balance for the year ended
December 31, 2010:
Thousands
Deferred tax expense, above, including investment tax credit
Decrease in differences required to be flowed-through
Increase in minimum pension liability included in AOCI
Decrease in deferred taxes associated with asset held for sale
Decrease in deferred investment tax credits
Change in deferred income tax accounts
2010
$77,138
(3,899)
(417)
214
(525)
$72,511
We calculate our deferred tax assets and liabilities according to accounting guidance on
income taxes, whereby deferred income taxes are generally determined based on the difference
between the financial statement and tax bases of assets and liabilities using enacted tax rates in effect
in the years in which the differences are expected to reverse. Deferred tax provisions are not recorded
in the income statement for certain temporary differences where regulators require that we flow
through deferred income tax benefits or expenses in the utility ratemaking process.
In September 2010, Congress passed the Unemployment Insurance, Reauthorization and Job
Creation Act of 2010 (the 2010 Act) and the legislation was signed into law by President Obama. The
Act extends for one additional year the temporary 50 percent bonus depreciation first enacted in the
Economic Stimulus Act of 2008 (the 2008 Act) and subsequently renewed in the American Recovery
and Reinvestment Act of 2009. Under the 2010 Act, an additional temporary first-year tax deduction
for depreciation equal to 100 percent of the adjusted basis of qualified property may be deducted in the
year the property is placed in service. The 100 percent depreciation deduction in the first year is an
acceleration of depreciation deductions that otherwise would have been taken in the later years of an
asset’s recovery period. As a result of this extension, we will recognize an increase in our cash flow by
reducing our current tax liability for the 2010 tax year. Any deductions in excess of income for federal
income tax purposes will be carried back to the 2009 tax year or carried forward to the 2011 tax year.
We estimate this extension will generate cash flow of between $40 million to $45 million in federal
income taxes.
For the year ended December 31, 2010, we reported an estimated net operating loss (NOL) for
federal income tax purposes of $94.4 million, primarily due to the effects of accelerated tax
depreciation provided by the 2010 Act. The federal NOL will be carried back to 2009 and partially
utilized for a refund of taxes paid in prior years. The remaining NOL of approximately $20.2 million
will be carried forward to reduce current taxes paid in the 2011 tax year. We anticipate that we will be
able to use all loss carryforwards in future years. The 2010 federal NOL would expire in 2031 if not
used in earlier years.
In December 2008, we filed an application with the Internal Revenue Service (IRS) requesting
a change in our tax accounting method to expense routine repair and maintenance costs for gas
pipelines that are currently being capitalized and depreciated for book purposes. The IRS consented to
our request in August 2009, and we recognized a tax deduction of approximately $59 million on our
2008 tax return as a result of this method change, which resulted in a federal refund of approximately
$21 million during the fourth quarter of 2009.
116
For the year ended December 31, 2008, we reported an NOL for federal and Oregon income
tax purposes of $19.2 million and $23.8 million, respectively, primarily due to the effects of
accelerated tax depreciation provided by the 2008 Act. As a result of the change in our tax accounting
method for repair and maintenance costs discussed above as well as our increased pension
contribution, our NOL for federal and Oregon income tax purposes was $89.0 million and $87.2
million on our 2008 federal and Oregon tax returns, respectively. The federal NOL was carried back to
2006 and fully utilized for a refund of taxes paid in prior years, while the Oregon NOL was carried
forward to 2009 and fully utilized reducing current Oregon taxes paid for the 2009 tax year.
Uncertain tax positions are accounted for in accordance with accounting standards that require
management’s assessment of the expected treatment of a tax position taken in a filed tax return, or
planned to be taken in a future tax return, that has not been reflected in measuring income tax expense
for financial reporting purposes. Until such positions are sustained by the taxing authorities, we would
not recognize the tax benefits resulting from such positions and would report the tax effect as a liability
in the Company’s consolidated balance sheet. As of December 31, 2010, we had no uncertain tax
positions.
An IRS examination of the 2006 through 2008 consolidated federal income tax returns
commenced during the fourth quarter of 2009. The IRS completed its examination of the 2002 through
2004 audit cycle in the second quarter of 2006. Completion of the 2006 through 2008 federal income
tax return examination is expected during the first quarter of 2011.
The Oregon Department of Revenue (ODOR) is currently examining our 2006 through 2008
consolidated Oregon income tax returns. Completion of this examination is expected during the first
quarter of 2011.
Interest and penalties related to any future income tax deficiencies will be recorded within
income tax expense in the consolidated statements of income.
11.
Property, Plant and Equipment
The following table sets forth the major classifications of our property, plant and equipment
and accumulated depreciation at December 31:
Thousands, except percentages
Utility plant in service
Utility construction work in progress
Less accumulated depreciation
Utility plant-net
Non-utility plant in service
Non-utility construction work in progress
Less accumulated depreciation
Non-utility plant-net
Total property plant and equipment
117
December 31,
2010
$2,247,952
29,324
710,214
2009
$2,188,176
27,936
682,060
1,567,062
1,534,052
290,038
9,088
12,025
66,084
80,538
10,540
$ 287,101
$ 136,082
$1,854,163
$1,670,134
The weighted average depreciation rate for utility assets was 2.8 percent in 2010 and
2.9 percent in 2009. The weighted average depreciation rate for non-utility assets was 2.5 percent in
2010 and 2.2 percent in 2009.
Accumulated depreciation does not include the accumulated provision for asset removal costs
of $252.9 million and $238.8 million at December 31, 2010 and 2009, respectively. These accrued
asset removal costs are reflected on the balance sheets as regulatory liabilities (see Note 2, “Plant and
Property and Accrued Asset Removal Costs”).
The OPUC and WUTC approved our filed depreciation study and our request to change the
amortization of our regulatory tax asset account balance on pre-1981 plant. These approvals
specifically authorized the implementation of new depreciation rates in Oregon and Washington, with a
corresponding decrease to customer billing rates effective January 1, 2009. The new regulatory tax
amortization schedule on pre-1981 assets, with a corresponding increase to customer rates, became
effective January 1, 2009 in Washington and November 1, 2009 in Oregon. The implementation of the
new rates decreases depreciation expense and increases income tax expense, both of which are offset
on an annualized basis by a corresponding change in utility operating revenues. FERC also approved
the application of these new depreciation rates for our interstate gas storage assets in May 2009, and
the new rates were made effective as of January 1, 2009. Due to the depreciation rate decreases, total
depreciation and amortization expense in 2009 decreased by $9.3 million, or 13 percent. In 2010 asset
additions have caused an increase in total depreciation and amortization expense of $2.3 million, or
3.7 percent.
12.
Investments
Our other long-term investments include financial investments in life insurance policies, which
are accounted for at fair value, and equity investments in certain partnerships and limited liability
companies, which are accounted for under the equity or cost methods. The following table summarizes
our long-term investments at December 31:
Thousands
Life insurance investments
Note receivable
Investments in gas pipeline joint ventures
Other
Total other investments
2010
2009
$51,090
12
15,742
2,250
$49,327
609
15,154
2,275
$69,094
$67,365
Life Insurance Investment. We have invested in key person life insurance contracts to
provide an indirect funding vehicle for certain long-term employee benefit plan liabilities. The amount
in the above table is reported as cash surrender value, net of policy loans.
Investments in Gas Pipeline Joint Ventures. We have two investments in gas pipeline joint
ventures. Our primary investment is in PGH, owned 50 percent by us and 50 percent by Gas
Transmission Northwest Corporation, an indirect wholly-owned subsidiary of TransCanada
Corporation. Our other gas pipeline joint venture investment is a 10 percent undivided interest that is
not material to our consolidated assets or net income. PGH plans to develop a natural gas transmission
pipeline in Oregon to serve our utility as well as the growing natural gas markets in Oregon and other
parts of the Pacific Northwest, through its wholly-owned subsidiary Palomar. Palomar is a
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development stage entity. As of December 31, 2010 and 2009 our investment in PGH was
$14.8 million and $14.1 million, respectively, primarily related to planning and permitting. The
increase in our equity investment balance over the last 12 months is from an income allocation based
on our 50 percent ownership interest. We did not make any equity contributions during 2010.
Variable Interest Entities. PGH is a variable interest entity. As of December 31, 2010, we
updated our VIE analysis and determined that we are not the primary beneficiary of PGH’s activities as
defined by the authoritative guidance related to consolidations (see Note 2). Therefore, we account for
our investment in PGH and the Palomar project under the equity method, which is included in other
investments on our balance sheet. Our maximum loss exposure related to PGH is limited to our equity
investment balance, less our share of any cash or other assets available to us as a 50 percent owner.
PGH Impairment Analysis. In May 2010, we learned that the company proposing to build an
LNG terminal on the Columbia River had suspended its operations and filed for bankruptcy. This
company previously entered into a precedent agreement with Palomar for a majority of the
transmission capacity on the proposed pipeline. As of December 31, 2010, Palomar had incurred a total
$45.6 million of capital costs, including AFUDC, toward the development of the pipeline (both east
and west segments), and it had collected $15.8 million from a letter of credit which supported the
bankrupt shipper’s obligations under a prior precedent agreement. Palomar also received certain assets
out of the bankrupt company’s liquidation.
We performed an impairment analysis of our total equity investment as of December 31, 2010
and determined that no impairment write-down is needed because the fair value of the expected
development of this pipeline exceeds our total equity investment. If, however, we learn that the project
is not viable, we could be required to recognize an impairment of up to approximately $14 million
based on the amount of our equity investment as of December 31, 2010 net of cash and working capital
at Palomar. We will continue to monitor and update our impairment analysis as needed.
13.
Derivative Instruments
We enter into swap, option and combinations of option contracts for the purpose of hedging
natural gas which qualify as non-trading derivative instruments under accounting rules for derivative
instruments and hedging activities. We primarily use these derivative financial instruments to manage
commodity prices related to our natural gas purchase requirements.
In the normal course of business, we enter into indexed-price physical forward natural gas
commodity purchase (gas supply) contracts to meet the requirements of core utility customers. We also
enter into financial derivatives, up to prescribed limits, to hedge price variability related to the physical
gas supply contracts. Derivatives entered into prudently for future gas years prior to our annual PGA
filing receive regulatory deferred accounting treatment. Derivative contracts entered into after the
annual PGA rate was set on November 1, 2010 that are for the current gas contract year are subject to
our PGA incentive sharing mechanism, which provides for 90 percent of the changes in fair value to be
deferred as regulatory assets or liabilities and the remaining 10 percent to be recorded to the income
statement for contracts not qualifying for cash flow hedge accounting and to other comprehensive
income for contracts qualifying for cash flow hedge accounting.
Certain natural gas purchases from Canadian suppliers are payable in Canadian dollars,
including both commodity and demand charges, which expose us to adverse changes in foreign
currency rates. Foreign currency forward contracts are used to hedge the fluctuation in foreign
119
currency exchange rates for our commodity and commodity-related demand charges paid in Canadian
dollars. Foreign currency contracts for commodity costs are purchased on a month-to-month basis
because the Canadian cost is priced at the average noon-day exchange rate for each month. Foreign
currency contracts for demand costs have terms ranging up to 12 months. The gains and losses on the
shorter-term currency contracts for commodity costs are recognized immediately in cost of gas. The
gains and losses on the currency contracts for demand charges are not recognized in current income
because they are subject to a regulatory deferral tariff and, as such, are recorded as a regulatory asset or
liability. These forward contracts qualify for cash flow hedge accounting treatment under accounting
for derivatives and hedges. The mark-to-market adjustment at December 31, 2010 was an unrealized
gain of $0.1 million. This unrealized gain is subject to regulatory deferral and, as such, was recorded as
a derivative instrument, which is offset by recording a corresponding amount to a regulatory liability
account.
The unrealized mark-to-market value at December 31, 2010 for all derivative contracts
outstanding was a net loss of $52.6 million consisting of the following: a $52.7 million unrealized loss
on natural gas commodity hedge and derivative contracts, and a $0.1 million unrealized gain on the
foreign exchange forward contracts.
Derivative hedge contracts are subject to a hedge effectiveness test to determine the financial
statement treatment of each specific derivative. As of December 31, 2010, all of our derivatives were
effective economic hedges and either qualified or were expected to qualify for regulatory deferral or
hedge accounting treatment. We use the dollar offset method under accounting for derivatives and
hedges to determine the hedge effectiveness of derivative contracts. The effectiveness test applied to
financial derivatives is dependent on the type of derivative and its use. All derivatives were effective as
of December 31, 2010.
Most of our commodity hedging for the upcoming gas year is completed prior to the start of
each gas year, and these hedge prices are included in our annual PGA filing. We typically hedge
approximately 75 percent of our anticipated year-round sales volumes based on normal weather. We
entered the 2010-11 gas year (November 1, 2010 – October 31, 2011) hedged at a targeted level of
approximately 77 percent, including 62 percent financially hedged and 15 percent physically hedged
through gas storage volumes.
At December 31, 2010 we were hedged with financial contracts for the upcoming gas year at
approximately 45 percent, based on anticipated sales volumes. Of the amount hedged for the 2011-12
gas year at December 31, 2010, we were hedged approximately 30 percent with financial contracts,
and at 15 percent attributable to storage.
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The following table discloses the balance sheet presentation of our derivative instruments as of
December 31, 2010 and 2009:
Thousands
Assets:(1)
Natural gas commodity
Foreign exchange
Total
Liabilities:(2)
Natural gas commodity
Total
(1)
(2)
Fair Value of Derivative Instruments
2010
2009
Current Non-Current Current Non-Current
$ 2,154
91
$ 2,245
$
$
628
-
628
$ 6,214
290
$ 6,504
$38,437
$17,022
$19,643
$38,437
$17,022
$19,643
$ 843
-
$ 843
$3,193
$3,193
Unrealized fair value gains are classified under current- or non-current assets as derivative
instruments.
Unrealized fair value losses are classified under current- or non-current liabilities as derivative
instruments.
The following table discloses the income statement presentation for the unrealized gains and
losses from our derivative instruments for the years ended December 31, 2010 and 2009. All of our
currently outstanding derivative instruments are related to regulated utility operations as illustrated by
the derivative gains and losses being deferred to balance sheet accounts in accordance with regulatory
accounting.
Thousands
2010
2009
Natural gas
commodity(1)
Foreign
exchange(2)
Natural gas
commodity(1)
Foreign
exchange(2)
Cost of sales
Other comprehensive income (loss)
Less:
Amounts deferred to regulatory accounts on
balance sheet
Total impact on earnings
$(52,677)
-
52,677
$
-
$
-
91
(91)
$
-
$(15,779)
-
$
-
290
15,779
$
-
(290)
$
-
(1)
(2)
Unrealized gain (loss) from natural gas commodity hedge contracts is recorded in cost of sales
and reclassified to regulatory deferral accounts on the balance sheet.
Unrealized gain (loss) from foreign exchange forward purchase contracts is recorded in other
comprehensive income, and reclassified to regulatory deferral accounts on the balance sheet.
Our derivative instrument liabilities exclude the netting of collateral. We had no collateral
posted with our counterparties as of December 31, 2010 or 2009. We attempt to minimize the potential
exposure to collateral calls by our counterparties to manage our liquidity risk. Based on our current
credit ratings, most counterparties allow us credit limits ranging from $25 million to $50 million before
collateral postings are required. Our collateral call exposure is set forth under credit support
agreements, which generally contain credit limits. We also could be subject to collateral call
exposure where we have agreed to provide adequate assurance, which is not specific as to the amount
of credit limit allowed, but could potentially require additional collateral in the event of a material
121
adverse change. Based upon current contracts outstanding, which reflect unrealized losses of
$52.7 million at December 31, 2010, we have estimated the projected collateral demands, with and
without potential adequate assurance calls, using current gas prices and various downgrade credit
rating scenarios for NW Natural as follows:
Thousands
Credit Rating Downgrade Scenarios
(Current
Ratings)
A+/A3 BBB+/Baa1 BBB/Baa2 BBB-/Baa3 Speculative
With Adequate Assurance Calls
Without Adequate Assurance Calls
$-
$-
$-
$-
$1,988
$1,988
$6,988
$6,988
$27,300
$23,527
As of December 31, 2010 and 2009, we realized net losses of $61.0 million and $187.9
million, respectively, from the settlement of natural gas hedge contracts at maturity, which were
recorded as increases to the cost of gas. The currency exchange rate in all foreign currency forward
purchase contracts is included in our purchased cost of gas at settlement; therefore, no gain or loss is
recorded from the settlement of those contracts. We settled our $50 million interest rate swap in March
2009, concurrent with our issuance of the underlying long-term debt, and realized a $10.1 million
effective hedge loss which is being amortized to interest expense over the term of the debt.
We are exposed to derivative credit risk primarily through securing pay-fixed natural gas
commodity swaps to hedge the risk of price increases for our natural gas purchases on behalf of
customers. We utilize master netting arrangements through International Swaps and Derivatives
Association contracts to minimize this risk along with collateral support agreements with
counterparties based on their credit ratings. In certain cases we require guarantees or letters of credit
from counterparties in order for them to meet our minimum credit requirement standards.
Our financial derivatives policy requires counterparties to have a certain investment-grade
credit rating at the time the derivative instrument is entered into, and the policy specifies limits on the
contract amount and duration based on each counterparty’s credit rating. We do not speculate on
derivatives; instead we utilize derivatives to hedge our exposure above risk tolerance limits. Any
increase in market risk created by the use of derivatives should be offset by the exposures they modify.
We actively monitor our derivative credit exposure and place counterparties on hold for
trading purposes or require other forms of credit assurance, such as letters of credit, cash collateral or
guarantees as circumstances warrant. Our ongoing assessment of counterparty credit risk includes
consideration of credit ratings, credit default swap spreads, bond market credit spreads, financial
condition, government actions and market news. We utilize a Monte-Carlo simulation model to
estimate the change in credit and liquidity risk from the volatility of natural gas prices. We use the
results of the model to establish earnings at-risk trading limits. Our credit risk for all outstanding
derivatives at December 31, 2010 currently does not extend beyond October 2013.
We could become materially exposed to credit risk with one or more of our counterparties if
natural gas prices experience a significant increase. If a counterparty were to become insolvent or fail
to perform on its obligations, we could suffer a material loss, but we would expect such loss to be
eligible for regulatory deferral and rate recovery, subject to prudency review. All of our existing
counterparties currently have investment-grade credit ratings.
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Fair Value
In accordance with fair value accounting, we include nonperformance risk in calculating fair
value adjustments. This includes a credit risk adjustment based on the credit spreads of our
counterparties when we are in an unrealized gain position, or on our own credit spread when we are in
an unrealized loss position. Our assessment of non-performance risk is generally derived from the
credit default swap market and from bond market credit spreads. The impact of the credit risk
adjustments for all outstanding derivatives was immaterial to the fair value calculation at December 31,
2010. We also did not have any transfers between level 1 or level 2 during the year ended
December 31, 2010 and 2009.
The following table provides the fair value hierarchy of our net derivative instruments as of
December 31, 2010 and 2009:
Thousands
Level 1
Level 2
Level 3
14.
Leases
Description of Derivative Inputs
2010
2009
Quoted prices in active markets
Significant other observable inputs
Significant unobservable inputs
$
-
(52,586)
-
$
-
(15,489)
-
$(52,586) $(15,489)
We lease land, buildings and equipment under agreements that expire in various years through
2095. Rental expense under operating leases was $5.1 million, $5.3 million and $4.7 million for the
years ended December 31, 2010, 2009 and 2008, respectively. The table below reflects the future
minimum lease payments due under non-cancelable leases at December 31, 2010. Such payments total
$52.7 million for operating leases. The net present value of payments on capital leases less imputed
interest was $1.0 million. These commitments relate principally to the lease of our office headquarters,
underground gas storage facilities, vehicles and computer equipment.
Thousands
Operating leases
Capital leases
2011
2012
2013
2014
2015
Later
years
$4,984
482
$4,937
330
$4,909
178
$5,152
9
$5,034
-
$28,169
-
Minimum lease payments
$5,466
$5,267
$5,087
$5,161
$5,034
$28,169
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15.
Commitments and Contingencies
Gas Purchase and Pipeline Capacity Purchase and Release Commitments
We have signed agreements providing for the reservation of firm pipeline capacity under
which we are required to make fixed monthly payments for contracted capacity. The pricing
component of the monthly payment is established, subject to change, by U.S. or Canadian regulatory
bodies. In addition, we have entered into long-term sale agreements to release firm pipeline
capacity. We also enter into short-term and long-term gas purchase agreements. The aggregate
amounts of these agreements were as follows at December 31, 2010:
Thousands
2011
2012
2013
2014
2015
Thereafter
Total
Less: Amount representing interest
Total at present value
Gas
Purchase
Agreements
Pipeline
Capacity
Purchase
Agreements
Pipeline
Capacity
Release
Agreements
$111,514
19,310
13,684
11,404
-
-
155,912
1,151
$ 87,046
56,610
48,953
25,059
17,853
253,254
488,775
129,793
$3,464
-
-
-
-
-
3,464
5
$154,761
$358,982
$3,459
Our total payments for fixed charges under capacity purchase agreements in 2010, 2009 and
2008 were $91.4 million, $84.6 million and $85.7 million, respectively. Included in the amounts were
reductions for capacity release sales of $4.2 million for 2010, $4.2 million for 2009 and $5.0 million
for 2008. In addition, per-unit charges are required to be paid based on the actual quantities shipped
under the agreements. In certain take-or-pay purchase commitments, annual deficiencies may be offset
by prepayments subject to recovery over a longer term if future purchases exceed the minimum annual
requirements.
Environmental Matters
We own, or previously owned, properties that may require environmental remediation or
action. We accrue all material loss contingencies relating to these properties that we believe to be
probable of assertion and reasonably estimable. We continue to study and evaluate the extent of our
potential environmental liabilities, but due to the numerous uncertainties surrounding the course of
environmental remediation and the preliminary nature of several site investigations, in some cases, we
may not be able to reasonably estimate the high end of the range of possible loss. In those cases we
have disclosed the nature of the potential loss and the fact that the high end of the range cannot be
reasonably estimated.
We regularly review our environmental liability for each site where we may be exposed to
remediation responsibilities. The costs of environmental remediation are difficult to estimate. A
number of steps are involved in each environmental remediation effort, including site investigations,
remediation, operations and maintenance, monitoring and site closure. Each of these steps may, over
124
time, involve a number of alternative actions, each of which can change the course and scope of the
effort. Many of these steps are dependent upon the approval and direction of federal and state
environmental regulators. The policies, determinations and directions of the regulators may develop
and change over time and different regulators may take different positions on the various steps,
creating further uncertainty as to the timing and scope of remediation activities. In certain cases, in
addition to us, there are a number of other potentially responsible parties, each of which, in
proceedings and negotiations with other potentially responsible parties and regulators, may influence
the course and scope of the remediation effort. The allocation of liabilities among the potentially
responsible parties is often subject to dispute and can be highly uncertain. The events giving rise to
environmental liabilities often occurred many decades ago, which complicates the determination of
allocating liabilities among potentially responsible parties. Site investigations and remediation efforts
often develop slowly over many years. In addition, disputes may arise between potentially responsible
parties and regulators as to the severity of particular environmental matters and what remediation
efforts are appropriate. These disputes could lead to adversarial administrative proceedings or
litigation, with uncertain outcomes.
We estimate the range of loss for environmental liabilities using current technology, enacted
laws and regulations, industry experience gained at similar sites and an assessment of the probable
level of involvement and financial condition of other potentially responsible parties. Unless there is an
estimate within this range of possible losses that is more likely than other cost estimates, we record the
liability at the lower end of this range. It is likely that changes in these estimates and ranges will occur
throughout the remediation process for each of these sites due to uncertainty concerning our
responsibility, the complexity of environmental laws and regulations and the selection of compliance
alternatives. The status of each of the sites currently under investigation is provided below.
Gasco site. We own property in Multnomah County, Oregon that is the site of a former gas
manufacturing plant that was closed in 1956 (Gasco site). The Gasco site has been under investigation
by us for environmental contamination under the Oregon Department of Environmental Quality’s
(ODEQ) Voluntary Clean-Up Program. In June 2003, we filed a Feasibility Scoping Plan and an
Ecological and Human Health Risk Assessment with the ODEQ, which outlined a range of remedial
alternatives for the most contaminated portion of the Gasco site. In May 2007, we completed a revised
Remediation Investigation Report and submitted it to the ODEQ for review. We also submitted a
Focused Feasibility Study (FFS) for the groundwater source control portion of the Gasco site, which
ODEQ conditionally approved in March 2008, subject to the submission of additional information. We
provided that information to ODEQ and are now working with the agency on the final design for the
source control system. Based on the information currently available for groundwater source control at
the Gasco site and our current assumptions regarding remediation, we have estimated a range of
liability between $11 million and $30 million, for which we have recorded an accrued liability of $11.4
million at December 31, 2010. The range of liability will be reassessed when ODEQ makes a final
source control design decision. In addition to groundwater source control, we signed a joint Order on
Consent with the Environmental Protection Agency (EPA), which requires the design of remedial
action for sediments from the Gasco site. This design project is underway. We also have other
investigation and clean-up work, including work on the uplands portion of the Gasco site, that we
expect to be required. For the sediments project and other work, we have recorded an additional
accrued liability of $38.9 million, which reflects the low end of the range of potential liability. We
have accrued at the low end of the range of potential liability for the sediments project and other
environmental work at the Gasco site because no amount within the range is considered to be more
likely than another, and the high end of the range cannot reasonably be estimated.
125
Siltronic site. We previously owned property adjacent to the Gasco site that now is the
location of a manufacturing plant owned by Siltronic Corporation (the Siltronic site). We are currently
conducting an investigation of manufactured gas plant wastes on the uplands at this site for the
ODEQ. The liability accrued at December 31, 2010 for the Siltronic site is $0.9 million, which is at the
low end of the range of potential liability because no amount within the range is considered to be more
likely than another, and the high end of the range cannot reasonably be estimated.
Portland Harbor site. In 1998, the ODEQ and the EPA completed a study of sediments in a
5.5-mile segment of the Willamette River (Portland Harbor) that includes an area adjacent to the Gasco
and Siltronic sites. The Portland Harbor was listed by the EPA as a Superfund site in 2000 and we were
notified that we are a potentially responsible party. We then joined with other potentially responsible
parties, referred to as the Lower Willamette Group, to fund environmental studies in the Portland
Harbor. Subsequently, the EPA approved a Programmatic Work Plan, Field Sampling Plan and Quality
Assurance Project Plan for the Portland Harbor Remedial Investigation/Feasibility Study (RI/FS),
completion of which is scheduled for 2011. The EPA and the Lower Willamette Group are conducting
focused studies on approximately nine miles of the lower Willamette River, including the 5.5-mile
segment previously studied by the EPA. In August 2008, we signed a cooperative agreement to
participate in a phased natural resource damage assessment, with the intent to identify what, if any,
additional information is necessary to estimate further liabilities sufficient to support an early
restoration-based settlement of natural resource damage claims. As of December 31, 2010, we have a
liability accrued of $8.1 million for this site, which is at the low end of the range of the potential
liability because no amount within the range is considered to be more likely than another, and the high
end of the range cannot reasonably be estimated.
Central Service Center site. In 2006, we received notice from the ODEQ that our Central
Service Center in southeast Portland (Central Service Center site) was assigned a high priority for
further environmental investigation. Previously there were three manufactured gas storage tanks on the
premises. The ODEQ believes there could be site contamination associated with releases of condensate
from stored manufactured gas as a result of historic gas handling practices. In the early 1990s, we
excavated waste piles and much of the contaminated surface soils and removed accessible waste from
some of the abandoned piping. In early 2008, we received notice that this site was added to the
ODEQ’s list of sites where releases of hazardous substances have been confirmed and to its list where
additional investigation or cleanup is necessary. We are currently performing an environmental
investigation of the property with the ODEQ’s Independent Cleanup Pathway. As of December 31,
2010, we have a liability accrued of $0.5 million for investigation at this site. The estimate is at the low
end of the range of potential liability because no amount within the range is considered to be more
likely than another and the high end of the range cannot reasonably be estimated.
Front Street site. The Front Street site was the former location of a gas manufacturing plant
we operated. It is near but outside the geographic scope of the current Portland Harbor site sediment
studies. The EPA directed the Lower Willamette Group to collect a series of surface and subsurface
sediment samples off the river bank adjacent to where that facility was located. Based on the results of
that sampling, the EPA notified the Lower Willamette Group that additional sampling would be
required. As the Front Street site is upstream from the Portland Harbor site, the EPA agreed that it
could be managed separately from the Portland Harbor site under ODEQ authority. Work plans for
source control investigation and a historical report were submitted to ODEQ and initial studies were
completed. In 2010, ODEQ required additional studies which are underway. As of December 31, 2010,
we have an estimated liability accrued of $1.1 million for the study of the sediments and riverbank
126
groundwater and soils at the site. The estimate is at the low end of the range of potential liability
because no amount within the range is considered to be more likely than another and the high end of
the range cannot reasonably be estimated.
Oregon Steel Mills site. See “Legal Proceedings,” below.
Accrued Liabilities Relating to Environmental Sites. The following table summarizes the
accrued liabilities relating to environmental sites at December 31, 2010 and 2009:
Thousands
Gasco site
Siltronic site
Portland Harbor site
Central Service Center site
Front Street site
Other sites
Total
Current Liabilities
Dec. 31,
2010
$11,366
720
2,304
5
1
-
Dec. 31,
2009
$ 9,841
653
2,114
5
72
-
Non-Current Liabilities
Dec. 31,
Dec. 31,
2009
2010
$43,659
$38,921
593
201
7,272
5,784
511
510
436
1,097
123
108
$14,396
$12,685
$46,621
$52,594
Regulatory and Insurance Recovery for Environmental Costs. In May 2003, the OPUC
approved our request to defer unreimbursed environmental costs associated with certain named sites,
including those described above. Beginning in 2006, the OPUC granted us additional authorization to
accrue interest on deferred environmental cost balances, subject to an annual demonstration that we
have maximized our insurance recovery or made substantial progress in securing insurance recovery
for unrecovered environmental expenses. Through a series of extensions, the authorized cost deferral
and interest accrual was extended through January 2010. We have filed a request with the OPUC to
extend this deferral, and expect authorization during the first quarter of 2011.
On a cumulative basis, we have recognized a total of $105.2 million for environmental costs,
including legal, investigation, monitoring and remediation costs, including $4.9 million accrued and
paid prior to regulatory deferral order approval. At December 31, 2010, we had a regulatory asset of
$114.3 million, which includes $44.7 million of total paid expenditures to date, $61.0 million for
additional environmental costs expected to be paid in the future and accrued interest of $14 million,
partially offset by $5.4 million of environmental costs expensed in prior years. See table below.
In December 2010, NW Natural commenced litigation against certain of its historical liability
insurers in Multnomah County Circuit Court, State of Oregon, Case Number 1012-17532. The
defendants include Associated Electric & Gas Insurance Services Limited, Allianz Global Risk US
Insurance Company, certain underwriters at Lloyd’s London, certain London market insurance
companies and ten other insurance companies. In the suit, NW Natural alleges that the defendant
insurance companies issued third party liability insurance policies to NW Natural and that the
defendants have breached the terms of those policies by failing to indemnify NW Natural for liabilities
arising from environmental contamination at certain sites caused or alleged to be caused by its
historical operations. NW Natural seeks damages in excess of $40 million in losses it has incurred to
date, as well as declaratory relief for additional losses it expects to incur in the future. After seeking
recovery of our environmental costs from our insurers, we believe recovery of the remainder of our
deferred charges, if any, is probable through the regulatory process. Our regulatory asset will be
reduced by the amount of any corresponding insurance recoveries. We continue to anticipate that our
overall insurance recovery effort will extend over several years.
127
We anticipate that our regulatory recovery of environmental cost deferrals will not be initiated
within the next 12 months because we do not expect to have completed our insurance recovery efforts
during that time period. As such we have classified our regulatory assets for environmental cost
deferrals as non-current. The following table summarizes the non-current regulatory assets relating to
environmental sites at December 31, 2010 and 2009:
Thousands
Gasco site
Siltronic site
Portland Harbor site
Central Service Center site
Front Street site
Other sites
Total
Legal Proceedings
Non-Current Regulatory Assets
2010
$ 74,205
3,174
33,940
553
2,020
420
$114,312
2009
$ 69,607
2,974
31,500
550
910
507
$106,048
We are subject to claims and litigation arising in the ordinary course of business. Although the
final outcome of any of these legal proceedings cannot be predicted with certainty, including the matter
described below, we do not expect that the ultimate disposition of any of these matters will have a
material effect on our financial condition, results of operations or cash flows.
Oregon Steel Mills site. In 2004, NW Natural was served with a third-party complaint by the
Port of Portland (Port) in a Multnomah County Circuit Court case, Oregon Steel Mills, Inc. v. The Port
of Portland. The Port alleges that in the 1940s and 1950s petroleum wastes generated by our
predecessor, Portland Gas & Coke Company, and 10 other third-party defendants were disposed of in a
waste oil disposal facility operated by the United States or Shaver Transportation Company on
property then owned by the Port and now owned by Oregon Steel Mills. The complaint seeks
contribution for unspecified past remedial action costs incurred by the Port regarding the former waste
oil disposal facility as well as a declaratory judgment allocating liability for future remedial action
costs. No date has been set for trial and discovery is ongoing. Although the final outcome of this
proceeding cannot be predicted with certainty, we do not expect that the ultimate disposition of this
matter will have a material effect on our financial condition, results of operations or cash flows.
16.
Subsequent Event
On February 24, 2011, we signed an agreement to participate in a joint venture to develop gas
reserves to secure a long-term gas supply for our utility customers over a 30-year period (Gas Reserves
Joint Venture). During the first 10 year period, we expect the volume of gas produced to provide
approximately 8 percent to 10 percent of the average annual requirements for our utility customers.
Under the agreement, we will pay approximately $45 million to $55 million a year over a five year
period. Our total investment is expected to be about $250 million. Under the agreement, we will be
assigned a working interest in leases to certain sections of the gas field; the sections include both future
and currently producing wells. Operation of the wells and the leases are governed by a joint operating
agreement under which we will pay our proportionate share of operating costs to the operator of the
field. The Gas Reserves Joint Venture is subject to OPUC approval. If approved by the OPUC, we
expect it would provide a regulated rate of return on our net investment.
128
NORTHWEST NATURAL GAS COMPANY
QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
Thousands, except per share amounts
2010
Operating revenues
Net operating revenues
Net income (loss)
Basic earnings (loss) per share
Diluted earnings (loss) per share
2009
Operating revenues
Net operating revenues
Net income (loss)
Basic earnings (loss) per share
Diluted earnings (loss) per share
Quarter ended
March 31
June 30
Sept. 30
Dec. 31
Total
$286,529
130,926
43,608
1.64
1.64
$162,365
72,193
6,888
0.26
0.26
$ 95,067 $268,145
118,251
29,591
1.11
1.11
46,211
(7,420)
(0.28)
(0.28)
$ 812,106
367,581
72,667
2.73(1)
2.73(1)
$437,355
142,639
47,363
1.79
1.78
$149,060
65,919
3,086
0.12
0.12
$116,854
48,626
(6,733)
(0.25)
(0.25)
$309,442
119,703
31,406
1.19
1.18
$1,012,711
376,887
75,122
2.83(1)
2.83(1)
(1)
Quarterly earnings (loss) per share are based upon the average number of common shares outstanding
during each quarter. Because the average number of shares outstanding has changed in each quarter
shown, the sum of quarterly earnings (loss) per share may not equal earnings per share for the year.
Variations in earnings between quarterly periods are due primarily to the seasonal nature of our business.
129
NORTHWEST NATURAL GAS COMPANY
SCHEDULE II – VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
COLUMN A
COLUMN B
Balance at
beginning
of
period
Thousands (year ended Dec. 31)
2010
Reserves deducted in balance sheet from
assets to which they apply:
COLUMN C
Additions
COLUMN D COLUMN E
Deductions
Charged to
costs
and expenses
Charged to
other
accounts
Net
Write-offs
Balance
at end
of
period
Allowance for uncollectible accounts
$3,125
$1,717
$-
$1,892
$2,950
2009
Reserves deducted in balance sheet from
assets to which they apply:
Allowance for uncollectible accounts
$2,927
$4,201
$-
$4,003
$3,125
2008
Reserves deducted in balance sheet from
assets to which they apply:
Allowance for uncollectible accounts
$2,890
$3,145
$-
$3,108
$2,927
130
Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING
AND FINANCIAL DISCLOSURE
None.
Item 9A.CONTROLS AND PROCEDURES
(a) Evaluation of Disclosure Controls and Procedures
Our management, under the supervision and with the participation of our Chief Executive Officer and
Chief Financial Officer, has completed an evaluation of the effectiveness of the design and operation of
our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Securities
Exchange Act of 1934, as amended (the “Exchange Act”)). Based upon this evaluation, our Chief
Executive Officer and Chief Financial Officer have concluded that, as of the end of the period covered
by this report, our disclosure controls and procedures were effective to ensure that information required
to be disclosed by us and included in our reports filed or submitted under the Exchange Act is
recorded, processed, summarized and reported within the time periods specified in the Securities and
Exchange Commission rules and forms and that such information is accumulated and communicated to
management, including the Chief Executive Officer and Chief Financial Officer, as appropriate to
allow timely decisions regarding required disclosure.
(b) Changes in Internal Control Over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over
financial reporting, as such term is defined in the Exchange Act Rule 13a-15(f).
There have been no changes in our internal control over financial reporting that occurred during the
quarter ended December 31, 2010 that have materially affected, or are reasonably likely to materially
affect, our internal control over financial reporting. The statements contained in Exhibit 31.1 and
Exhibit 31.2 should be considered in light of, and read together with, the information set forth in this
Item 9(a).
Item 9B. OTHER INFORMATION
None.
131
PART III
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Information concerning our Board of Directors, its Committees and the Audit Committee
financial expert contained in NW Natural’s definitive Proxy Statement for the May 26, 2011 Annual
Meeting of Shareholders is hereby incorporated by reference. The information concerning “Section
16(a) Beneficial Ownership Reporting Compliance” and “Corporate Governance” contained in our
definitive Proxy Statement for the May 26, 2011 Annual Meeting of Shareholders is hereby
incorporated by reference.
Name
Dec. 31, 2010 Positions held during last five years
Age at
Gregg S. Kantor
David H. Anderson
Margaret D. Kirkpatrick
Lea Anne Doolittle
J. Keith White
David R. Williams
Grant M. Yoshihara
C. Alex Miller
Stephen P. Feltz
MardiLyn Saathoff
53
49
56
55
57
57
55
53
55
54
President and Chief Executive Officer (2009-
); President and Chief
Operating Officer (2007 - 2008); Executive Vice President (2006 -
2007); Senior Vice President, Public and Regulatory Affairs (2003-
2006).
Senior Vice President and Chief Financial Officer (2004-
).
Vice President and General Counsel (2005- ); Partner in the law firm
of Stoel Rives LLP (1991- 2005).
Senior Vice President (2008-
); Vice President, Human Resources
(2000-2007).
Vice President, Business Development and Energy Supply/Chief
Strategic Officer (2007-
and Wholesale Services (2005-2006); Managing Director and Chief
Strategic Officer (2003-2005).
); Managing Director, Gas Operations
Vice President, Utility Services (2007-
); Director of Utility
Operations, Districts and managed Labor Relations (2004-2006).
Vice President, Utility Operations (2007-
); Managing Director,
Utility Services (2005-2006); Director, Utility Services (2004-
2005).
Vice President, Finance and Regulation (2009-
); Assistant
Treasurer (2008-
Affairs (2002-2009).
); General Manager of Rates and Regulatory
Assistant Secretary (2007-
); Treasurer and Controller (1999-
).
); Chief Governance Officer and
Deputy General Counsel (2010-
Corporate Secretary (2008-
Assistant General Counsel, Tektronix, Inc. (2005-2008); General
Counsel to Oregon Governor Kulongoski and Business and
Economic Development Advisor (2003-2005).
); Chief Compliance Officer and
Each executive officer serves successive annual terms; present terms end on May 26, 2011.
There are no family relationships among our executive officers, directors or any person chosen to
become one of our officers or directors.
NW Natural has adopted a Code of Ethics (Code) applicable to all employees and officers, and
a Financial Code of Ethics that applies to senior financial employees, both of which are available on
our website at www.nwnatural.com. We intend to disclose on our website at www.nwnatural.com any
amendments to the Code or waivers of the Code for executive officers.
132
ITEM 11. EXECUTIVE COMPENSATION
The information concerning “Executive Compensation” and “Report of the Organization and
Executive Compensation Committee” contained in our definitive Proxy Statement for the May 26,
2011 Annual Meeting of Shareholders is hereby incorporated by reference. Information related to
Executive Officers as of December 31, 2010 is reflected in Part III, Item 10, above.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT AND RELATED STOCKHOLDER MATTERS
The following table sets forth information regarding compensation plans under which equity
securities of NW Natural are authorized for issuance as of December 31, 2010 (see Note 6 to the
Consolidated Financial Statements):
(a)
(b)
Number of securities
to be issued upon
exercise of
outstanding options,
warrants and rights
Weighted-average
exercise price of
outstanding options,
warrants and rights
(c)
Number of securities
remaining available for
future issuance under
equity compensation
plans (excluding
securities reflected in
column (a))
82,500
490,460
18,936
4,635
66,027
108,360
770,918
n/a
$40.82
$41.90
n/a
n/a
n/a
270,204
693,600
152,323
n/a
n/a
n/a
1,116,127
Plan Category
Equity compensation plans approved by
security holders:
Long-Term Incentive Plan (LTIP) (Target
Award) (1)
Restated Stock Option Plan
Employee Stock Purchase Plan
Equity compensation plans not approved by
security holders:
Executive Deferred Compensation Plan
(EDCP) (2)
Directors Deferred Compensation Plan
(DDCP) (2)
Deferred Compensation Plan for
Directors and Executives (DCP) (3)
Total
The information captioned “Beneficial Ownership of Common Stock by Directors and
Executive Officers” contained in our definitive Proxy Statement for the May 26, 2011 Annual Meeting
of Shareholders is incorporated herein by reference.
(1)
(2)
Shares issued pursuant to the LTIP do not include an exercise price, but are payable when the award criteria
are satisfied. If the maximum awards were paid pursuant to the performance-based awards outstanding at
December 31, 2010, the number of shares shown in column (a) would increase by 82,500 shares and the
number of shares shown in column (c) would decrease by 165,000 shares.
Prior to January 1, 2005, deferred amounts were credited, at the participant’s election, to either a “cash
account” or a “stock account.” If deferred amounts were credited to stock accounts, such accounts were
credited with a number of shares of NW Natural common stock based on the purchase price of the common
stock on the next purchase date under our Dividend Reinvestment and Direct Stock Purchase Plan, and such
accounts were credited with additional shares based on the deemed reinvestment of dividends. Cash
133
(3)
accounts are credited quarterly with interest at a rate equal to Moody’s Average Corporate Bond Yield plus
two percentage points, subject to a six percent minimum rate. At the election of the participant, deferred
balances in the stock accounts are payable after termination of Board service or employment in a lump sum,
in installments over a period not to exceed 10 years in the case of the DDCP, or 15 years in the case of the
EDCP, or in a combination of lump sum and installments. We have contributed common stock to the trustee
of the Umbrella Trusts such that the Umbrella Trusts hold approximately the number of shares of common
stock equal to the number of shares credited to all participants’ stock accounts.
Effective January 1, 2005, the EDCP and DDCP were replaced by the DCP. The DCP continues the basic
provisions of the EDCP and DDCP under which deferred amounts are credited to either a “cash account” or
a “stock account.” Stock accounts represent a right to receive shares of NW Natural common stock on a
deferred basis, and such accounts are credited with additional shares based on the deemed reinvestment of
dividends. Effective January 1, 2007, cash accounts are credited quarterly with interest at a rate equal to
Moody’s Average Corporate Bond Yield. Our obligation to pay deferred compensation in accordance with
the terms of the DCP will generally become due on retirement, death, or other termination of service, and
will be paid in a lump sum or in installments of five or 10 years as elected by the participant in accordance
with the terms of the DCP. We have contributed common stock to the trustee of the Supplemental Trust
such that this trust holds approximately the number of common shares equal to the number of shares
credited to all participants stock accounts. The right of each participant in the DCP is that of a general,
unsecured creditor of the Company.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR
INDEPENDENCE
The information captioned “Transactions with Related Persons” and “Corporate Governance”
in the Company’s definitive Proxy Statement for the May 26, 2011 Annual Meeting of Shareholders is
hereby incorporated by reference.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
The information captioned “2010 and 2009 Audit Firm Fees” in the Company’s definitive
Proxy Statement for the May 26, 2011 Annual Meeting of Shareholders is hereby incorporated by
reference.
134
PART IV
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
(a) The following documents are filed as part of this report:
1. A list of all Financial Statements and Supplemental Schedules is incorporated by
reference to Item 8.
2.
List of Exhibits filed:
Reference is made to the Exhibit Index commencing on page 137.
135
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly
authorized.
SIGNATURES
Date: February 25, 2011
NORTHWEST NATURAL GAS COMPANY
By:
/s/ Gregg S. Kantor
Gregg S. Kantor
President and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed
below by the following persons on behalf of the registrant and in the capacities and on the date indicated.
SIGNATURE
/s/ Gregg S. Kantor
President and Chief Executive Officer
/s/ David H. Anderson
David H. Anderson
Senior Vice President
and Chief Financial Officer
/s/ Stephen P. Feltz
Stephen P. Feltz
Treasurer and Controller
/s/ Timothy P. Boyle
Timothy P. Boyle
/s/ Martha L. Byorum
Martha L. Byorum
/s/ John D. Carter
John D. Carter
/s/ Mark S. Dodson
Mark S. Dodson
/s/ C. Scott Gibson
C. Scott Gibson
/s/ Tod R. Hamachek
Tod R. Hamachek
/s/ Jane L. Peverett
Jane L. Peverett
/s/ George J. Puentes
George J. Puentes
/s/ Kenneth Thrasher
Kenneth Thrasher
/s/ Russell F. Tromley
Russell F. Tromley
Principal Executive Officer and Director
February 25, 2011
TITLE
DATE
Principal Financial Officer
February 25, 2011
Principal Accounting Officer
February 25, 2011
Director
Director
Director
Director
Director
Director
Director
Director
Director
Director
136
)
)
)
)
)
)
)
)
)
)
)
)
)
)
)
)
)
)
)
)
)
)
)
)
)
)
)
)
)
February 25, 2011
NORTHWEST NATURAL GAS COMPANY
EXHIBIT INDEX
To
Annual Report on Form 10-K
For Fiscal Year Ended
December 31, 2010
Exhibit Number
Document
*3a.
*3b.
*4a.
*4b.
*4c.
*4d.
Restated Articles of Incorporation, as filed and effective May 31, 2006 and
amended June 3, 2008 (incorporated herein by reference to Exhibit 3a. to
Form 10-K for 2006, File No. 1-15973).
Bylaws as amended May 24, 2007 (incorporated herein by reference to
Exhibit 3.1 to Form 8-K dated May 29, 2007, File No. 1-15973).
Copy of Mortgage and Deed of Trust, dated as of July 1, 1946, to Bankers
Trust and R. G. Page (to whom Stanley Burg is now successor), Trustees
(incorporated herein by reference to Exhibit 7(j) in File No. 2-6494); and
copies of Supplemental Indentures Nos. 1 through 14 to the Mortgage and
Deed of Trust, dated respectively, as of June 1, 1949, March 1, 1954,
April 1, 1956, February 1, 1959, July 1, 1961, January 1, 1964, March 1,
1966, December 1, 1969, April 1, 1971, January 1, 1975, December 1, 1975,
July 1, 1981, June 1, 1985 and November 1, 1985 (incorporated herein by
reference to Exhibit 4(d) in File No. 33-1929); Supplemental Indenture
No. 15 to the Mortgage and Deed of Trust, dated as of July 1, 1986 (filed as
Exhibit 4(c) in File No. 33-24168); Supplemental Indentures Nos. 16, 17
and 18 to the Mortgage and Deed of Trust, dated, respectively, as of
November 1, 1988, October 1, 1989 and July 1, 1990 (incorporated herein
by reference to Exhibit 4(c) in File No. 33-40482); Supplemental Indenture
No. 19 to the Mortgage and Deed of Trust, dated as of June 1, 1991
(incorporated herein by reference to Exhibit 4(c) in File No. 33-64014); and
Supplemental Indenture No. 20 to the Mortgage and Deed of Trust, dated as
of June 1, 1993 (incorporated herein by reference to Exhibit 4(c) in File
No. 33-53795).
Copy of Indenture, dated as of June 1, 1991, between the Company and
Bankers Trust Company, Trustee, relating to the Company’s Unsecured
Medium-Term Notes (incorporated herein by reference to Exhibit 4(e) in
File No. 33-64014).
Officers’ Certificate dated June 12, 1991 creating Series A of the
Company’s Unsecured Medium-Term Notes (incorporated herein by
reference to Exhibit 4e. to Form 10-K for 1993, File No. 0-994).
Officers’ Certificate dated June 18, 1993 creating Series B of the
Company’s Unsecured Medium-Term Notes (incorporated herein by
reference to Exhibit 4f. to Form 10-K for 1993, File No. 0-994).
137
*4e.
*4f.
*4g.
*4h.
*4i.
*4j.
*4k.
*4l.
*10a.(1)
*10a.(2)
Officers’ Certificate dated January 17, 2003 relating to Series B of the
Company’s Unsecured Medium-Term Notes and supplementing the
Officers’ Certificate dated June 18, 1993 (incorporated herein by reference
to Exhibit 4f.(1) to Form 10-K for 2002, File No. 0-994).
Form of Credit Agreement between Northwest Natural Gas Company and
the banks that are party thereto, with JPMorgan Chase Bank, N.A., as
administrative agent and Bank of America, N.A., as syndication agent, dated
as of May 31, 2007, including Form of Note (incorporated herein by
reference to Exhibit 4 to Form 10-Q dated November 5, 2010, File
No. 1-15973).
Form of Letter Agreement, between each of JPMorgan Chase Bank, N.A.,
Bank of America, N.A., U.S. Bank National Association, UBS Loan
Finance LLC, Wells Fargo Bank, N.A., Merrill Lynch Bank USA, dated as
of April 29, 2008, extending the Credit Agreement between Northwest
Natural Gas Company and each financial institution with JPMorgan Chase
Bank, N.A., as Administrative Agent (incorporated herein by reference to
Exhibit 4i.(1) to Form 10-K for 2008, File No. 1-15973).
Form of Secured Medium-Term Notes, Series B (incorporated herein by
reference to Exhibit 4.1 to Form 8-K dated October 4, 2004, File
No. 1-15973).
Letter Agreement among the Company, JPMorgan Chase Bank, N.A., Bank
of America, N.A., U.S. Bank National Association, Wachovia Bank,
National Association, Wells Fargo Bank, N.A., Bank of America, N.A.,
Successor by merger to Merrill Lynch Bank USA, and UBS Loan Finance
LLC, dated October 29, 2009 (incorporated herein by reference to
Exhibit 4i. to Form 10-K for 2009, File No. 1-15973).
Distribution Agreement, dated March 18, 2009, among Banc of America
Securities LLC, UBS Securities LLC, J.P. Morgan Securities Inc., and Piper
Jaffray and Co. (Incorporated herein by reference to Exhibit 1.1 to
Form 8-K dated March 23, 2009, File No. 1-15973).
Form of Letter Agreement, dated August 24, 2009, among Banc of America
Securities, LLC, UBS Securities LLC, J.P. Morgan Securities Inc., Piper
Jaffray & Co. and Wells Fargo Securities, LLC (incorporated herein by
reference to Exhibit 4k. to Form 10-K for 2009, File No. 1-15973).
Form of Unsecured Medium-Term Notes, Series B (incorporated herein by
reference to Exhibit 4.2 to Form 8-K dated October 4, 2004, File
No. 1-15973).
Replacement Firm Transportation Agreement, dated July 31, 1991, between
the Company and Northwest Pipeline GP (incorporated herein by reference
to Exhibit 10j.(2) to Form 10-K for 1992, File No. 0-994).
Firm Transportation Service Agreement, dated November 10, 1993,
between the Company and Pacific Gas Transmission Company
(incorporated herein by reference to Exhibit 10j.(2) to Form 10-K for 1993,
File No. 0-994).
138
*10a.(3)
*10a.(4)
*10a.(5)
*10a.(6)
*10a.(7)
*10a.(8)
*10a.(9)
*10a.(10)
*10a.(11)
*10a.(12)
*10a.(13)
*10a.(14)
*10a.(15)
*10a.(16)
Service Agreement, dated June 17, 1993, between Northwest Pipeline GP
and the Company (incorporated herein by reference to Exhibit 10j.(3) to
Form 10-K for 1994, File No. 0-994).
Firm Transportation Service Agreement, dated June 22, 1994, between
Pacific Gas Transmission Company and the Company (incorporated herein
by reference to Exhibit 10j.(5) to Form 10-K for 1995, File No. 0-994).
Firm Service Agreement between the Company and Westcoast Energy Inc.,
dated as of April 1, 2003 (incorporated herein by reference to Exhibit 10 to
Form 10-Q for quarter ended March 31, 2003, File No. 001-15973).
Service Agreement Amendment, dated February 12, 2008, between the
Company and Northwest Pipeline GP (incorporated herein by reference to
Exhibit 10j.(7) to Form 10-K for 2007, File No. 1-15973).
Service Agreement, dated February 8, 2008, between the Company and
Northwest Pipeline GP (incorporated herein by reference to Exhibit 10j.(8)
to Form 10-K for 2007, File No. 1-15973).
Agreement between the Company and March Point Cogeneration Company,
dated February 8, 2008 (incorporated herein by reference to Exhibit 10j.(9)
to Form 10-K for 2007, File No. 1-15973).
Firm Transportation Service Agreement, dated October 22, 1993, between
the Company and Pacific Gas Transmission Company (incorporated herein
by reference to Exhibit 10j.(10) to Form 10-K for 2008, File No. 1-15973).
Service Agreement (100310), dated January 21, 2008, between the
Company and Northwest Pipeline GP (incorporated herein by reference to
Exhibit 10j.(11) to Form 10-K for 2008, File No. 1-15973).
Service Agreement, dated January 21, 2008, between the Company and
Northwest Pipeline GP (incorporated herein by reference to Exhibit 10j.(12)
to Form 10-K for 2008, File No. 1-15973).
Service Agreement (Gas Storage Service), dated January 12, 1994, between
the Company and Northwest Pipeline Corporation (incorporated herein by
reference to Exhibit 10j.(13) to Form 10-K for 2008, File No. 1-15973).
Service Agreement (100309), dated January 21, 2008, between the
Company and Northwest Pipeline GP (incorporated herein by reference to
Exhibit 10j.(14) to Form 10-K for 2008, File No. 1-15973).
Service Agreement (100308), dated January 12, 1994, between the
Company and Northwest Pipeline GP (incorporated herein by reference to
Exhibit 10j.(15) to Form 10-K for 2008, File No. 1-15973).
Service Agreement, dated January 20, 1995, between the Company and
NOVA Gas Transmission Ltd (incorporated herein by reference to Exhibit
10j.(16) to Form 10-K for 2008, File No. 1-15973).
Service Agreement, dated November 1, 2004, between the Company and
TransCanada PipeLines Limited (incorporated herein by reference to
Exhibit 10j.(17) to Form 10-K for 2008, File No. 1-15973).
139
*10a.(17)
*10a.(18)
12
21
23
31.1
31.2
32.1
Service Agreement, dated October 24, 2008, between Foothills Pipe Lines
Ltd. and the Company (incorporated herein by reference to Exhibit 10j.(18)
to Form 10-K for 2008, File No. 1-15973).
Amendment and Restatement of Firm Transportation Service Agreement,
dated November 1, 2004, between Terasen Gas Inc. and the Company
(incorporated herein by reference to Exhibit 10j.(19) to Form 10-K for 2008,
File No. 1-15973).
Statement re computation of ratios of earnings to fixed charges.
Subsidiaries of Northwest Natural Gas Company
Consent of PricewaterhouseCoopers LLP.
Certification of Principal Executive Officer Pursuant to Rule
13a-14(a)/15-d-14(a), Section 302 of the Sarbanes-Oxley Act of 2002.
Certification of Principal Financial Officer Pursuant to Rule
13a-14(a)/15-d-14(a), Section 302 of the Sarbanes-Oxley Act of 2002.
Certification of Principal Executive Officer and Principal Financial Officer
Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
Executive Compensation Plans and Arrangements:
*10b.
*10c.
*10d.
*10e.
*10f.
*10g.
*10h.
*10i.
Executive Supplemental Retirement Income Plan 2010 Restatement
(incorporated herein by reference to Exhibit 10b. to Form 10-K for 2009,
File No. 1-15973).
Supplemental Executive Retirement Plan, effective September 1, 2004
restated 2010 (incorporated herein by reference to Exhibit 10c. to
Form 10-K for 2009, File No. 1-15973).
Northwest Natural Gas Company Supplemental Trust, effective January 1,
2005, restated as of December 15, 2005 (incorporated herein by reference to
Exhibit 10.7 to Form 8-K dated December 16, 2005, File No. 1-15973).
Northwest Natural Gas Company Umbrella Trust for Directors, effective
January 1, 1991, restated as of December 15, 2005 (incorporated herein by
reference to Exhibit 10.5 to Form 8-K dated December 16, 2005,
File No. 1-15973).
Northwest Natural Gas Company Umbrella Trust for Executives, effective
January 1, 1988, restated as of December 15, 2005 (incorporated herein by
reference to Exhibit 10.6 to Form 8-K dated December 16, 2005,
File No. 1-15973).
Restated Stock Option Plan, as amended effective December 14, 2006
(incorporated herein by reference to Exhibit 10c. to Form 10-K for 2006,
File No. 1-15973).
Form of Restated Stock Option Plan Agreement (incorporated herein by
reference to Exhibit 10h. to Form 10-K for 2009, File No. 1-15973).
Executive Deferred Compensation Plan, effective as of January 1, 1987,
restated as of February 26, 2009 (incorporated herein by reference to Exhibit
10(e). to Form 10-K for 2008, File No. 1-15973).
140
*10j.
*10k.
*10l.
*10l.(1)
*10m.
*10n.
*10o.
*10p.
*10q.
*10r.
10s.
*10t.
*10u.
*10v.
Directors Deferred Compensation Plan, effective June 1, 1981, restated as of
February 26, 2009 (incorporated herein by reference to Exhibit 10(f). to
Form 10-K for 2008, File No. 1-15973).
Deferred Compensation Plan for Directors and Executives effective
January 1, 2005, restated as of January 1, 2010 (incorporated herein by
reference to Exhibit 10k. to Form 10-K for 2009, File No. 1-15973).
Form of Indemnity Agreement as entered into between the Company and
each director and certain executive officers (incorporated herein by
reference to Exhibit 10l. to Form 10-K for 2009, File No. 1-15973).
Form of Indemnity Agreement as entered into between the Company and
certain executive officers (incorporated herein by reference to
Exhibit 10l.(1) to Form 10-K for 2009, File No. 1-15973).
Non-Employee Directors Stock Compensation Plan, as amended effective
December 15, 2005 (incorporated herein by reference to Exhibit 10.2 to
Form 8-K dated December 16, 2005, File No. 1-15973).
Executive Annual Incentive Plan, effective February 25, 2010 (incorporated
herein by reference to Exhibit 10n. to Form 10-K for 2009, File
No. 1-15973).
Form of Agreement to Recoupment Provisions of Executive Annual
Incentive Plan, effective as of January 1, 2010 (incorporated herein by
reference to Exhibit 10o. to Form 10-K for 2009, File No. 1-15973).
Form of Change in Control Severance Agreement between the Company
and each executive officer (incorporated herein by reference to Exhibit 10o.
to Form 10-K for 2008, File No. 1-15973).
Severance agreement dated December 19, 2008 between the Company and
Gregg S. Kantor (incorporated herein by reference to Exhibit 10.1 to
Form 8-K dated December 23, 2008, File No. 1-15973).
Northwest Natural Gas Company Long-Term Incentive Plan, as amended
and restated effective July 26, 2001 (incorporated herein by reference to
Exhibit 10(c) to Form 10-Q for the quarter ended June 30, 2001, File
No. 1-15973).
Form of Long-Term Incentive Award Agreement under the Long-Term
Incentive Plan.
Form of Long-Term Incentive Award Agreement under the Long-Term
Incentive Plan (incorporated herein by reference to Exhibit 10.1 to
Form 8-K dated February 21, 2007, File No. 1-15973).
Form of Long-Term Incentive Award Agreement under the Long-Term
Incentive Plan (incorporated herein by reference to Exhibit 10w.(2) to
Form 10-K for 2007, File No. 1-15973).
Form of Restricted Stock Bonus Agreement under the Long-Term Incentive
Plan (incorporated herein by reference to Exhibit 10.9 to Form 8-K dated
December 16, 2005, File No. 1-15973).
141
*10w.
*10x.
*10y.
*10z.
Restricted Stock Bonus Agreement with an executive officer dated July 26,
2006 (incorporated by reference to Exhibit 10.1 to Form 8-K dated July 28,
2006, File No. 1-15973).
Form of Consent dated December 14, 2006 entered into by each executive
officer (incorporated herein by reference to Exhibit 10.1 to Form 8-K dated
December 19, 2006, File No. 1-15973).
Consent to Amendment of Deferred Compensation Plan for Directors and
Executives, dated February 28, 2008 entered into by each executive officer
(incorporated herein by reference to Exhibit 10bb to Form 10-K for 2007,
File No. 1-15973).
Form of Long-Term Incentive Award Agreement under the Long-Term
Incentive Plan relating to a special award to an executive officer
(incorporated herein by reference to Exhibit 10z. to Form 10-K for 2009,
File No. 1-15973).
10z.(1)
Separation Agreement with an executive officer dated January 7, 2011.
* Incorporated herein by reference as indicated
142
NORTHWEST NATURAL GAS COMPANY
Ratio of Earnings to Fixed Charges
Thousands, except per share amount
(Unaudited)
EXHIBIT 12
Year Ended December 31,
2010
2009
2008
2007
2006
Fixed Charges, as defined:
Interest on Long-Term Debt . . . . . . . . . . . . . . . . .
Other Interest
. . . . . . . . . . . . . . . . . . . . . . . . . . . .
Amortization of Debt Discount and Expense . . . .
Interest Portion of Rentals . . . . . . . . . . . . . . . . . .
$ 39,198
1,587
1,766
2,130
$ 37,447
1,937
1,503
1,735
$ 33,605
4,022
700
1,551
$ 34,294
4,116
711
1,523
$ 34,651
4,648
716
1,465
Total Fixed Charges, as defined . . . . . . . . . . . . . .
$ 44,681
$ 42,622
$ 39,878
$ 40,644
$ 41,480
Earnings, as defined:
Net Income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Taxes on Income . . . . . . . . . . . . . . . . . . . . . . . . .
Fixed Charges, as above . . . . . . . . . . . . . . . . . . . .
$ 72,667
49,462
44,681
$ 75,122
46,671
42,622
$ 69,525
40,678
39,878
$ 74,497
44,060
40,644
$ 63,415
36,234
41,480
Total Earnings, as defined . . . . . . . . . . . . . . . . . .
$166,810
$164,415
$150,081
$159,201
$141,129
Ratio of Earnings to Fixed Charges . . . . . . . . . . . . . . .
3.73
3.86
3.76
3.92
3.40
Consent of Independent Registered Public Accounting Firm
EXHIBIT 23
We hereby consent to the incorporation by reference in the Registration Statements on Form S-8
(Nos. 333-70218, 333-100885, 333-120955, 333-134973 and 333-139819) and in the Registration
Statement on Form S-3 (No. 333-171596) of Northwest Natural Gas Company of our report dated
February 25, 2011 relating to the consolidated financial statements, financial statement schedule and
the effectiveness of internal control over financial reporting, which appears in this Form 10-K.
/s/ PricewaterhouseCoopers LLP
Portland, Oregon
February 25, 2011
I, Gregg S. Kantor, certify that:
CERTIFICATION
EXHIBIT 31.1
1.
I have reviewed this annual report on Form 10-K of Northwest Natural Gas Company;
2. Based on my knowledge, this report does not contain any untrue statement of a material fact or
omit to state a material fact necessary to make the statements made, in light of the circumstances
under which such statements were made, not misleading with respect to the period covered by this
report;
3. Based on my knowledge, the financial statements, and other financial information included in this
report, fairly present in all material respects the financial condition, results of operations and cash
flows of the registrant as of, and for, the periods presented in this report;
4.
The registrant’s other certifying officer and I are responsible for establishing and maintaining
disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e))
and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and
15d-15(f)) for the registrant and have:
(a) Designed such disclosure controls and procedures, or caused such disclosure controls and
procedures to be designed under our supervision, to ensure that material information relating
to the registrant, including its consolidated subsidiaries, is made known to us by others within
those entities, particularly during the period in which this report is being prepared;
(b) Designed such internal control over financial reporting, or caused such internal control over
financial reporting to be designed under our supervision, to provide reasonable assurance
regarding the reliability of financial reporting and the preparation of financial statements for
external purposes in accordance with generally accepted accounting principles;
(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and
presented in this report our conclusions about the effectiveness of the disclosure controls and
procedures, as of the end of the period covered by this report based on such evaluation; and
(d) Disclosed in this report any change in the registrant’s internal control over financial reporting
that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal
quarter in the case of an annual report) that has materially affected, or is reasonably likely to
materially affect, the registrant’s internal control over financial reporting; and
5.
The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation
of internal control over financial reporting, to the registrant’s auditors and the audit committee of
the registrant’s board of directors (or persons performing the equivalent functions):
(a) All significant deficiencies and material weaknesses in the design or operation of internal
control over financial reporting which are reasonably likely to adversely affect the
registrant’s ability to record, process, summarize and report financial information; and
(b) Any fraud, whether or not material, that involves management or other employees who have
a significant role in the registrant’s internal control over financial reporting.
Date: February 25, 2011
/s/ Gregg S. Kantor
Gregg S. Kantor
President and Chief Executive Officer
I, David H. Anderson, certify that:
CERTIFICATION
EXHIBIT 31.2
1.
I have reviewed this annual report on Form 10-K of Northwest Natural Gas Company;
2. Based on my knowledge, this report does not contain any untrue statement of a material fact or
omit to state a material fact necessary to make the statements made, in light of the circumstances
under which such statements were made, not misleading with respect to the period covered by this
report;
3. Based on my knowledge, the financial statements, and other financial information included in this
report, fairly present in all material respects the financial condition, results of operations and cash
flows of the registrant as of, and for, the periods presented in this report;
4.
The registrant’s other certifying officer and I are responsible for establishing and maintaining
disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e))
and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and
15d-15(f)) for the registrant and have:
(a) Designed such disclosure controls and procedures, or caused such disclosure controls and
procedures to be designed under our supervision, to ensure that material information relating
to the registrant, including its consolidated subsidiaries, is made known to us by others within
those entities, particularly during the period in which this report is being prepared;
(b) Designed such internal control over financial reporting, or caused such internal control over
financial reporting to be designed under our supervision, to provide reasonable assurance
regarding the reliability of financial reporting and the preparation of financial statements for
external purposes in accordance with generally accepted accounting principles;
(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and
presented in this report our conclusions about the effectiveness of the disclosure controls and
procedures, as of the end of the period covered by this report based on such evaluation; and
(d) Disclosed in this report any change in the registrant’s internal control over financial reporting
that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal
quarter in the case of an annual report) that has materially affected, or is reasonably likely to
materially affect, the registrant’s internal control over financial reporting; and
5.
The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation
of internal control over financial reporting, to the registrant’s auditors and the audit committee of
the registrant’s board of directors (or persons performing the equivalent functions):
(a) All significant deficiencies and material weaknesses in the design or operation of internal
control over financial reporting which are reasonably likely to adversely affect the
registrant’s ability to record, process, summarize and report financial information; and
(b) Any fraud, whether or not material, that involves management or other employees who have
a significant role in the registrant’s internal control over financial reporting.
Date: February 25, 2011
/s/ David H. Anderson
David H. Anderson
Senior Vice President and Chief Financial Officer
NORTHWEST NATURAL GAS COMPANY
Certificate Pursuant to Section 906
of Sarbanes – Oxley Act of 2002
EXHIBIT 32.1
Each of the undersigned, GREGG S. KANTOR, the President and Chief Executive Officer, and
DAVID H. ANDERSON, the Senior Vice President and Chief Financial Officer, of NORTHWEST
NATURAL GAS COMPANY (the Company), DOES HEREBY CERTIFY that:
1.
2.
The Company’s Annual Report on Form 10-K for the year ended December 31, 2010 (the Report)
fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of
1934, as amended; and
Information contained in the Report fairly presents, in all material respects, the financial condition
and results of operations of the Company.
IN WITNESS WHEREOF, each of the undersigned has caused this instrument to be executed
this 25th day of February 2011.
/s/ Gregg S. Kantor
Gregg S. Kantor
President and Chief Executive Officer
/s/ David H. Anderson
David H. Anderson
Senior Vice President and
Chief Financial Officer
A signed original of this written statement required by Section 906 of the Sarbanes-Oxley Act of 2002
has been provided to Northwest Natural Gas Company and will be retained by Northwest Natural Gas
Company and furnished to the Securities and Exchange Commission or its staff upon request.
Living our
MISSION & VALUES
NW Natural Community and Sustainability Report
Learn more about NW Natural’s community involvement and philanthropic
contributions, environmental stewardship efforts, pipeline integrity program,
and employee safety and wellness initiatives.
View the 2010 Community & Sustainability Report at
nwnatural.com/aboutnwnatural/community.
NW Natural Energy-Effi ciency Programs
NW Natural partners with Energy Trust of Oregon to offer our Oregon and
Washington customers energy-effi ciency programs and services. Learn more
about the results of these programs and the benefi ts to our customers.
View the Energy Trust of Oregon Annual Report at
nwnatural.com/aboutnwnatural/environmentalstewardship.
NW Natural Low-Income Weatherization Program
NW Natural offers a program to our low-income customers designed to
reduce their natural gas use through the installation of energy-effi cient
equipment and weatherization measures. Find out more about this
innovative Oregon program.
View the Low-Income Energy-Effi ciency Program Annual Report at
nwnatural.com/aboutnwnatural/environmentalstewardship.
Produced by NW Natural’s Corporate Communications
PHOTO CREDITS
Page 4 - Gregg Kantor: Robbie McClaran, photographer;
service technician: Corky Miller, photographer.
Page 5 - Gill Ranch facility: Robbie McClaran, photographer.
Page 8 - Joe Karney: Corky Miller, photographer.
Page 9 - Gill Ranch facility & headshots: Robbie McClaran, photographer.
Page 10 - Backpack stuffing event: Corky Miller, photographer.
Page 18-19 - Corporate Officers & Board of Directors: Robbie McClaran, photographer.
Page 21 - Robert Hess: Robbie McClaran, photographer.
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