Small StepS add up.
2012 NW Natural aNNual r eport
N
W
N
a
t
u
r
a
l
2
0
1
2
A
n
n
u
a
l
R
e
p
o
r
t
•
S
m
a
l
l
S
t
e
p
s
A
d
d
U
p
.
for 57 consecutive years.
Capital structure at year-end:
Corporate profile
NW Natural (NYSE: NWN) is a 154-year-old
natural gas local distribution and storage
company headquartered in Portland,
Oregon. NW Natural serves about 686,000
utility customers in Oregon and Southwest
Washington, and provides gas storage to
customers on the West Coast. In keeping
with its steady growth, the company has
increased dividends paid to shareholders
ServiCe territory
And StorAge FAcilitieS
WASHINGTON
WASHINGTON
ASTORIA
ASTORIA
MIST STORAGE
VANCOUVER
GASCO LNG
PORTLAND
MIST STORAGE
FIELD TRAINING
CENTER
THE DALLES
VANCOUVER
GASCO LNG
PORTLAND
SALEM
ALBANY
EUGENE
LINCOLN CITY
OREGON
NEWPORT LNG
KEY
FIELD TRAINING
CENTER
SALEM
ALBANY
LINCOLN CITY
NEWPORT LNG
COOS BAY
THE DALLES
COOS BAY
EUGENE
NW NATURAL SERVICE TERRITORY
FIELD TRAINING CENTER
REGIONAL RESOURCE CENTER
LNG PLANT
MIST STORAGE
GILL RANCH STORAGE
HEADQUARTERS
OREGON
KEY
NW NATURAL SERVICE TERRITORY
FIELD TRAINING CENTER
REGIONAL RESOURCE CENTER
LNG PLANT
MIST STORAGE
GILL RANCH STORAGE
HEADQUARTERS
NEVADA
SAN FRANCISCO
GILL RANCH
FRESNO
CALIFORNIA
FinAnciAl overview
2012
2011
percent
increase
(decrease)
earnings
Financial facts ($000):
Operating revenues
Utility margin
Net income
Financial ratios (%):
730,607
828,055
344,527
342,970
59,855
63,898
Return on average common equity
8.3
9.1
Long-term debt
Common stock equity
common stock
Shareholder data (000):
48.5
51.5
47.3
52.7
Average shares outstanding-basic
26,831
26,687
Year-end shares outstanding
26,917
26,756
Per share data ($):
Basic earnings
Diluted earnings
Dividends paid
Dividend rate at year-end
Book value at year-end
Market value at year-end
operating highlights
Gas sales and transportation deliveries
(000 therms)
Degree days
Customers at year-end
Employees at year-end
dividends paid on common stock
(per share)
February 15
May 15
August 15
November 15
2.23
2.22
1.79
1.82
27.23
44.20
2.39
2.39
1.75
1.78
26.70
47.93
1,111,769
1,152,354
4,152
4,652
685,941
679,543
1,092
1,050
$ 0.445
$ 0.435
0.445
0.445
0.455
0.435
0.435
0.445
Total dividends paid
$ 1.790
$ 1.750
(12)
0 )
(6)
(9)
3)
(2)
1)
1)
(7)
(7)
2)
2 )
2 )
(8)
(4)
(11)
1 )
4)
diluted earnings per share
(in dollars)
dividends paid per share
(in dollars)
$3.00
2.50
2.00
1.50
1.00
.50
0
NEVADA
$1.85
1.80
1.75
1.70
1.65
1.60
1.55
1.50
1.45
1.40
1.35
2008
2009
2010
2011
2012
2008
2009
2010
2011
2012
Diluted earnings per share were $2.22 in 2012.
Annual dividends paid per share in 2012 increased
for the 57th consecutive year. The current
indicated annual dividend is $1.82 per share.
LOS ANGELES
SAN FRANCISCO
SAN DIEGO
GILL RANCH
FRESNO
CALIFORNIA
LOS ANGELES
SAN DIEGO
LETTER TO SHAREHOLDERS
3
Gregg Kantor, President and CEO, at our new Sherwood
Operations and Training Center, which provides field
employees hands-on, scenario-based training.
Progress is not always a straight line or a smooth path, but when you
2012 HigHligHts
are a 154-year-old company, small steps add up. In 2012 there were
plenty of steps forward, though they came with some curves and
rough terrain.
• Renewed three key rate mechanisms in Oregon –
decoupling, weather normalization and our system
integrity tracker – critical to revenue stability.
Last year, we made significant advancements in our employee training
and public safety initiatives, maintained industry-leading customer
• Reduced utility rates for the fourth consecutive year,
satisfaction scores, and continued to invest in growth – all while
working through our first Oregon rate case in 10 years.
in addition to refunding $39 million in gas-cost savings
to customers.
Without question, the Oregon rate case was one of last year’s key
• Opened an advanced operations and training center
undertakings. We filed in December of 2011 for two primary reasons.
First, after allowing the company to rate-base the $250 million gas
reserves investment with Encana Oil & Gas, the Public Utility Com-
mission of Oregon (OPUC) wanted the opportunity to review our
rates. Second, our decoupling, weather normalization and system
integrity mechanisms were due to expire and needed to be renewed.
that provides field employees with hands-on,
scenario-based natural gas safety training.
•
Launched a specialized Emergency Contact Center
dedicated exclusively to taking emergency calls day
and night, seven days a week.
The results of the case announced by the OPUC in late October
• Continued to grow the utility by adding new customer
were mixed. There was good news, disappointing news and news
yet to be determined.
hook-ups and investing in gas reserves through our
innovative partnership with Encana.
The OPUC ruled that NW Natural’s annual revenue requirement
should be increased $8.7 million or about 1 percent, with an allowed
rate-base return of 7.78 percent, and an allowed return on equity of
9.5 percent. This revenue increase, however, included approximately
$15 million that was already being recovered through the company’s
• Awarded top-tier satisfaction scores by J.D. Power
and Associates from surveys of our residential and
business customers.
4 LETTER TO SHAREHOLDERS
decoupling mechanism. So overall, the Commission’s decision
meant a net decrease of about $6 million in utility margin annually.
The Commission also ruled that the company could not recover
increases in deferred tax amounts caused by a 2009 Oregon income
tax rate increase. As a result, we took a one-time, after-tax charge of
$2.7 million, or 10 cents per share – ending the year with earnings
of $2.22 per share.
While these were disappointing outcomes, the good news was that
three key rate mechanisms – decoupling, weather normalization and
our system integrity tracker – were renewed. We consider these
mechanisms fundamental to our core earnings going forward and
their renewal was a critical objective of our case. The Commission
decision means we continue to be largely protected from declining
$1.60
$1.40
$1.20
$1.00
$0.80
$0.60
$0.40
$0.20
$0.00
OREGON RESIDENTIAL RATES
Effective Nov. 1 of Each Year
2008
2009
2010
2011
2012
customer use, warmer than average weather, and regulatory lag
OREGON RESIDENTIAL RATES
from investments driven by federal pipeline safety requirements.
Oregon residential rates have declined about 30% since 2008.
In addition, the OPUC approved our request to start recovering costs
related to our environmental cleanup efforts. This new mechanism,
called the Site Remediation and Recovery Mechanism or SRRM,
Also under the “news yet to be determined” category, the Commission
allows for the recovery of prudently incurred past and future environ-
pushed three rate case issues into new regulatory proceedings this
mental cleanup costs. These costs are primarily associated with
year, including whether prepaid pension assets should be added to
sites the company used to manufacture gas for customers dating
rate base. The Commission ultimately decided to open a new docket
back to the 1800s.
on pensions so that it could make a determination that would apply
to all Oregon energy utilities. Until the conclusion of that proceeding,
In a rate proceeding that began in the first quarter of 2013, the
NW Natural will continue to recover its pension expense through
Commission will determine how to apply a prudence review and
amounts currently collected in customer rates or deferred through
earnings test before authorizing the amount to be recovered, but
the regulatory balancing account for collection in future rates.
how that mechanism works and what impact it will have on our
recovery of prudently incurred cleanup costs has not been decided.
The OPUC has also opened a new docket to review how NW Natural
recovers its carrying costs on working gas inventory balances, which
we estimate to be about $4 million in margin annually based on our
allowed rate of return. Historically, we’ve recovered those costs in
rates, and we’ll be striving to retain that treatment.
In another proceeding, Commissioners will review the margin-sharing
agreement we have in place for interstate storage and gas supply
optimization activities. Right now, 67 percent of the margins from
optimization activities go to customers and 33 percent are retained
by shareholders. The OPUC wants to review the agreement and
assess whether it should be revised.
Successful resolution of any of these pending items in 2013 and the
associated revenues will be in addition to the $8.7 million increase to
base rates we received in the October 2012 Commission decision.
While we didn’t get all we hoped for in the rate case, we did secure
the regulatory mechanisms that provide NW Natural a stable
foundation and the opportunity to grow in the future.
Residential and business customers consistently
give us top scores in surveys conducted by J.D.
Power and Associates.
The general rate case took a great deal of time and focus, but it did
not distract us from working on the basics of our business. In 2012,
LETTER TO SHAREHOLDERS
5
NW Natural continued to make progress on our most fundamental
Delivering superior customer service consistently over the long run
commitment: Safety.
requires that employees have the right tools and skills. This year we
continued to update our resource centers to provide a workspace
Delivering on our commitments
that meets the needs of a modern workforce. After careful study and
Safety is at the core of everything we do, and it starts with keeping
planning for future needs, we seized an opportunity to consolidate
our employees healthy and injury-free. In the last few years we’ve
two outdated resource centers into a new building with a much-
ramped up our employee safety efforts – focusing on everything from
needed training facility.
enhanced training to an improved recognition program for incident
reporting.
In October, we officially opened the new Sherwood Operations and
Training Center, which contains a mock residential neighborhood
One of the ways we measure employee safety is by tracking days
that provides our field employees hands-on, scenario-based safety
away from work due to injury along with the number of incidents
training.
where an employee is restricted from normal work activities. Last
year, we lowered that average number to just two cases per 100
Providing safe, reliable service also means making wise pipeline
employees, down from five cases three years ago. We also improved
investments and system improvements. In 2012, we completed
our injury rate per employee, lowering it by more than 50 percent
significant pipeline upgrades in our Mid-Willamette Valley service
over the last three years. While we’re proud of this progress, making
area. These are critical infrastructure investments that significantly
sure all our employees go home uninjured each day is work that is
improve the reliability of our system for years to come.
never finished.
We also made progress last year in many areas that support the
housing market helped our customer growth rate increase to nearly
Last year, lower prices coupled with a modest improvement in the
safety of our system. For example, we launched a new Emergency
1 percent.
Contact Center dedicated exclusively to taking emergency calls day
and night, seven days a week. We are now answering nearly every
And for the fourth consecutive year, lower natural gas prices allowed
emergency call in less than 10 seconds – helping us improve our
us to reduce customer rates – further strengthening our competitive
damage and odor response times.
position against oil and electricity. In Oregon, residential customers re-
ceived about a 5 percent decrease (including adjustments from the rate
We are proud to say that our commitment to safety and to service
case), and Washington residential customers received an 8 percent
across the board continues to be recognized by our customers. Last
reduction. These rate decreases were in addition to $39 million in gas-
year we were again ranked among the top-scoring utilities in satisfac-
cost savings we passed back to customers in their June bills last year.
tion surveys conducted by J.D. Power and Associates. Year after
year, consistently high residential and business satisfaction scores
In 2012, we also continued to reap the long-term advantage of low
demonstrate our employees take great care and pride in what they do.
natural gas prices for customers through our innovative gas reserves
UTILITy CUSTOm ERS AT yEAR-END
BARE STEEL AND CAST IRON REPLACEmENT
700,000
680,000
660,000
640,000
620,000
600,000
2008
2009
2010
2011
2012
UTILITY CUSTOMERS
We added 6,398 new customers in 2012, and now serve nearly
686,000 customers.
l
e
e
t
s
e
r
a
b
f
o
s
e
l
i
M
1,250
1,000
750
500
250
0
n
o
r
i
t
s
a
c
f
o
s
e
l
i
M
250
200
150
100
50
0
1986
1991
1996
2001
2006
2012
BARE STEEL
CAST IRON
The company has about 17 miles of bare steel main left in our system.
There has been no cast iron pipe in our system since 2000.
6
LETTER TO SHAREHOLDERS
investment with Encana. Through last year, our cumulative investment
where they shop – in big box stores and online – and to broaden
reached about $107 million, or about 42 percent of the approximately
our exposure in the retail channel. Our goal is one-stop shopping for
$250 million total investment, which we expect to complete in 2015.
customers looking to get gas to their home, select equipment, and
These investments are expected to provide long-term price protec-
take advantage of special offers. This year we’ll also be looking to
tion for our utility customers.
expand our growth efforts beyond traditional residential and commer-
opportunities abounD
cial customer markets.
Natural gas is shaping a new energy landscape, one defined by
We plan to explore the transportation fuel market for liquefied natural
lower costs. In fact, our customers have seen four consecutive years
gas and compressed natural gas. At half the cost of gasoline, and
of rate decreases and $400 million in cumulative savings. This truly
with 30 percent lower carbon emissions, natural gas is becoming an
is a “golden age” for our industry, with exciting opportunities for the
important fuel for fleets, marine vessels and long-haul trucks. The
nation and for NW Natural.
challenge is building refueling infrastructure. We are working with
policy leaders and regulators to find new ways to support develop-
Abundant domestic supplies and lower prices are creating jobs and
ment as part of our basic utility services.
bringing manufacturing back to the U.S. from overseas. For the first
time since records were kept, as much electricity is being generated
Of course, as more natural gas is consumed for transportation and to
with gas as with coal, which is helping bring U.S. carbon emissions
back up renewables, we believe storage will become an increasingly
to 20-year lows. From climate change to energy independence, the
important asset. Last year we signed an agreement to provide
shale gas revolution is making its mark on the nation’s future.
Portland General Electric (PGE) with storage services at our Mist
facility – an agreement that was dependent on PGE being the suc-
cessful bidder in an open process to provide flexible power generation
to their customers. In the first quarter of 2013, PGE’s bid for that
project was selected, and it is moving forward with plans to build
a new generating plant at Port Westward.
Under our agreement with PGE, NW Natural will develop a storage
expansion at Mist to serve this new plant’s dynamic natural gas
demand. Assuming regulatory and permitting clearances are granted
as planned, we believe this expansion will be online in 2016. It will
include the development of storage wells, a compressor station,
and additional pipeline facilities. This investment will help position
us for future growth at Mist.
At Gill Ranch, our underground gas storage facility in California,
operations are running efficiently, and we are working to expand our
customer base and add higher-value contracts to our portfolio. We
remain confident that storage is a good long-term investment as the
nation moves increasingly to natural gas for power generation and
industrial processes.
Abundant shale gas supplies are helping to boost
growth in our commercial and industrial markets.
NW Natural is seeing the positive impacts of this dramatic rise in
natural gas supplies and the resulting lower prices. In less than two
It’s that increasing dependency on gas for power generation in the
years, 36 new, large commercial and industrial businesses signed up
Northwest that also continues to drive the need for a new interstate
for natural gas service in our market. In the past, the typical rate has
transmission pipeline. Now, like never before, the natural gas and
been about five or six a year. With our growing price advantage over
electric systems are interconnected and interdependent.
other fuel options, we’ll be aggressively looking for new large com-
mercial and industrial customer opportunities in 2013 and beyond.
Today during peak demand the existing interstate pipeline serving
the Northwest is at maximum capacity. There is no question that
We also believe there are additional opportunities in the residential
additional pipeline capacity is essential to ensure the future reliability
market. This year, we’ll be launching a new project to automate sev-
of the region’s gas supplies. This is why we are continuing to work
eral components of our customer acquisition process by developing a
with Northwest utilities and regulators to advance a new integrated,
web-based portal accessible to customers, builders, contractors and
regional, cross-Cascades pipeline solution.
retailers. Our vision for this multiyear initiative is to reach customers
LETTER TO SHAREHOLDERS
7
Natural gas has an important role to play in meeting our future
energy needs and adequate infrastructure will be essential.
The shale gas revolution has reshaped the nation’s energy future
and the value we provide to our customers and shareholders. Our
and it has created exciting possibilities for NW Natural. In 2013,
progress doesn’t always come in big leaps forward. But each year
we’ll aggressively pursue the growth opportunities low-cost natural
we dedicate ourselves to taking the steps necessary to make
gas provides. And we’ll do it without losing sight of our most funda-
NW Natural a stronger company. To this end, there was progress
mental responsibilities – delivering natural gas safely, reliably and
in 2012 and there will be more in 2013. That is the commitment we
with superior customer service.
make to our customers, and to you, our shareholders.
This year we’ll be implementing an automated incident reporting
On behalf of NW Natural employees, thank you for your investment
system to advance our employee safety efforts. We’ll be rolling out
in our company. It is a privilege for all of us to work on your behalf.
appointment windows and further improving our odor response
times to better meet customer expectations. We’ll be focused on
Sincerely,
the successful completion of the remaining rate case issues, and
we’ll continue to collaborate with state policy leaders on expanding
natural gas use to lower carbon emissions and reduce energy
costs to consumers.
At NW Natural we continue to move forward with persistence
and determination, grounded by the knowledge of who we are
Gregg S. Kantor
President and CEO
in recognition
Russell “Russ” Tromley retired in 2012 after
serving 19 years on the NW Natural Board of
Directors, most recently as Chairman of the
Board since 2008. During his tenure, Russ
drew from his extensive business experience
and provided invaluable advice and counsel.
His knowledge of NW Natural and his strong
leadership skills were instrumental in many of
the company’s achievements. Russ helped
shape NW Natural as we know it today, and
for that we owe him our deepest gratitude.
8
8
CORPORATE OFFICERS
NW NATuRAL OFFICERS
FRONt ROW: Margaret Kirkpatrick, David Anderson,
Gregg Kantor and Lea Anne Doolittle.
BAcK ROW: Grant Yoshihara, MardiLyn Saathoff,
Alex Miller, David Williams, Keith White and Stephen Feltz.
DAVID H. ANDERSON
Executive Vice President
Operations and Regulation
StEpHEN p. FELtz
Senior Vice President and
Chief Financial Officer
LEA ANNE DOOLIttLE
Senior Vice President
and Chief Administrative
Officer
GREGG S. KANtOR
President and Chief
Executive Officer
bOARD OF DIRECTORS
MARGAREt D.
KIRKpAtRIcK
Senior Vice President
and General Counsel
MARDILyN SAAtHOFF
Vice President and
Corporate Secretary
Legal, Risk and Compliance
c. ALEx MILLER
Vice President
Regulation and
Treasurer
J. KEItH WHItE
Vice President
Business Development
and Energy Supply, and
Chief Strategic Officer
DAVID R. WILLIAMS
Vice President
Utility Services
GRANt M. yOSHIHARA
Vice President
Utility Operations
tIMOtHy p. BOyLE
President and Chief
Executive Officer
Columbia Sportswear
Company
MARtHA L. “StORMy”
ByORuM
Executive Vice President
Stephens, Inc.
JOHN D. cARtER
Chairman of the Board
Schnitzer Steel
Industries, Inc.
MARK S. DODSON
Former Chief
Executive Officer
NW Natural
c. ScOtt GIBSON
President
Gibson Enterprises
tOD R. HAMAcHEK
Former Chairman and
Chief Executive Officer
Penwest Pharmaceuticals
Company and Chairman
of the Board NW Natural
GREGG S. KANtOR
President and Chief
Executive Officer
NW Natural
JANE L. pEVEREtt
Former President and
Chief Executive Officer
British Columbia
Transmission Corporation
GEORGE J. puENtES
Former President
Don Pancho Authentic
Mexican Foods, Inc.
KENNEtH tHRASHER
Chairman of the Board
Compli Corporation
SHAREHOLDER INFORMATION
9
notice of annual meeting
The 2013 Annual Meeting will be held at 2 p.m., Thursday, May 23, 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 4, 2013, and we will provide you with an admission ticket. A form of government-issued photograph identification will be required
to enter the meeting.
DiviDenD reinvestment anD
Direct stock purcHase plan
contact tHe nW natural boarD
Governance Standards; Director Indepen-
Concerns may be directed to the
dence Standards; Code of Ethics; and Board
Participants may make an initial investment
nonmanagement directors by writing to
Committee Charters. These publications, as
in company stock and common sharehold-
NW Natural Board of Directors, c/o
well as other filings made with the SEC, are
ers of record may reinvest all or part of their
Corporate Secretary.
dividends in additional shares under the
company’s plan. Cash purchases may also
be made. Participants in the plan bear the
forWarD-looking
statements
also available on our website at nwnatural.
com. Our SEC filings are also available by
request through the SEC by mail at U.S.
Securities and Exchange Commission, Office
cost of brokerage fees and commissions for
The statements made in this Annual Report
of FOIA/PA Operations, 100 F Street, N.E.,
shares purchased on the open market to
that are not purely historical, including state-
Washington, D.C. 20549, or online at sec.gov.
fulfill purchases under the plan. A prospectus
ments regarding strategy, growth, future
You can obtain information about access
will be sent upon request.
demand for gas, commodity costs, revenues,
to the Public Reference Room and how to
gas supplies and reserves, investments and
access or request records by calling the
returns, price protection, business develop-
SEC at (202) 551-8090.
scHeDuleD DiviDenD
payment Dates
February 15, 2013
May 15, 2013
August 15, 2013
November 15, 2013
certifications
ment, project timelines, pipeline development,
replacement and safety programs, system
reliability, storage performance and storage
values, pension deferrals, governmental
policy legislation, regulatory cost recovery
mechanisms, prudence reviews, and regula-
tory proceedings and actions, economic
The Chief Executive Officer certified to the
factors, market trends and the competitive
NYSE on June 14, 2012 that, as of that date,
environment are forward-looking statements
he was not aware of any violation by the
within the “safe harbor” provisions of the
company of NYSE’s corporate governance
Private Securities Litigation Reform Act of
listing standards, and the company had filed
1995. NW Natural’s actual results could differ
with the Securities and Exchange Commis-
materially from those anticipated in these
sion (SEC), as exhibits 31.1 and 31.2 to its
forward-looking statements as a result of risks
Annual Report on Form 10-K for the year
and uncertainties, including those described
ended December 31, 2011, the certificates
in the attached report on Form 10-K.
of the Chief Executive Officer and the Chief
Financial Officer of the company certifying
For a more complete description of these
the quality of the company’s public disclo-
risks and uncertainties, please refer to our fil-
sure. For the year ended December 31,
ings with the SEC on Forms 10-K and 10-Q.
2012, the certificates of the Chief Executive
Officer and Chief Financial Officer are
request for publications
attached as exhibits 31.1 and 31.2 to the
The following publications may be obtained
Form 10-K included in this Annual Report.
without charge by contacting the Corporate
Secretary at NW Natural’s address: Annual
Report; Form 10-K; Form 10-Q; Corporate
COmPARISON OF FIVE-yEAR
CUmULATIVE TOTAL RETURN
(based on $100 invested on 12/31/07)
$120
$100
$80
$60
$40
2007
2008
2009
2010
2011
2012
NWN
S&P UTILITIES INDEX
S&P 500 INDEX
Total shareholder return (annualized) over the five
years ending December 31, 2012 for NW Natural was
1.6%, compared to Standard & Poor’s (S&P) Utilities
Index return of negative 1.1%, and the S&P 500
Index return of negative 0.7%. In 2011, the S&P
Small Cap 600 Index was also presented, which
had a return of 3.5% for the same five-year period
presented above. The S&P Small Cap 600 Index was
replaced with the broader S&P 500 Index comparison
as it is more indicative of overall market performance.
10 LIVING Ou R MISSION & VALu ES
our mission:
our core values:
We provide safe, reliable
and affordable energy
in an environmentally responsible way
to better the lives
of the public we serve.
integrity
Safety
Service Ethic
CARING
Environmental Stewardship
Produced by NW Natural’s corPorate commuNicatioNs
pHoto creDits
Cover - Gill Ranch: Robbie McClaran; Service Technichian: Corky Miller; Sherwood Facility: Jeff Lee.
Page 3 - Gregg Kantor: Jeff Lee.
Page 4 - Call Center: Corky Miller.
Page 7 - Russell Tromley: Robbie McClaran.
Page 8 - NW Natural Officers and Board of Directors: Robbie McClaran.
Inside Back Cover - Robert Hess and Chu Lee: Robbie McClaran; Family Picnic: Dale Headrick.
Design
Magneto Brand Advertising
printing
RR Donnelley
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, 2012
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 Name of each exchange on which registered
Common Stock New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: None.
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 ] Accelerated Filer [ ]
Non-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, 2012, the registrant had 26,827,437 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 $1,261,935,437.
At February 22, 2013, 26,937,683 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 2013 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, 2012
TABLE OF CONTENTS
PART I
Glossary of Terms
Forward-Looking Statements
Item 1.
Business
Overview
Business Model
Local Gas Distribution
Gas Storage
Other
Environmental Issues
Employees
Additions to Infrastructure
Executive Officers of the Registrant
Available Information
Item 1A. Risk Factors
Item 1B. Unresolved Staff Comments
Properties
Legal Proceedings
Mine Safety Disclosures
Item 2.
Item 3.
Item 4.
PART II
Item 5.
Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer
Item 6.
Item 7.
Purchases of Equity Securities
Selected Financial Data
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Item 8.
Item 9.
Financial Statements and Supplementary Data
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
Item 9A. Controls and Procedures
Item 9B. Other Information
PART III
Item 10. Directors, Executive Officers and Corporate Governance
Item 11.
Item 12.
Executive Compensation
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Item 13. Certain Relationships and Related Transactions, and Director Independence
Item 14.
Principal Accountant Fees and Services
PART IV
Item 15.
Exhibits and Financial Statement Schedules
SIGNATURES
Page
1
2
3
3
3
3
8
10
11
11
12
12
12
13
20
20
20
20
21
22
23
47
49
82
82
82
83
83
84
84
84
85
86
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 negative 260
degrees Fahrenheit.
PURCHASED GAS ADJUSTMENT (PGA): a regulatory
mechanism which adjusts customer rates to reflect changes
in the forecasted cost of gas and differences between
forecasted and actual gas costs from the prior year.
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.
SITE REMEDIATION AND RECOVERY MECHANISM (SRRM): a
rate mechanism for recovering prudently incurred
environmental site remediation costs through customer
billings, subject to an earnings test.
THERM: the basic unit of natural gas measurement, equal to
100,000 Btu’s.
TRANSPORTATION SERVICE: service provided whereby a
customer purchases natural gas commodity directly from a
supplier but pays the utility to transport the gas over its
distribution system to the customer’s facility.
UTILITY MARGIN: a financial measure consisting of utility
operating revenues less the associated cost of gas.
WEATHER NORMALIZATION: a rate mechanism applied to
residential and commercial customers’ bills to adjust for
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.
GLOSSARY OF TERMS
AVERAGE WEATHER: equal to the 25-year average degree
days based on temperatures established in our last 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 receiving firm service from the utility.
COST OF GAS: the delivered cost of natural gas sold to
customers, including the cost of gas purchased or
withdrawn/produced from storage inventory or reserves,
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 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 billing rates for all classes of utility
customers.
GENERALLY ACCEPTED ACCOUNTING PRINCIPLES (GAAP):
accounting principles generally accepted in the United
States of America.
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.
1
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.
FORWARD-LOOKING STATEMENTS
This report contains “forward-looking statements” within the
meaning of the U.S. Private Securities Litigation Reform Act
of 1995. Forward-looking statements can be identified by
words such as “anticipates,” “intends,” “plans,” “seeks,”
“believes,” “estimates,” “expects” and similar references to
future periods. Examples of forward-looking statements
include, but are not limited to statements regarding the
following:
plans;
•
objectives;
•
goals;
•
strategies;
•
assumptions and estimates;
•
future events or performance;
•
trends;
•
cyclicality;
•
earnings and dividends;
•
growth;
•
customer rates;
•
commodity costs;
•
gas reserves;
•
operational performance and costs;
•
efficacy of derivatives and hedges;
•
liquidity and financial positions;
•
project development and expansion;
•
competition;
•
procurement and development of gas supplies;
•
estimated expenditures;
•
costs of compliance;
•
credit exposures;
•
potential efficiencies;
•
rate recovery and refunds;
•
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;
availability, adequacy, and shift in mix, of gas supplies;
approval and adequacy of regulatory deferrals; and
environmental, regulatory, litigation and insurance costs
and recoveries.
•
•
•
•
2
NORTHWEST NATURAL GAS
COMPANY
PART I
ITEM 1. BUSINESS
OVERVIEW
Northwest Natural Gas Company (NW Natural or the
Company) 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 1997. We maintain
operations in Oregon, Washington and California and
conduct businesses through NW Natural and its
subsidiaries. References in this discussion to "Notes" are
the Notes to Consolidated Financial Statements in Item 8 of
this report.
BUSINESS MODEL
Our business model primarily consists of two core
businesses: local gas distribution, referred to as our "utility"
business segment, which serves residential, commercial,
and industrial customers in Oregon and southwest
Washington; and gas storage, referred to as our "gas
storage" business segment, which serves utilities, gas
marketers, electric generators, and large industrial users.
The utility business represents approximately 90% of our
consolidated assets and net income, while our gas storage
business accounts for a majority of the remaining 10%. We
also have other business and investment activities, which
we aggregate and refer to as our "other" segment and which
accounts for less than 1% of consolidated assets and net
income. We refer to our “gas storage” and “other” business
segments as “non-utility.”
Local Gas Distribution "Utility"
We are principally engaged in the distribution of natural gas
in Oregon and southwest Washington, which involves the
following activities:
•
building and maintaining a safe and reliable pipeline
distribution system;
purchasing gas from producers and marketers;
contracting for the upstream transportation of gas over
pipelines from regional supply basins into our service
territory;
reselling gas commodity 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); and
transporting gas commodities owned by customers
from an interstate pipeline connection, or city gate, to
the customers' facilities for a fee.
•
•
•
•
Our exclusive service area as allocated to us by the OPUC
includes 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. The Portland
metropolitan area is the principal retail and manufacturing
center in the Columbia River Basin and is a major port for
trade with Asia.
3
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 125 cities and neighboring
communities in 15 Oregon counties, as well as in 16 cities
and neighboring communities in three Washington counties.
We serve residential, commercial and industrial customers
in these service areas. 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.
In these service areas, we have no direct competition from
other natural gas distributors. However, each customer
class (i.e. residential, commercial and industrial) is subject
to indirect competition. For residential customers, we
compete primarily with electricity, fuel oil, propane and
renewable energy providers. We also compete with
electricity, fuel oil, propane, and renewable energy for small
to mid-size commercial customers. In the industrial and
large commercial markets, we compete with all forms of
energy, including competition from wholesale natural gas
marketers. Competition among energy suppliers is based on
price, efficiency, reliability, performance, market conditions,
technology, legislative policy, and environmental impact.
At December 31, 2012, we had approximately 686,000
utility customers, consisting of 621,000 residential, 64,000
commercial and 1,000 industrial customers. Approximately
90% of our utility customers are located in Oregon, and 10%
are located in Washington. On an annual basis, residential
and commercial customers typically account for about 50%
to 60% of our utility’s total volumes delivered and about
80% to 90% of our utility margin, while industrial customers
account for the remaining 40% to 50% of volumes and
about 5% to 15% utility margin. The remaining 10% or less
of utility margin is derived from miscellaneous services,
gains or losses from an incentive gas cost sharing
mechanism and other service fees.
In 2012 we experienced a net increase in residential
customers of 5,729 primarily from single- and multi-family
new construction, and from the conversion of existing
homes from oil, electric and propane. The net increase of all
new customers added in 2012 was 6,398. This represents a
12-month growth rate of 0.9%, which is up slightly from
2011 but below historical growth rates due to the
economy. We estimate that natural gas is in less than 60%
of residential single-family dwellings in our service territory.
With natural gas' price advantage, operating convenience,
and environmental benefits over fuel oil, we believe there is
the potential for continued growth in residential and
commercial conversions for many years.
See Note 4 for information on the utility's assets and results
of operations.
Regulation and Rates
The utility is subject to regulation with respect to, among
other matters, rates we charge to utility customers and
systems of accounts by State commissions, which include
the OPUC and WUTC, as well as the Federal Energy
Regulatory Commission (FERC). Among other matters, the
OPUC and WUTC also regulate NW Natural's issuance of
securities.
In order to establish approved rates with the commissions,
we file general rate cases and rate tariff requests
periodically. It is through these requests that the
commission approves our authorized return on equity
(ROE), an overall rate of return on rate base (ROR), the
utility's capital structure, and other revenue/cost deferral
and recovery mechanisms, such as our Purchased Gas
Adjustment (PGA), Weather Normalization Tariff,
Decoupling, System Integrity Program (SIP), Pension Cost
Deferral (Pension Balancing), and environmental Site
Remediation and Recovery Mechanism (SRRM).
In addition, under our Mist interstate storage certificate with
the FERC, the utility is required to file either a petition for
rate approval or a cost and revenue study every five years
to change or justify maintaining the existing rates for the
interstate storage service. The last such filing was made in
2008. The next filing is due by December 2013.
The utility's most recent general rate case in Oregon was
effective November 1, 2012 and its most recent general rate
case in Washington was effective January 1, 2009. As a
result of these most recent rate cases, our current approved
rates and recovery mechanisms for each service area
include:
Authorized Rate Structure:
ROE
ROR
Oregon
Washington(1)
9.5%
7.8%
10.1%
8.4%
Debt/Equity Ratio
50%/50%
49%/51%
X
Key Regulatory Mechanisms(2):
PGA
Incentive Sharing
Weather Normalization Tariff
Decoupling
SIP
Pension Balancing
SRRM
X
X
X
X
X
X
X
(1)Although we do not have the same specific regulatory
mechanisms in Washington, we do have approved regulatory
deferral orders which allow us to defer certain costs for future
recovery through the PGA or future general rate cases, such as our
environmental cost deferral order.
(2)See additional details on each rate mechanism in Part II, Item 7,
“Results of Operations—Regulatory Matters,” and “Gas Storage,”
below.
In our most recent general rate case, the OPUC decided
that several items would be resolved in separate
proceedings, including the Commission's review of:
4
recovery of working gas inventory carrying costs; the
definition of the earnings test and a prudence review under
SRRM; pension cost recovery specifically related to prepaid
pension assets; and the Commission's review of our
revenue-sharing arrangement on the utility's interstate
storage and asset management activities.
Authorized rates and allowed recovery mechanisms provide
our utility business the opportunity to recover prudently
incurred capital and operating costs from customers, while
also earning a reasonable return on investment for
investors. In general, these rates and regulatory
mechanisms do not provide for the utility to earn a profit or
incur a loss on our gas commodity purchases. This means
gas commodity purchase costs are generally a pass-
through cost in customer rates, with the exception of our
incentive cost sharing mechanism in Oregon. Under this
mechanism, we can either increase or decrease margin
revenues based on higher or lower actual gas purchase
costs compared to gas purchase costs embedded in the
PGA and our gas reserve investment. We can earn an
authorized return on the equivalent rate base investment on
our gas reserves.
The pass-through of gas commodity purchase costs in
customer rates also means that for our industrial and large
commercial customers, margin is not materially affected by
whether we sell them gas commodity as part of the utility
service or only provide them with utility transportation
services because they purchase the gas commodity directly
from a marketer or supplier.
In addition to being able to select sales or transportation
only service from the utility, our industrial and large
commercial customers may select between firm and
interruptible service levels. These choices can positively or
negatively affect margin. Rates for firm service generally
have higher profit margins for the utility than interruptible
service. 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 cause
industrial customers to choose 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 so that we can manage the level of
gas supplies we will need to purchase in order to serve this
customer group. These terms include an annual election
cycle period, special pricing provisions for out-of-cycle
changes, and the requirement that industrial customers on
our annual PGA sales rate must complete the agreed upon
term of their service before switching to a new service. In
the case of customers switching out-of-cycle from
transportation to sales service, the customer may be
charged the incremental cost of gas supply in accordance
with our regulatory tariffs.
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 pipeline connections to upstream 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 Supply
The utility's gas supply strategy is to secure sufficient
supplies of natural gas to meet the needs of our customers
and to hedge gas prices so that we can effectively manage
costs, reduce price volatility and maintain a competitive
advantage. We have a diverse portfolio of short-, medium-
and long-term firm gas supply contracts that are
supplemented with gas from storage facilities either owned
by us or contractually committed to us during periods of
peak demand.
To execute our strategy we forecast customer requirements
by considering estimated load growth and sensitivity
analyses based on factors such as weather variations and
price elasticity effects.
We also employ a gas purchasing strategy that includes:
•
•
diverse sources of supply;
diverse portfolio of contract durations and types,
including both physical and financial contracts;
strategic use of gas storage facilities and capacity recall
agreements; and
a variety of gas cost management strategies
•
•
DIVERSITY OF SUPPLY SOURCES. We purchase our gas
supplies primarily at liquid trading points to facilitate
competition and price transparency. These trading points
include the NOVA Inventory Transfer (NIT) point in Alberta,
Canada (also referred to as AECO), Huntingdon/Sumas and
Station 2 in British Columbia, Canada, and multiple receipt
points in the U.S. Rocky Mountains. Currently, about 71% of
our supply comes from Canada, with the balance coming
primarily from the U.S. Rocky Mountain region. 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 our
long-term supply mix based on projections of gas production
and pricing 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 with broader
U.S. market prices. Additionally, we have seen increased
availability of gas supplies throughout North America as a
result of the extraction of shale gas and the building of new
transmission pipeline projects to increase capacity out of the
U.S. Rocky Mountain region.
DIVERSE PORTFOLIO OF CONTRACT TYPES AND
DURATIONS. Our diverse portfolio of firm gas supply
contracts typically includes gas purchase contracts for:
•
•
year-round baseload supply;
additional baseload supply for the winter heating
season;
5
•
•
seasonal contracts where we have an option to call on
additional supplies on a daily basis during the winter
heating season; and
daily or monthly spot purchases.
At December 31, 2012, we have contracts with gas
suppliers for deliveries ranging from three months to three
years, which provide for a maximum of 2.1 million therms of
firm gas per day during the winter heating season and 0.6
million therms per day year-round. In addition, we have
another 1.2 million therms per day of firm gas supplies
whereby we can purchase supplies for delivery to our
system during the winter heating season. During 2012, we
purchased a total of 733 million therms under contracts with
durations outlined in the chart below.
Contract Duration (primary term)
Long-term (one year or longer)
Short-term (more than one month, less than one
year)
Spot (one month or less)
Total
Percent of
Purchases
34%
21
45
100%
We typically renew or replace our gas supply contracts with
new agreements from existing and new suppliers. Aside
from the asset management of our core utility gas supplies
by an independent energy marketing company, no individual
supplier provided more than 10% of our supply
requirements. Firm year-round supply contracts have
remaining terms ranging from one to three years. Currently,
all firm gas supply contracts use price formulas tied to
monthly index prices. See “Gas Cost Management Strategy
—Asset management,” below.
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. During 2012, new
short-term purchase contracts were entered into with 18
suppliers, which in addition to our year- round contracts
provide for a total of up to 2.1 million therms per day. We
intend to enter into new purchase contracts during 2013 for
roughly the same volume of gas with existing or new
suppliers, as needed, to replace contracts that will expire in
2013.
We also buy gas on the spot market as needed to meet
utility customer demand. We have flexibility under the terms
of some firm supply contracts, 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.
A small volume of gas is also purchased from a non-
affiliated producer in the Mist gas field in Oregon. Current
production supplies are less than 1% of our total annual
purchase requirements. Production from these wells varies
as existing wells are depleted and new wells are drilled.
STRATEGIC USE OF GAS STORAGE AND CAPACITY RECALL.
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. A portion of our daily and seasonal
peaking supplies to core utility customers are from our
underground gas storage facility in the Mist gas storage
field. This facility has a maximum daily deliverability of 5.2
million therms and a total working gas capacity of about 16
Bcf, which includes the capacity reserved for core utility
customers as well as the capacity used for non-utility
service. Under our regulatory agreement with the OPUC,
non-utility gas storage at Mist can be developed in advance
of core utility customer needs, but it is subject to recall by
the utility when needed 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. In May 2012, a total of 150,000 therms per day of
Mist storage capacity that had previously been available for
non-utility interstate services was recalled and committed to
use for core utility customers. Similarly in May 2011, a total
of 100,000 therms per day of Mist storage capacity was
recalled for core utility customer use. There was no Mist
recall in 2010. The core utility currently has 2.8 million
therms per day of deliverability and approximately 10.0 Bcf
of working gas capacity available at the Mist storage facility.
We also have contracts with Northwest Pipeline, a
subsidiary of The Williams Companies, for firm gas storage
at the Jackson Prairie underground facility near Chehalis,
Washington, which provides us with daily firm deliverability
of about 0.5 million therms and total seasonal capacity of
about 1.1 Bcf. 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.
In addition, we also contract for underground storage
service in Alberta, Canada for amounts totaling just under 2
Bcf. This supply will displace equivalent volumes of spot
purchases in Alberta as it uses the same pipeline
transportation for delivery from Alberta to our local gas
distribution system. While this supply helps manage price
risks, it does not add to our total peak day resources.
Liquefied Natural Gas (LNG) storage. We own and operate
two LNG storage facilities in our Oregon service territory
that liquefy gas for storage during off-peak months so that it
is available for withdrawal during periods of peak demand.
These two facilities provide a maximum combined daily
deliverability of 1.8 million therms and a total seasonal
capacity of 1.5 Bcf. In addition, we have a contract for firm
gas storage from an LNG facility in Plymouth, Washington,
which provides us with daily firm deliverability of about 0.6
million therms and total seasonal capacity of about 0.5 Bcf.
Capacity recall 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.
GAS COST MANAGEMENT STRATEGY. The cost of gas sold
to utility customers primarily consists of:
•
•
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, including our gas reserves contract, entered
into in connection with the purchase of gas for core
utility customers.
•
Recent developments in drilling technologies have
increased access to gas supplies in shale gas formations
around the U.S. and Canada, the current outlook for North
American natural gas supplies is strong and is projected to
remain this way well into the future.
We are charged pipeline transportation rates by Canadian
pipelines and U.S. interstate pipeline transportation service
providers. 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 FERC, as applicable. Settlement was recently reached
on a Northwest Pipeline rate case and new rates went into
effect beginning January 1, 2013. Pipeline transportation
rate increases or decreases are generally passed on to our
customers through annual PGA updates.
We employ a number of strategies to mitigate the cost of
gas sold to utility customers. Our primary strategies for
managing gas commodity price risk include:
•
•
negotiating fixed prices directly with gas suppliers;
negotiating financial derivative contracts that effectively
convert floating index prices in physical gas supply
contracts to fixed prices (referred to as commodity price
swaps);
negotiating financial derivative contracts that effectively
set a ceiling or floor price, or both, on floating index
priced physical supply contracts (referred to as
commodity price options such as calls, puts, and
collars);
buying physical gas supplies at a set price and injecting
it into storage for price stability;
investing in gas reserves for longer term price stability;
and
using an asset management service provider to
produce incremental revenues that are used to reduce
our utility’s net cost of gas.
•
•
•
•
Financial derivative instruments. We hedge a majority of our
firm year-round supply contracts each year using financial
derivative instruments as a key component of our gas
purchasing strategy. Our financial hedge contracts make up
a majority of our commodity price hedging activity, and
these contracts are with a number of investment-grade
credit counterparties, typically with credit ratings of AA- or
higher. Under our financial hedge policy, we enter into
commodity swaps, puts, calls and collars with terms
generally ranging anywhere from one month to five years.
See Part II, Item 7A, “Quantitative and Qualitative
Disclosures About Market Risk—Credit Risk—Credit
exposure to financial derivative counterparties.”
6
Gas reserves. We entered into agreements with Encana Oil
& Gas (USA) Inc. (Encana) which provide us a long-term
fixed price hedge that is backed with physical supplies.
These agreements are intended to provide long-term price
protection for our utility customers. Our investment in these
gas field interests are rate base investments that are part of
our annual Oregon PGA filing, which is subject to incentive
sharing and allows us to recover our costs through
customer rates in a manner previously approved by the
OPUC. This transaction acted to hedge the cost of gas for
approximately 4% of our gas supplies for the year-ended
December 31, 2012.
Asset management. 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 to manage net gas costs. In addition to maximizing
the value of our gas storage and pipeline capacity, we
contract with an independent energy marketing company
that manages our unused capacity when those assets are
not serving the needs of our core utility customers. Our
asset management activities provide cost savings that
reduce our utility’s cost of gas, and generate incremental
revenues from a regulatory incentive-sharing mechanism,
which are included in our gas storage business segment.
GAS DISTRIBUTION OPERATIONS. The goals of our gas
distribution operations are:
•
SAFETY – Building and maintaining a safe pipeline
distribution system;
•
• RELIABILITY – Ensuring gas resource portfolios that
are sufficient to satisfy customer requirements under
extremely cold weather conditions;
LOWEST REASONABLE COST – Acquiring gas
supplies at the lowest reasonable cost for utility
customers;
PRICE STABILITY – Managing commodity price
volatility by making the best use of physical assets and
financial instruments; and
•
• COST RECOVERY – Managing gas purchase costs
prudently to minimize risks associated with regulatory
review and cost recovery.
Safety. Safety and the protection of our employees, our
customers and the public at large are and will remain a top
priority. We monitor and maintain our pipeline distribution
system and storage operations with the goal of ensuring
that natural gas is stored and delivered safely, reliably and
efficiently. We have had various cost recovery mechanisms
since 2004 and currently have a program which integrates
the Company’s bare steel replacement, transmission
pipeline integrity management, and distribution pipeline
integrity management programs into a single program. In
response to the recent pipeline incidents involving other
companies, natural gas distribution businesses are likely to
be subject to even greater federal and state regulation in the
future. The “Pipeline Safety, Regulatory Certainty, and Job
Creation Act of 2011” signed into law in early 2012, includes
several new safety initiatives including:
•
an analysis of the appropriateness of automatic or
remote shut-off valves on new and replaced gas
transmission lines;
7
•
•
an evaluation of the benefits of expanding transmission
integrity management regulations to additional
pipelines; and
requirements for operators to reverify the maximum
allowable operating pressures for transmission
pipelines.
We continue to work diligently with industry associations as
well as federal and state regulators to ensure the safety of
our system and ensure compliance with new laws and
regulations. We expect that costs associated with
compliance to federal, state and local rules would be
recoverable in rates.
Reliability. The effectiveness of our gas distribution program
ultimately rests on whether we provide reliable service at a
reasonable cost to our core utility customers. To ensure our
effectiveness, we develop a composite design year,
including a three day design peak event that is based on the
most severe cold weather experienced during the last 20
years in our service territory.
Our projected sources of delivery for design day firm utility
customer sendout total approximately 9.3 million therms. Of
this total, we are currently capable of meeting over 60% of
our maximum design day requirements with gas from
storage located within or adjacent to our service territory,
while the remaining supply requirements would be met by
gas purchases under firm and recall gas purchase
contracts.
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.
We believe that our supplies would be sufficient to meet
existing firm customer demand if we were to experience
maximum 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 further discussion of IRP below).
The following table shows the sources of supply that are
projected to be used to satisfy the design day sendout for
the 2012-2013 winter heating season:
Therms in millions
Sources of utility supply
Therms
Percent
Firm supply purchases
Mist underground storage (utility only)
Company-owned LNG storage
Off-system firm storage contracts
Recall agreements
Total
3.3
2.7
1.8
1.1
0.4
9.3
36%
29
19
12
4
100%
The OPUC and WUTC have IRP processes 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 providing reliable service
at the “least cost.”
basins; and (2) the east, which brings supplies from Alberta
as well as the U.S. Rocky Mountain supply basins.
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 receipt of 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
prudence 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 prudence
review. We filed our draft 2013 IRP with Washington in
January 2013 and will file an IRP update in Oregon in May
of 2013.
Lowest Reasonable Cost. We apply cost management
strategies, including fixed-price contracts, financial
derivative instruments, storage supplies, acquisition of gas
reserves, and asset management, to acquire gas supplies
at the lowest reasonable cost for utility customers. See “Gas
Supply—Gas Cost Management Strategy” above.
Price Stability. We use physical assets and financial
instruments to manage commodity price volatility. We
purchase gas for our storage facility generally during the
summer months when gas prices are typically lower. In
addition, our gas reserves provide long-term gas price
protection for our utility customers. We also mitigate year-to-
year commodity price volatility through financial hedge
contracts such as commodity price swaps and options.
Cost Recovery. Mechanisms for gas cost recovery are
designed to be fair and reasonable, with an appropriate
balancing of interests between our customers and
shareholders. In general, utility rates are designed to
recover the costs, but not to earn a return on, the gas
commodity sold. We minimize risks associated with gas cost
recovery by:
•
re-setting customer rates annually to reflect changes in
forecasted gas costs for the upcoming year and
differences between actual and forecasted gas costs
from the prior year. See Part II, Item 7, “Results of
Operations—Regulatory Matters—Rate Mechanisms—
Purchased Gas Adjustment”;
aligning customer and shareholder interests through
the use of our PGA incentive sharing mechanism,
weather normalization, decoupling, 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.
•
•
Transportation of Gas Supplies
SINGLE TRANSPORTATION PIPELINE. Our local gas
distribution system is reliant on a single, bi-directional
interstate transmission pipeline to bring gas supplies into
our distribution system. Although we are dependent on a
single pipeline, the pipeline’s gas flows into the Portland
metropolitan market from two directions: (1) the north, which
brings supplies from the British Columbia and Alberta supply
8
In 2003 a federal order requiring Northwest Pipeline to
replace its 26-inch mainline from the Canadian border to our
service territory underscored the potential need for pipeline
transportation diversity. That replacement project was
completed by Northwest Pipeline in November 2006. We
are pursuing options to further diversify the pipeline
transportation system. Specifically, we are jointly developing
plans to build a pipeline that would connect TransCanada
Pipelines Limited’s (TransCanada) Gas Transmission
Northwest (GTN) interstate transmission line to our local
gas distribution system. 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, “2013 Outlook—Strategic
Opportunities—Pipeline Diversification”.
PIPELINE TRANSPORTATION AGREEMENTS. We incur
monthly demand charges related to our firm pipeline
transportation contracts.
Our largest pipeline agreements are with Northwest Pipeline
for firm transportation capacity providing us access to
natural gas supplies in British Columbia and the U.S. Rocky
Mountains by connecting us with Northwest Pipeline and
GTN systems in Oregon. These and other contracts are
multi-year contracts with expirations ranging from 2016 to
2044. We actively work with Northwest Pipeline and others
to renew these contracts in advance of expiration and
ensure gas transportation capacity is sufficient to meet our
needs.
RATES GOVERNING TRANSPORTATION OF GAS SUPPLIES.
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.
Gas Storage
Our gas storage segment primarily consists of two
underground natural gas storage facilities:
• NON-UTILITY MIST – the non-utility portion of our Mist
gas storage facility near Mist, Oregon; and
• GILL RANCH – our 75% share of the Gill Ranch gas
storage facility near Fresno, California.
Transmission pipeline capacity and natural gas production
are relatively constant over the course of a year compared
to the demand for natural gas, which fluctuates daily and
seasonally. Therefore, 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 and price volatility 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. See Note 4 for more
information on gas storage assets and results of operations.
Regulation and Rates
Our gas storage segment is subject to regulation with
respect to, among other matters, rates, terms of service,
and system of accounts established by the OPUC, WUTC
and FERC with respect to the Mist facilities, and by the
California Public Utilities Commission (CPUC) with respect
to Gill Ranch. Gill Ranch has a tariff on file with the CPUC
authorizing it to charge market-based rates for the storage
services offered. FERC has approved maximum cost-based
rates under our Mist interstate storage certificate. We are
required to file with FERC either a petition for rate approval
or a cost and revenue study at least every five years to
change or justify maintaining the existing rates for the
interstate storage service. See Part II, Item 7, “Results of
Operations–Regulatory Matters”.
Facilities
MIST 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. The Mist field was converted
to storage operations for our utility customers during the
1990s. Since 2001, gas storage capacity at Mist has been
made available to interstate customers by developing new
incremental capacity in advance of core utility customer
requirements to meet the 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 services
in Oregon under an OPUC-approved rate schedule as an
optional service to eligible non-residential utility customers.
GILL RANCH STORAGE FACILITY. Gill Ranch Storage, LLC
(Gill Ranch), our subsidiary, has a joint project agreement
with Pacific Gas and Electric Company (PG&E) to develop
and own the Gill Ranch underground natural gas storage
facility near Fresno, California. Currently, Gill Ranch is the
sole operator of the facility. The facility began operations in
the fourth quarter of 2010.
The Gill Ranch 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
transmission pipeline extending 27 miles from the storage
field to an interconnection with the PG&E transmission
system, and other related facilities. Gill Ranch owns the
rights to 75% of the available storage capacity at the
facility. Gill Ranch’s share of the facility currently provides
15 Bcf of working gas capacity.
Gill Ranch is offering storage services to the California
market at market-based rates, subject to regulation by the
CPUC for certain activities including, but not limited to,
service terms and operating conditions.
ASSETS. The following table highlights certain important
design information about the Company’s non-utility gas
storage assets.
Mist Storage(1)
Gill Ranch Storage(2)
Storage
Capacity
(Bcf)
6
15
Withdrawal
(MMcf/day)(3)
Injection
(MMcf/day)(3)
243
488
97
240
(1) Approximately 6 Bcf of a total 16 Bcf at Mist is currently available
to our gas storage segment. The remaining 10 Bcf is used to
provide gas storage for our local distribution business and its utility
customers. All storage capacity and daily deliverability currently
developed for the gas storage segment at Mist is available for recall
by the utility.
(2) Our share of the Gill Ranch facility is currently 15 Bcf out of a
total capacity of 20 Bcf.
(3) Our share of the expected daily maximum injection and
withdrawal rates.
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 Interstate storage capacity has
been developed as a non-utility investment by NW Natural
in advance of core utility customers’ requirements.
Gill Ranch storage facility is not 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 our firm interstate storage service
regulated by FERC, except that these customers are
located and served in Oregon.
Gill Ranch 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.
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
with Mist storage capacity related to utility, and
management of available surplus storage capacity and
related transportation capacity can be managed under
regulatory sharing agreements with the OPUC and WUTC.
This temporary surplus capacity is quite often available
during the spring and summer months when the demand for
gas by utility customers is low. See "Asset Management"
below.
Although we expect much of the storage revenue at Gill
Ranch to be in the form of fixed monthly demand charges,
total cash flows could be more seasonal in nature than the
Mist storage facility. A significant portion of operating costs
9
at Gill Ranch is related to compression. Because
compression is used primarily for the injection of gas rather
than for withdrawal, we expect power costs to be higher
during the injection season.
Gas Storage Customers
For our Mist interstate storage services, firm service
agreements with customers are entered into with terms
typically ranging from 1 to 10 years. Currently, our gas
storage revenues from Mist are derived primarily from firm
service customers who provide energy related services,
including natural gas production or distribution, electric
generation, and energy marketing. Three storage customers
currently account for over 90% of our existing non-utility gas
storage capacity at Mist, with the largest customer
accounting for about half of the total capacity. These three
customers have contracts that expire at various dates
through 2018.
Customer contracts for firm storage capacity at Gill Ranch
are as long as 28 years in duration, but we expect Gill
Ranch in the early years of operation to contract for terms
mostly ranging from one to five years due to current market
conditions. Gill Ranch currently has several storage
customers, with the largest single contract accounting for
approximately 13% of the facility’s design capacity. 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 customer or group of
customers for capacity at Gill Ranch. Current Gill Ranch
customers provide energy related services, including natural
gas production, marketing, and electric generation.
Competitive Conditions
Our Mist gas storage facility benefits from limited
competition from other Pacific Northwest storage facilities
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.
The 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 market. There are also ongoing
expansions and proposed new construction of storage
capacity in northern California that could increase
competition for Gill Ranch.
•
•
regulatory approval. We believe the earliest timeframe for
completing the next expansion is 2016. We expect to begin
working on detailed design and project scope during 2013,
which will be followed by permitting and construction. The
project will likely include the development of storage wells, a
compression station, and additional pipeline facilities that
would enable more storage expansions in the future.
Gill Ranch Storage Facility. Subject to market demand,
project execution, available financing, receipt of future
permits, and other rights, the Gill Ranch storage facility can
be expanded beyond the current combined permitted
capacity of 20 Bcf without further expansion of the 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 at least 40 Bcf, of which Gill
Ranch would have the rights to at least an aggregate of 20
Bcf or 50% of the total estimated storage capacity.
Asset Management
We contract with an independent energy marketing
company to provide asset management services, primarily
through the use of commodity transactions and pipeline
capacity release transactions, the results of which are
included in the gas storage business segment, except for
amounts allocated to our utility pursuant to regulatory
sharing agreements involving the use of utility assets. Pre-
tax income from third-party asset management services is
subject to revenue sharing with core utility customers. See
Part II, Item 7, “Results of Operations–Business Segments -
Gas Storage”
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 part of our
utility or gas storage segments. This segment primarily
consists of:
•
an equity method investment in a joint venture to build
and operate a gas transmission pipeline in Oregon. See
Part II, Item 7, “2013 Outlook—Strategic Opportunities
—Pipeline Diversification”;
a minority interest in other pipeline assets held by our
wholly-owned subsidiary NNG Financial Corporation
(NNG Financial); and
other operating and non-operating income and
expenses of the parent company that are not included
in utility or gas storage operations.
The pipelines referred to above are regulated by FERC.
Less than 1% of our consolidated assets and consolidated
net income are related to activities in the “Other” business
segment. See Note 4 for summary information on this Other
segment’s assets and results of operations.
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 future expansion at Mist in
anticipation of increased natural gas demand for electric
generation in the Pacific Northwest. In 2012, a request for
proposal (RFP) to provide additional electric generation was
sent out by Portland General Electric (PGE). PGE's bid was
recently selected for this project. We have an agreement to
provide gas storage services to PGE as part of this project,
subject to several conditions including NW Natural receiving
10
ENVIRONMENTAL ISSUES
Properties and Facilities
We own, or previously owned, properties and facilities that
are currently being investigated that may require
environmental remediation and 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 address 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.
•
•
•
•
•
We continue to seek recovery of environmental costs
through insurance and through customer rates, and we
believe recovery of these costs is probable. Pursuant to the
2012 Oregon general rate case, environmental cost
deferrals will be recovered under the new SRRM subject to
a reduction for third-party insurance recoveries, a prudence
review, and an earnings test that will be defined in a
separate regulatory proceeding which is currently open. As
there is uncertainty surrounding the outcome of this
proceeding, we will continue to carefully assess these
environmental assets for recoverability. 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
"Results of Operations—Rate Matters—Rate Mechanisms
—Environmental Costs" below and Note 15.
Greenhouse Gas Issues
We recognize that our businesses are likely to be impacted
by future requirements to address greenhouse gas
emissions. Future federal and/or state requirements may
seek to limit future emissions of greenhouse gases,
including both carbon dioxide (CO2) and methane. These
future laws and regulations may require certain activities to
reduce emissions and/or increase the price paid for energy
based on its carbon content.
Current federal rules require the reporting of 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. We
began reporting emission information in 2011. Under this
reporting rule, local gas distribution companies like NW
Natural are required to report system throughput to the EPA
11
on an annual basis. The EPA also issued additional
greenhouse gas reporting regulations requiring the annual
reporting of fugitive emissions from our operations.
The outcome of federal and state policy development in the
area of climate change 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 gas from our
operations could require us to incur costs to reduce
emissions of greenhouse gas 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 generation,
direct use of natural gas in homes and businesses, and as a
reliable and relatively low-emission back-up fuel source for
alternative energy sources. Requirements to reduce
greenhouse gas emissions from the transportation sector,
such as those in Oregon’s clean fuel standard, could also
result in additional demand for natural gas for use in
vehicles.
We continue to take steps to address future greenhouse
gas emission issues, including actively participating in policy
development through participation on various Oregon
taskforces and, at the federal level, within the American Gas
Association. 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 offering the Smart Energy program, which allows
customers to voluntarily contribute funds to projects such as
biodigesters on dairy farms that offset the greenhouse
gases produced from their natural gas use.
EMPLOYEES
At December 31, 2012, the utility workforce consisted of 623
members of the Office and Professional Employees
International Union (OPEIU) Local No. 11, AFL-CIO, and
469 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.
At December 31, 2012, our subsidiaries had a combined
workforce of 20 non-union employees. Our subsidiaries
receive certain services from centralized operations at the
utility, and as such the utility is reimbursed for those
services pursuant to a Shared Services Agreement.
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
improvements and gas storage facilities. In 2013, utility
capital expenditures are estimated to be between $115 and
$130 million, and non-utility capital investments are
estimated to be between $10 and $15 million. For the five-
year period ending in 2017, capital expenditures for the
utility are estimated to be between $600 and $700 million,
while the amount for gas storage and other investments
after 2013 will depend largely on future decisions about
potential expansion opportunities in gas storage and
pipeline projects.
EXECUTIVE OFFICERS OF THE REGISTRANT
For information concerning our executive officers, see Part
III, Item 10.
AVAILABLE INFORMATION
We file annual, quarterly and special reports and other
information with the Securities and Exchange Commission
(SEC). Reports, proxy statements and other information
filed by us can be read and requested through the SEC by
mail at U.S. Securities and Exchange Commission, Office of
FOIA/PA Operations, 100 F Street, N.E., Washington, D.C.
20549, by facsimile at (202) 772-9337, or online at its
website (http://www.sec.gov). You can obtain information
about access to the Public Reference Room and how to
access or request records by calling the SEC at (202)
551-8090. The SEC website contains reports, proxy and
information 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 filed or furnished
pursuant to Section 13(a) or 15(d) and proxy materials filed
under 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 (Code) for all employees
and officers that is available on our website. We intend to
disclose amendments to, and any waivers from the Code of
Ethics on our website. Our Corporate Governance
Standards, Director Independence Standards, charters of
each of the committees of the Board of Directors and
additional information about us are also available at the
website. Copies of these documents may be requested, at
no cost, by writing or calling Shareholder Services, NW
Natural, One Pacific Square, 220 N.W. Second Avenue,
Portland, Oregon 97209, telephone 503-226-4211 ext.
3412.
12
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
REGULATORY RISK. Regulation of our businesses, including
changes in the regulatory environment, failure of regulatory
authorities to approve rates which provide for timely
recovery of our costs and an adequate return on invested
capital, or an unfavorable outcome in regulatory
proceedings 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 rate base, including return on
equity, the amounts and types of securities we may issue,
services we provide and the manner in which we provide
them, the nature of investments we make, actions investors
may take with respect to our company, and deferral and
recovery of various expenses, including, but not limited to,
pipeline replacement, environmental remediation costs,
pension expense, transactions with affiliated interests, and
other matters. Similarly, in our gas storage business FERC
has regulatory authority over interstate storage services,
and the CPUC has regulatory authority over our Gill Ranch
storage operations.
The prices that the OPUC and WUTC allow us to charge for
retail service, and the tariff rate that FERC permits us to
charge for transmission, are the most significant factors
affecting our financial position, results of operations and
liquidity. The OPUC and WUTC have the authority to
disallow recovery of costs they find imprudently incurred.
For example, in our most recent Oregon rate case
concluding in 2012, the OPUC disallowed certain deferred
tax amounts the deferral of which was not previously
reviewed by the OPUC, resulting in an after tax charge to
net income when the order was received. Additionally, the
rates allowed by the FERC may be insufficient for recovery
of costs incurred. We expect to continue to make
expenditures to expand, improve and operate our utility
distribution and gas storage systems. Regulators can find
such expansions or improvements of expenditures were not
prudently incurred, and deny recovery. Additionally, while
the OPUC and WUTC have established through the
ratemaking process an authorized rate of return for our
utility, the regulatory process does not provide assurance
that we will be able to achieve the earnings level authorized.
Moreover, 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
13
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.
In our latest general rate case with the OPUC, various items
were deferred for future resolution in separate proceedings,
including a review of our working gas inventory carrying
costs, the definition of the earnings test under the SRRM,
the prudence of environmental expenditures we have
deferred to date, recovery of prepaid pension costs, and our
revenue-sharing arrangement on the utility's interstate
storage activities. The regulatory proceedings in which
these issues will be resolved typically involve multiple
parties, including governmental agencies, consumer
advocacy groups, and others who are impacted by the use
of natural gas. Each party has differing concerns, but all
generally have the common objective of limiting amounts
included in rates. We cannot predict the outcome of these
deferred proceedings or the effects of those outcomes on
our results of operations and financial condition.
ECONOMIC AND MARKET RISK. Adverse economic and
financial market conditions may have a negative impact on
our financial condition and results of operations.
While the national and regional economy appears to be
experiencing some recovery from the recent downturn, we
cannot predict how robust the recovery will be, or whether it
will be sustained. Continued or increased sluggishness in
our regional economy, could result in low levels of new
housing construction, conversions to natural gas, customer
additions, and relatively higher levels of residential
vacancies, lending restrictions, and personal and business
bankruptcies, as well as reduced spending. All of these
factors could all result in a decline in or sustained lower
levels of natural gas consumption and customer growth, a
slowing of collections from our customers, and higher levels
of delinquent accounts receivable and bad debts, all of
which could have a negative effect on our financial condition
and results of operations.
ENVIRONMENTAL LIABILITY RISK. Certain of our properties
and facilities may pose environmental risks requiring
remediation, the costs of which are difficult to estimate and
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. A
regulatory asset at the utility has already been recorded for
estimated costs pursuant to a deferral order from the OPUC
and WUTC. In addition to maintaining regulatory deferrals,
we are vigorously litigating against certain of our historical
liability insurers for a portion of the costs we have incurred
to date and expect to incur in the future. 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 result in a
charge to current year earnings. In addition, in our most
recent Oregon general rate case, the OPUC approved the
SRRM, which limits recovery of our deferred amounts to
those amounts which satisfy an annual prudence review
and an earnings test, the definition of which was deferred to
a later regulatory proceeding. These prudence reviews and
earnings tests could reduce the amounts we are allowed to
recover, and which could adversely affect our financial
condition, results of operations and cash flows
In addition to litigation against historical insurers, we may
have disputes with regulators and other parties as to the
severity of particular environmental matters and what
remediation efforts are appropriate. We cannot predict with
certainty the amount or timing of future expenditures related
to environmental investigation, remediation or other action,
or disputes or litigation arising in relation thereto. Our
liability estimates are based on current remediation
technology, industry experience gained at similar sites, an
assessment of the probable level of involvement, and
financial condition of other potentially responsible parties.
However, it is difficult to estimate such costs due to
uncertainties surrounding the course of environmental
remediation, the preliminary nature of certain of our site
investigations, and the application of environmental laws
that impose joint and several liabilities on all potentially
responsible parties. These uncertainties and disputes
arising therefrom could lead to further adversarial
administrative proceedings or litigation, with associated
costs and uncertain outcomes, all of which could adversely
affect our financial condition, results of operations and cash
flows.
ENVIRONMENTAL REGULATION COMPLIANCE RISK. We are
subject to environmental regulations for our ongoing
operations, compliance with 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, including those legal requirements that govern
discharges of substances into the air and water, the
management and disposal of hazardous substances and
waste, groundwater quality and availability, plant and wildlife
protection, and other aspects of environmental regulation.
Current and additional environmental regulations could
result in increased compliance costs or additional operating
restrictions and 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.
GLOBAL CLIMATE CHANGE RISK. Future legislation to
address global climate change may expose us to regulatory
and financial risk. Additionally, our business may be subject
to physical risks associated with climate change, all of which
could adversely affect our financial condition, results of
operations and cash flows.
There are a number of 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 and
methane. Such current or future legislation or regulation
could impose on us operational requirements, additional
charges to fund energy efficiency initiatives, or levy a tax
based on carbon content. 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
increased costs on us 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.
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
disruptions to natural gas production and transportation
systems potentially increasing the cost of gas beyond that
assumed in our PGA and affecting our ability to procure gas
to meet our customer demand. These changes could also
affect our distribution systems resulting in increased
maintenance and capital costs, disruption of service,
regulatory actions and lower customer satisfaction.
Additionally, to the extent that climate change adversely
impacts the economic health or weather conditions of our
service territory directly, it could adversely impact customer
demand or our customers' ability to pay. Such physical risks
could have an adverse effect on our financial condition,
results of operations, and cash flows.
BUSINESS DEVELOPMENT RISK. Our business development
projects may encounter unanticipated obstacles, costs,
changes or delays that could result in a project becoming
impaired, which could negatively impact 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, but not limited to, the early planning and
development stage on a regional cross-Cascades pipeline
in Oregon. 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 additional long-term gas reserves. With
respect to these projects, we may not be able to obtain
required governmental permits and approvals to complete
our projects in a cost-efficient or timely manner potentially
resulting in delays or abandonment of the projects. We
could also experience startup and construction delays,
construction cost overruns, inability to negotiate acceptable
agreements such as rights-of-way, easements, construction,
gas supply or other material contracts, changes in customer
demand or commitment, public opposition to projects,
changes in market prices, and operating cost increases.
Additionally, we may be unable to finance our business
14
development projects at acceptable interest rates or within a
scheduled timeframe necessary for completing the project.
One or more of these events could result in the project
becoming 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 affects 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 our cross-Cascades
pipeline, Gill Ranch storage and Encana gas reserves. We
may acquire or develop part-ownership interests in other
similar projects in the future. Under these 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. 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.
For example, our gas reserves venture with Encana, which
operates as a hedge backed by physical gas supplies,
involves a number of risks. These risks include gas
production that is significantly less than the expected
volumes, or no gas volumes; operating costs that are higher
than expected; changes in our consolidated tax position or
tax law that could affect our ability to take, or timing of,
certain tax benefits that impact the financial outcome of this
transaction; inherent risks of gas production, including
disruption to operations or complete shut-in of the field; and
a participant in one of these business arrangements acting
contrary to our interests. In addition, while the cost of the
gas reserves venture with Encana is currently included in
customer rates, the occurrence of one or more of these
risks, could affect our ability to recover this hedge in rates,
which could adversely impact the project as well as 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 local 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 or 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 underground 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 resulting in loss of the gas;
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 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 outcome resulting from such events
could be significant. 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, including cyber attacks, and other
extreme events to which we may not able to promptly
respond.
Local or national disasters, pandemic illness, terrorist
activities, including cyber attacks, 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 acts
of terrorism, including physical and cyber attacks, that could
target or impact our natural gas distribution, transmission or
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. 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.
15
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,
results of operations and cash flows.
Until we closed the plans to new hires, which for non-union
employees was in 2006 and for union employees was in
2009, we provided pension plans and postretirement
healthcare benefits to eligible full-time utility employees and
retirees. Most of our current utility employees were hired
prior to these dates, and therefore remain eligible for these
plans. 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, increases in healthcare costs, current and
future legislative changes, and various actuarial calculations
and assumptions. The actuarial assumptions used to
calculate our future pension and postretirement healthcare
expense may differ materially from actual results due to
significant market fluctuations and changing withdrawal
rates, wage rates, interest rates and other factors. These
differences may result in an adverse impact on the amount
of pension contributions, pension expense or other
postretirement benefit costs recorded in future periods.
Sustained declines in equity markets and reductions in bond
rates may have a material adverse effect on the value of our
pension fund assets. In these circumstances, we may be
required to recognize increased contributions and pension
expense earlier than we had planned to the extent that the
value of pension assets is less than the total anticipated
liability under the plans, which could have a negative impact
on financial condition, results of operations and cash flows.
WORKFORCE RISK. Our business is heavily dependent on
being able to attract and retain qualified employees and
maintain a competitive cost structure with market-based
salaries and employee benefits, and workforce disruptions
could adversely affect our operations and results.
Our ability to implement our business strategy and serve our
customers 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
OPEIU Local No.11 AFL-CIO (the Union), and are covered
by a collective bargaining agreement that extends to 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. Our collective bargaining agreement may also
increase the cost of employing our Union 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, which may negatively affect our
financial condition and results of operations.
LEGISLATIVE, COMPLIANCE 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.
Additionally, any failure to comply with existing or new laws
and regulations could result in fines, penalties or injunctive
measures that could affect operating assets. For example,
under the Energy Policy Act of 2005, the FERC has civil
authority under the Natural Gas Act to impose penalties for
current violations of up to $1 million per day for each
violation. In addition, as the regulatory environment for our
industry increases in complexity, the risk of inadvertent
noncompliance may also increase. Changes in regulations,
the imposition of additional regulations, and the failure to
comply with laws and regulations could negatively influence
our operating environment and results of operations.
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.
SAFETY REGULATION RISK. We may experience increased
federal, state and local regulation of the safety of our
systems and operations, which could adversely affect our
operating costs and financial results.
The safety and protection of the public, our customers and
our employees is and will remain our top priority. We are
committed to consistently monitoring and maintaining our
distribution system and storage operations to ensure that
natural gas is acquired, stored and delivered safely, reliably
and efficiently. Given recent high-profile natural gas
explosions and accidents in other parts of the country, we
anticipate that the natural gas industry may be the subject of
even greater federal, state and local regulatory oversight.
We intend to work diligently with industry associations and
federal and state regulators to ensure compliance with the
new laws, such as the “Pipeline Safety, Regulatory
Certainty, and Job Creation Act of 2011” signed into law in
16
early 2012. We expect there to be increased costs
associated with compliance with this and similar laws, and
those costs could be significant. If these costs are not
recoverable in our customer rates, they could have a
negative impact on our operating costs and 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.
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. In our Utility segment, we
attempt to manage these exposures with both financial and
physical hedging mechanisms, including our recent gas
reserve transaction with Encana which is a hedge backed
by physical gas supplies. While we have risk management
procedures for hedging in place, they 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 to obtain the
hedge. 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. However, the hedge transactions we
enter into for the utility are subject to a prudence review by
the OPUC and WUTC, and, if found imprudent, those
expenses may be disallowed, which could have an adverse
effect on our financial condition and results of operations.
In addition, our 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 to meet our normal business
requirements. In that event, our financial results could be
adversely affected. 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.
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, bond 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 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.
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 supplies,
transportation constraints, availability and cost of pipeline
capacity, federal and state energy and environmental
regulation and legislation, natural disasters 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 is generally passed through to our customers
through an annual PGA rate adjustment. If gas prices were
to increase significantly, it would raise the cost of energy to
our utility customers, potentially causing those customers to
conserve or switch to alternate sources of energy.
17
Significant price increases could also cause new home
builders and commercial developers to select alternative
fuel sources. Decreases in the volume of gas we sell could
reduce our earnings, and a decline in customers could slow
growth in our future earnings. Additionally, because a
portion of any 10% or 20% difference between the
estimated average PGA gas cost in rates and the actual
average gas cost incurred is recognized as current income
or expense, higher average gas costs than those assumed
in setting rates can adversely affect our operating cash
flows, liquidity and results of operations. Additionally,
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.
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 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 resulting in greater expense associated with
collection efforts and increased bad debt expense.
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 the natural gas in
our distribution segment, and limitations on our ability to
obtain supplies, or failure to receive expected supplies for
which we have contracted, 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 receive delivery of
supplies of natural gas from third parties. We, and in some
cases, our suppliers of natural gas do not have control over
the availability of natural gas supplies, competition for those
supplies, disruptions in those supplies, priority allocations
on transmission pipelines, or pricing of those supplies.
Additionally, third parties on which we rely may fail to deliver
gas for which we have contracted. If we are unable to
obtain, or are limited in our ability to obtain, natural gas from
our current suppliers or new sources, we may not be able to
meet our customers' gas requirements and would likely
incur costs associated with actions necessary to mitigate
services disruptions, both of which could significantly and
negatively impact our results of operations.
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.
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 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. Insufficient growth in these markets, for
economic, political or other reason could result in an
adverse long-term impact on our utility margin, earnings and
cash flows.
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, technology, environmental impacts and
public perception.
Technological improvements in other energy sources such
as heat pumps could also erode our competitive advantage.
If natural gas prices rise relative to other energy sources, or
if the cost, environmental impact or public perception of
such other energy sources improves relative to natural gas,
Our distribution system is directly connected to a single
interstate pipeline, which is owned and operated by
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
could significantly and negatively impact our results of
operations.
WEATHER RISK. Warmer than average weather 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 by gas sales to
space heating residential and commercial customers during
the winter heating season. Current utility rates are based on
an assumption of average weather. Warmer than average
weather typically results in lower gas sales. Colder weather
typically results in higher gas sales. Although the effects of
warmer or colder weather on utility margin in Oregon are
expected to be mitigated through the operation of our
weather normalization mechanism, weather variations from
normal could adversely affect utility margin because we may
be required to purchase more or less gas at spot rates,
which may be higher or lower than the rates assumed in our
PGA. Also, a portion of our Oregon residential and
18
commercial customers (usually less than 10%) have opted
out of the weather normalization mechanism, and 10% of
our customers are located in Washington where we do not
have a weather normalization mechanism. These effects
could have an adverse effect on our financial condition,
results of operations and cash flows.
CUSTOMER CONSERVATION RISK. Customers’ conservation
efforts may have a negative impact on our revenues.
An increasing national focus on energy conservation,
including improved building practices and appliance
efficiencies may result in increased energy conservation by
customers. This can decrease our sales of natural gas and
adversely affect our results of operations because revenues
are collected mostly through volumetric rates, based on the
amount of gas sold. In Oregon, we have a conservation
tariff which is designed to recover lost utility margin due to
declines in residential and commercial customers’
consumption. However, we do not have a conservation tariff
in Washington that provides us this protection.
RELIANCE ON TECHNOLOGY RISK. Our efforts to integrate,
consolidate and streamline our operations have resulted in
increased reliance on technology, the failure or security
breach 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, an automated
dispatch system, an automated meter reading system, a
customer information system, 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. Additionally, our utility could experience
breaches of security pertaining to sensitive customer,
employee and vendor information maintained by the utility in
the normal course of business. which could adversely affect
the utility’s reputation, diminish customer confidence, disrupt
operations, and subject us to possible financial liability or
increased regulation or litigation, any of which could
adversely affect our financial condition and results of
operations.
Furthermore, we rely on information technology systems in
our operations of our distribution and storage operations.
There are various risks associated with these systems,
including, hardware and software failure, communications
failure, data distortion or destruction, unauthorized access
to data, misuse of proprietary or confidential data,
unauthorized control through electronic means,
programming mistakes and other inadvertent errors or
deliberate human acts. In particular, cyber security attacks,
terrorism or other malicious acts could damage, destroy or
disrupt all of our business systems. Any failure of
information technology systems could result in a loss of
operating revenues, an increase in operating expenses and
costs to repair or replace damaged assets. As these
potential cyber security attacks become more common and
sophisticated, we could be required to incur costs to
19
strengthen our systems or obtain specific insurance
coverage against potential losses.
Risks Related Primarily to Our Gas Storage Business
LONG-TERM LOW OR STABILIZATION OF GAS PRICE RISK.
Any significant stabilization of natural gas prices or long-
term low 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 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.
Largely due to the abundant supply of natural gas made
available by hydraulic fracturing techniques, natural gas
prices have dropped significantly to levels that are near a
10-year low. If prices and volatility remain low or decline
further, then the demand for storage services, and the
prices that we will be able to charge for those services, may
decline or be depressed for a prolonged period of time. A
sustained decline in these prices could have an adverse
impact 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 storage, 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. Natural gas storage is
an increasingly competitive business, with ongoing
expansions and proposed construction of new storage
capacity 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 our storage
facilities to interstate pipelines, 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 could have an adverse impact on our financial
condition, results of operations and cash flows.
OPERATIONS AT NEW STORAGE FACILITY RISK. 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
storage facility has been successfully completed 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 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 financial condition, results of
operations and cash flows.
replacement program under which we removed and
replaced 100% of our cast iron mains by the end of 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 12,000 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 (Mortgage) is a first
mortgage lien on substantially all of the property constituting
our utility plant.
ITEM 1B. UNRESOLVED STAFF COMMENTS
ITEM 3. LEGAL PROCEEDINGS
Other than the proceedings disclosed in Note 15 and as
discussed below, we have only 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 10 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 reimburse and 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 $50 million in
losses it has incurred to date, as well as declaratory relief
for additional losses it expects to incur in the future.
ITEM 4. MINE SAFETY DISCLOSURES
Not applicable.
We have no unresolved comments.
ITEM 2. PROPERTIES
Utility Properties
Our natural gas pipeline system consists of approximately
14,000 miles of distribution and transmission mains located
in our service territory in Oregon and Washington. In
addition, the piping system includes service pipelines,
meters and regulators, and gas regulating and metering
stations. Pipeline 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 numerous navigable waterways
and smaller tributaries throughout our entire service
territory.
We own service building 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 also 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 also
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
20
PART II
ITEM 5. MARKET FOR THE REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS
AND ISSUER PURCHASES OF EQUITY SECURITIES
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
2012
2011
High
Low
High
Low
$
49.49
$
44.40
$
48.72
$
48.56
50.16
50.80
43.90
46.04
41.01
46.40
46.77
48.98
43.92
43.57
39.63
42.52
The closing quotations for our common stock on December 31, 2012 and 2011 were $44.20 and $47.93, respectively.
As of February 22, 2013, there were 6,366 holders of record of our common stock.
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
2012
2011
$
$
0.445
$
0.445
0.445
0.455
1.790
$
0.435
0.435
0.435
0.445
1.750
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.
The following table provides information about purchases of our equity securities that are registered pursuant to Section 12 of
the Securities Exchange Act of 1934 during the quarter ended December 31, 2012:
Period
Balance forward
10/01/12-10/31/12
11/01/12-11/30/12
12/01/12-12/31/12
Total
Issuer Purchases of Equity Securities
Total Number
of Shares Purchased(1)
Average
Price Paid per Share
Total Number of Shares
Purchased as Part of
Publicly Announced
Plans or Programs(2)
Maximum Dollar Value of
Shares that May Yet Be
Purchased Under the
Plans or Programs(2)
2,124,528
$
16,732,648
— $
3,114
—
3,114
$
—
42.75
—
42.75
—
—
—
—
—
—
2,124,528
$
16,732,648
(1) During the quarter ended December 31, 2012, 3,114 shares of our common stock were purchased on the open market to meet the
requirements of our share-based programs. During the quarter ended December 31, 2012, no shares of our common stock were accepted
as payment for stock option exercises pursuant to our Restated Stock Option Plan (Restated SOP).
(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, 2013 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, 2012, no shares of our common stock were repurchased 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.
21
ITEM 6. SELECTED FINANCIAL DATA
In thousands, except share data
2012
2011
2010
2009
2008
Operating revenues
Net income
$
730,607
$
828,055
$
792,115
$
988,055
$
1,012,783
59,855
63,898
72,667
75,122
69,525
For the year ended December 31,
Earnings per share of common stock:
Basic
Diluted
Dividends paid per share of common stock
$
2.23
$
2.39
$
2.73
$
2.83
$
2.22
1.79
2.39
1.75
2.73
1.68
2.83
1.60
2.63
2.61
1.52
Total assets, end of period
$
2,818,753
$
2,746,574
$
2,616,616
$
2,399,252
$
2,378,152
Total equity
Long-term debt
733,033
691,700
714,488
641,700
693,101
591,700
660,105
601,700
628,373
512,000
22
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 or the Company)
financial condition, including the principal factors that affect
results of operations. The discussion refers to our
consolidated activities for the years ended December 31,
2012, 2011, and 2010. References in this discussion to
"Notes" are the Notes to Consolidated Financial Statements
in Item 8 of this report.
The consolidated financial statements include NW Natural
and its direct and indirect wholly-owned subsidiaries which
include:
• NW Natural Energy, LLC (NWN Energy),
• NW Natural Gas Storage, LLC (NWN Gas Storage),
• Gill Ranch Storage, LLC (Gill Ranch), and
• NNG Financial Corporation (NNG Financial).
These statements also include our equity investment in
Palomar Gas Holdings, LLC (PGH), which is pursuing the
development of a proposed natural gas pipeline through its
wholly-owned subsidiary Palomar Gas Transmission, LLC
(Palomar), and NNG Financial's investment in KB Pipeline.
These entities make up our regulated local gas distribution
business, our regulated gas storage businesses, and other
regulated and non-regulated investments primarily in
energy-related businesses. In this report, the term “utility” is
used to describe our regulated gas distribution business
(local distribution company), and the term “non-utility” is
used to describe our gas storage businesses (gas storage)
and other business segments. For a further discussion of
our business segments, see Note 4.
In addition to presenting results of operations and earnings
amounts in total, certain financial measures are expressed
in cents per share, which are non-GAAP financial
measures. These amounts reflect factors that directly
impact earnings. In calculating these financial disclosures,
we allocate income tax expense based on the effective tax
rate, where applicable. All references in this section to
earnings per share are on the basis of diluted shares.
We use such non-GAAP measures in analyzing our
financial performance because we believe they provide
useful information to our investors and creditors in
evaluating our financial condition and results of operations.
EXECUTIVE SUMMARY
In 2012, we advanced the following core company
initiatives:
•
the Oregon general rate case was completed with key
regulatory mechanisms renewed including our
decoupling and weather normalization mechanisms and
system integrity program. Several items in the case
were delayed to separate dockets, and we will continue
to work to resolve these items in 2013. Delayed items
included interstate storage revenue sharing, working
gas inventory, and a pension cost recovery mechanism.
In addition, the earnings test for our new environmental
Site Remediation and Recovery Mechanism (SRRM)
•
•
will be defined and a prudence review will be
performed;
safety initiatives moved forward including the launch of
our emergency contact center dedicated exclusively to
responding to emergency calls and the opening of a
new industry-leading training facility; and
customer growth and satisfaction continued to remain
high with our growth rate at 0.9% for 2012 and J.D.
Power and Associates ranked us in the top two utilities
for customer satisfaction in the West for the ninth year
in a row.
While we accomplished many goals in 2012, we look
forward to further opportunities to safely provide service to
our customers, work with regulators, and grow our business
in 2013. See "2013 Outlook" below for more information.
Key financial highlights include:
In millions, except per
share data
2012
2011
2010
Consolidated net income
$
59.9
$
63.9
$
72.7
Consolidated earnings
per share (EPS)
2.22
2.39
2.73
Utility margin
$
344.5
$
343.0
$
346.1
Results for 2012:
•
•
•
net income decreased primarily due to higher utility
operations and maintenance, and depreciation
expenses, as well as a one-time tax charge resulting
from the Oregon general rate case;
gas storage income increased primarily due to higher
revenues reflecting additional capacity at our Gill Ranch
gas storage facility; and
utility margins increased primarily due to a $7.4 million
net charge in 2011 related to a utility tax law change in
Oregon, as well as residential and commercial
customer growth, partially offset by a decrease in
margin due to timing differences from the new billing
rate structure resulting from the Oregon general rate
case and the effects of warmer weather.
See "Consolidated Earnings and Dividends" below for
additional detail.
2013 OUTLOOK
With increased domestic supply of natural gas and lower
prices, 2013 affords many opportunities for the natural gas
industry and NW Natural. We remain committed to providing
safe, reliable gas service to customers while growing our
core businesses and exploring additional natural gas
service needs and markets. Safety for our customers,
employees, and communities is at the center of our
activities.
GROW CORE BUSINESSES. Our primary businesses are
utility and gas storage. In the utility, we continue to leverage
our resources to provide natural gas services to our
residential, commercial, and industrial customers. In
particular, we will continue working with industrial customers
to convert legacy oil heating systems to natural gas. In our
gas storage business, we will focus on maximizing our
storage capacity and optimizing revenue opportunities. We
believe that investing in operating efficiencies and marketing
23
opportunities for our core businesses positions us well for
growth now and into the future.
ENSURE SAFETY. Safety is at the core of everything we do.
We strive to provide our employees industry-leading safety
training facilities, effective safety policies, procedures, and
equipment, and foster a work environment that emphasizes
safety in all areas. Maintaining a safe infrastructure and
effective emergency response program is key to providing
safe and reliable natural gas service to our customers. That
is why we continue to focus on and invest in our system
integrity program (SIP), emergency response system,
training facilities and programs, and pipeline and system
improvements.
ENHANCE STRATEGIC POSITION. The decline in natural gas
prices and abundance of supplies creates opportunities for
our utility business as we leverage natural gas' competitive
price advantage. Our gas storage facilities are challenged
by current market conditions, but we are strategically
positioning ourselves to quickly respond to increasing
market demand as the economy improves or gas prices
become more volatile. Together, our businesses are
competitively positioned to meet growing market demands.
ADVANCE KEY PROJECTS. We seek to create shareholder
value by innovatively addressing the needs of our
customers, employees, and the communities we serve while
addressing economic, regulatory, and environmental
challenges. To that end, we are advancing key business
projects such as key rate mechanisms, pursuing storage
development opportunities at Mist, and evaluating
opportunities to create value and improve our Gill Ranch
operations and revenues. We also continue to pursue
regional solutions for reliable and safe energy needs
through our investment in natural gas cross-Cascades
pipeline infrastructure.
EXPLORE NEW SERVICE OPPORTUNITIES. We believe our
utility business is strategically and competitively positioned
with the decline in natural gas prices and the abundance of
supplies. Natural gas is competitively priced in the energy
market and compliments wind and solar renewable energy
options as a reliable, on-call, electric generation resource.
Therefore, we will be exploring new opportunities to serve
customers with natural gas such as gas storage for wind
following electric generation plants and natural gas for the
vehicle transportation fuel market. We are also investigating
expanded service offerings for our existing utility customers
to ensure customer needs are met. We remain committed to
continuous improvement and providing innovative and high
quality service.
Issues, Challenges and Performance Measures
ECONOMY. The local, national, and global economies
continued to show signs of weakness during 2012 and have
impacted utility customer growth, business demand for
natural gas and market prices for gas storage. Our utility’s
customer growth rate was 0.9% in 2012, compared to
growth of 0.8% in 2011 and 0.9% in 2010. The local
economy is beginning to show signs of a slow recovery as
unemployment rates in our region dropped from
approximately 9% in 2011 to about 8% at the end of 2012,
and industrial gas use increased in 2012 by 1% over 2011.
We believe our utility is well positioned to continue adding
customers and to serve increasing industrial demand as the
economy recovers because of low, stable natural gas
prices, our relatively low market penetration, and our
ongoing marketing focus of converting homes and
businesses to natural gas. In addition, environmental
initiatives that favor lower carbon emissions and lower cost
energy alternatives, such as natural gas, could increase
demand for our services in the future.
GAS PRICES AND SUPPLIES. Our gas acquisition strategy is
to secure sufficient supplies of natural gas to meet the
needs of our utility customers and to hedge gas prices so
we can effectively manage costs, reduce price volatility, and
maintain a competitive price advantage. With recent
developments in drilling technologies and substantial
access to supplies around the U.S. and in Canada, the
current outlook for North American natural gas supply is
strong and is projected to remain this way well into the
future. The continuation of low and stable gas prices in the
future depends on a combination of supply outlook and
demand factors as well as a regulatory environment that
continues to support hydraulic fracturing and other drilling
technologies.
Our utility's annual Purchased Gas Adjustment (PGA)
mechanisms in Oregon and Washington, combined with our
gas price hedging strategies, enable us to reduce earnings
exposure for the Company and secure lower gas costs for
our customers. See “Regulatory Matters—Rate
Mechanisms—Purchased Gas Adjustment” below.
We typically hedge gas prices on approximately 75% of our
utility's annual sales requirement based on average
weather, including both physical and financial hedges. We
entered the 2012-13 gas year (November 1, 2012 – October
31, 2013) hedged at approximately 75% of our forecasted
sales volumes, including 47% in financial swap and option
contracts and 28% in physical gas supplies. The physical
hedges consisted of a combination of gas inventories in
storage, local production from the Mist area, and production
from gas reserves. For further discussion of gas reserves,
see "Strategic Opportunities—Gas Reserves" and "Results
of Operations—Regulatory Matters—Rate Mechanisms—
Gas Reserves" below.
In addition to the amount of gas hedged for the current gas
contract year, as of December 31, 2012 we are also hedged
at approximately 22% for the 2013-14 gas year and
between 8% and 24% for annual requirements over the
following five gas years. Our hedge levels are subject to
change based on actual load volumes, which depend to a
certain extent on weather and economic conditions. Also,
our storage inventory levels may increase or decrease
based on storage expansion, storage contracts with third
parties, or storage recall by the utility.
Although less expensive and more stable gas prices provide
opportunities to manage costs for our utility customers, they
also present challenges for our gas storage businesses by
lowering the price of, and reducing the demand for, storage
services. Consequently, our ability to sign longer-term
storage contracts with customers at favorable prices affects
our financial results. However, if there is an increase in
demand for natural gas and/or a decrease in drilling activity,
there may be upward pressure on gas prices or price
24
volatility which may result in increased demand and prices
for storage services. In the short-term, we strive to find
opportunities for increasing revenues, lowering costs and
developing enhanced services for storage customers.
ENVIRONMENTAL COSTS. We accrue all material
environmental loss contingencies related to environmental
sites for which we are responsible. Due to numerous
uncertainties surrounding the nature of environmental
investigations and the development of remediation solutions
approved by regulatory agencies, actual costs could vary
significantly from our loss estimates. As a regulated utility,
we have been allowed to defer certain costs pursuant to
regulatory actions. In our general rate case, the Public Utility
Commission of Oregon (OPUC) approved our recovery of
costs from environmental site remediation subject to certain
conditions as noted in "Results of Operations—Regulatory
Matters—Rate Mechanisms" below.
We are pursuing recovery from insurance policies through
litigation and only seek recovery from customers for
amounts not covered by insurance. Ultimate recovery of
environmental costs from regulated utility rates will depend
on our ability to effectively manage these costs,
demonstrate that costs were prudently incurred, and the
impact of any earnings test the OPUC is expected to adopt
in a subsequent proceeding. Cost recovery and carrying
charges on amounts charged to Washington customers will
be determined in a future proceeding. Based on these future
proceedings, 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 we are likely to be
impacted by future carbon constraints. To address possible
constraints, we are seeking clean energy growth
opportunities that position us for long-term success in a
lower carbon energy economy and to advance our
customers’ interests in energy conservation, efficiency and
environmental stewardship. A variety of federal, state, local
and international climate change initiatives, including new
regulations, are underway, but we cannot determine the
impact of these initiatives at this time. For example, an array
of Environmental Protection Agency (EPA) rules impacting
coal plants may drive some coal plants to shut down early
although the EPA is not mandating coal plant closures. Coal
plant shut downs could increase the demand for natural gas
as a lower carbon emission fuel and create opportunities for
us. Similarly, 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 base load electric generation, direct use in homes and
businesses, backing up intermittent renewable resources,
and as a transportation fuel to displace gasoline and diesel
fuels.
As required under EPA greenhouse gas regulations, we
annually report our system throughput and unintended
greenhouse gas releases. 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.
PERFORMANCE MEASURES. In order to deal with the
challenges affecting our businesses, we annually review
and update our strategic plan to map out a course for the
next several years. Our plan includes strategies for:
growing our utility services and operations;
•
exploring new service opportunities in the natural gas
•
industry;
optimizing and growing our non-utility gas storage
businesses;
investing in natural gas infrastructure as needed to
support the energy needs of our region; and
•
•
• maintaining a leadership role in the gas utility industry
by advancing long-term energy policies.
We intend to measure our performance and monitor
progress on relevant metrics including, but not limited to:
•
•
•
•
earnings per share growth;
utility margin;
return on equity (ROE); and
various other operational metrics.
Strategic Opportunities
SAFETY, RELIABILITY, AND SERVICE. We are committed to
customer and employee safety, operational effectiveness,
service quality, and capitalizing on our competitive position.
Therefore, we have several ongoing initiatives designed to
improve the quality and integrity of our pipeline
infrastructure, and have upgraded several facilities to
enhance business continuity, employee training and safety,
productivity, and energy efficiency. In addition, we opened a
separate emergency contact center in 2012, which
increased our ability to effectively respond to emergencies.
Our initiatives in 2013 will further enhance our commitment
to safety. The Company has increased staffing levels in the
areas of pipeline safety, emergency response, regulatory
compliance, field training, and customer service to respond
to new federal pipeline safety legislation and system
integrity requirements as well as customer expectations for
service responsiveness.
GAS STORAGE. We own and operate two underground gas
storage facilities—the Mist facility in Oregon and the Gill
Ranch facility near Fresno, California. Storage operations
benefit from seasonal swings in commodity pricing and
market volatility. Our storage facilities position us to
capitalize on rising demand for natural gas, higher gas
prices or increased market volatility. Currently natural gas
prices remain relatively low and stable; however, if there is
an increase in demand for natural gas and/or a decrease in
drilling activity, there may be upward pressure on gas prices
and price volatility may return. We have the ability to expand
both facilities beyond their current capacities.
The Pacific Northwest storage market is also impacted by
lower gas prices and lack of gas price volatility, although
less than California because there are fewer regional
competitors. Nevertheless, we continue to plan for
expansion at Mist in anticipation of increased natural gas
demand for energy generation in the Pacific Northwest. In
2012, a request for proposal (RFP) to provide additional
electric generation was sent out by Portland General
Electric (PGE). PGE's bid was recently selected for this
25
project. We have an agreement to provide gas storage
services to PGE as part of this project, subject to several
conditions including NW Natural receiving regulatory
approval.
In addition, we estimate that the current Gill Ranch storage
facility could support an additional 20 Bcf of storage
capacity, bringing the total storage capacity to 40 Bcf, of
which our rights would give us at least an additional 5 Bcf or
ownership of a total of approximately 20 Bcf. An expansion
at the Gill Ranch storage facility would require certain
infrastructure modifications, but no further expansion of our
gas transmission pipeline. See Note 4 for more information
on our current gas storage facilities.
PIPELINE DIVERSIFICATION. Currently, our utility operations
and gas storage operations at Mist depend on a single bi-
directional interstate transmission pipeline to ship gas
supplies to customers. This is why we continue to work with
regulators and utilities in the Pacific Northwest to advance a
new integrated, regional cross-Cascades pipeline through
our Palomar investment.
The proposed pipeline would be regulated by the Federal
Energy Regulatory Commission (FERC). Palomar intends to
file an application with FERC for a pipeline delivering gas
from the GTN pipeline near Madras in central Oregon to a
NW Natural hub near Molalla, Oregon. The application will
be filed after NW Natural has completed resource plans and
Palomar has conducted a new open season to obtain
commercial support for the pipeline. The approval and
timing of potential construction of the pipeline will depend on
the project being competitive with alternative Pacific
Northwest pipeline projects, obtaining regulatory permits,
and garnering the necessary commercial support from
shippers. See Note 12 for further discussion.
GAS RESERVES. In addition to hedging gas prices with
financial derivative contracts, we entered into an agreement
with Encana Oil & Gas (USA) Inc. (Encana) in 2011 to
hedge a portion of our Oregon utility customers’ cost of gas
over 30 years through working interests in gas leases.
These working interests are in a gas field located in Sublette
County, Wyoming. During the first 10 years of the contract,
we forecast the volumes of gas to be produced under the
gas reserves agreement as sufficient to hedge
approximately 8% to 10% of the average annual utility gas
supply requirements. The gas reserves transaction is
expected to hedge approximately 8% of our utility gas
supply for the 2012-13 gas year. We receive certain federal
tax deductions for drilling costs incurred under our gas
reserves agreements. The timing of when we realize these
federal tax benefits has been affected by net operating
losses for tax purposes, which will be carried forward to
reduce our current tax liability in future years. We continue
to evaluate additional investments in gas reserves as part of
our gas hedging strategy. See "Results of Operations—
Regulatory Matters—Rate Mechanisms—Gas Reserves"
below.
CONSOLIDATED EARNINGS AND DIVIDENDS
Consolidated Earnings
Consolidated highlights include:
In millions, except EPS
data
Net income
EPS
2012
2011
2010
$
$
59.9
2.22
$
$
63.9
2.39
$
$
72.7
2.73
Return on equity
8.3%
9.1%
10.7%
2012 COMPARED TO 2011. The primary factors contributing
to the $4.0 million decrease in consolidated net income
were:
•
a $4.1 million increase in operations and maintenance
expense primarily due to increases in utility payroll and
employee benefit costs, utility training costs, and utility
expenses related to our Oregon general rate case;
a $3.0 million increase in depreciation and amortization
expenses primarily due to higher levels of investment in
property, plant, and equipment at the utility; and
a $2.7 million after-tax charge to income tax expense
related to a regulatory disallowance from the Oregon
general rate case.
•
•
Partially offsetting the above factors were:
•
a $1.6 million increase in utility margin primarily due to
a $7.4 million net charge in 2011 results related to a
utility tax law change in Oregon as well as residential
and commercial customer growth, partially offset by a
decrease in margin primarily due to timing differences
from the new billing rate structure resulting from the
Oregon general rate case and the effects of warmer
weather;
a $4.1 million increase in gas storage operating income
primarily attributable to revenue increases from
additional contracted storage capacity at Gill Ranch,
partially offset by $2.8 million increase in interest
expense due to the full year impact of Gill Ranch notes;
and
a $0.9 million increase in net income from our other
non-utility business segment.
•
•
2011 COMPARED TO 2010. The most significant factors
contributing to the $8.8 million decrease in consolidated net
income were:
•
a $7.2 million net charge against utility margin taken in
2011, plus the $7.7 million of utility margin revenues
accrued in 2010, related to the repeal of Oregon’s
legislative rule on utility income taxes;
a $5.4 million increase in general taxes, primarily due to
a $5.2 million refund of utility property taxes received in
2010, partially offset by a $0.9 million decrease in other
taxes at the utility, and a $1.3 million increase in
property and other taxes at Gill Ranch;
a $4.9 million increase in depreciation and amortization
expense, due to a $1.2 million increase at the utility and
a $3.7 million increase at Gill Ranch; and
a $4.3 million increase in operations and maintenance
expense, primarily due to a $3.2 million increase at Gill
Ranch reflecting first-year operating expenses.
•
•
•
26
Partially offsetting the above factors was:
•
an $11.3 million increase in utility margin attributable to
an increase in customers gas use, reflecting gains from
colder weather, customer growth and a slight increase in
industrial demand; and a $6.1 million decrease in income
tax expense related to lower taxable income.
Dividends
Dividend highlights include:
Per common share
Dividends paid
2012
2011
2010
$
1.79
$
1.75
$
1.68
The Board of Directors declared a quarterly dividend on our
common stock of 45.5 cents per share, payable on February
15, 2013, reflecting an indicated annual dividend rate of
$1.82 per share.
RESULTS OF OPERATIONS
Regulatory Matters
Regulation and Rates
UTILITY. Our utility business is subject to regulation with
respect to, among other matters, rates, terms of service,
and systems of accounts set by the OPUC, Washington
Utilities and Transportation Commission (WUTC), and
FERC. The OPUC and WUTC also regulate the issuance of
securities by our utility. In 2012, approximately 90% of our
utility gas volumes and revenues were derived from Oregon
customers, with the remaining 10% from Washington
customers. Earnings and cash flows from utility operations
are largely determined by rates set in rate cases and other
proceedings in Oregon and Washington, but will also be
affected by the economies in Oregon and Washington, by
the pace of customer growth in the residential and
commercial markets, and by our ability to remain price
competitive, control expenses, and obtain reasonable and
timely regulatory recovery of our utility-related costs,
including operating expenses and investment costs in utility
plant and other regulatory assets. See "General Rate
Cases" below.
GAS STORAGE. Our gas storage business is subject to
regulation with respect to, among other matters, issuance of
securities and systems of accounts set by the OPUC,
California Public Utilities Commission (CPUC), and FERC.
The OPUC and FERC regulate intrastate and interstate
storage services, respectively, under a maximum cost of
service model which allows for storage prices to be set at or
below the cost of service as approved by each agency in
the last regulatory filing. The CPUC regulates Gill Ranch
under a market-based rate model which allows for the price
of storage services to be set by the marketplace. In 2012,
approximately 54% of our storage revenues were derived
from FERC and Oregon regulated operations and
approximately 46% from California operations.
General Rate Cases
OREGON. Our most recent general rate case in Oregon was
completed in 2012, and in it the OPUC authorized rates to
customers based on an ROE of 9.5% and an overall rate of
return of 7.78% with a capital structure of 50% common
equity and 50% long-term debt. These customer rates went
into effect on November 1, 2012, with annual revenue
requirements increasing by $8.7 million or 1.2%. However,
this increase included the recovery of amounts that had
previously been deferred through the Company's
decoupling mechanism of about $15 million. As a result, the
overall effect on the Company was a decline in utility margin
of approximately $6 million on an annualized basis.
•
The following items were postponed by the Commission:
•
the request to include prepaid pension assets in rate
base and allow a return on and recovery of the asset
was denied; however, the OPUC indicated in the order
that it will open a docket to review the treatment of
pension expense on a general, non-utility-specific
basis. A docket has been opened and until a conclusion
is reached, the OPUC has authorized us to continue to
collect and defer pension costs as we have historically,
as outlined below;
the existing arrangement we use to share revenues
with customers from our Mist interstate storage
operations and optimization services was continued,
but a new docket will be opened to review the sharing
arrangement; and
the use of a new process to determine the appropriate
amounts of working gas inventory that we earn a return
on, and its corresponding rate of return. Included in the
rate decrease effective November 1, 2012 was a
reduction in margin of about $4 million related to
working gas inventory, which we have been authorized
to defer pending the outcome in a new docket.
•
In addition, to the items above, the earnings test for our new
SRRM will also be defined in a separate proceeding and a
prudence review will be performed. A decision on these
items is expected in 2013, with the working gas inventory
decision expected to be applied retroactively to November
1, 2012.
WASHINGTON. Our most recent general rate case in
Washington was in 2008, and in it the WUTC authorized
rates to customers based on an ROE of 10.1% and an
overall rate of return of 8.4% with a capital structure of 51%
common equity, 5% short-term debt, and 44% long-term
debt. These customer rates went into effect on January 1,
2009, with annual revenue requirements increased by $2.7
million or 3%.
FERC JURISDICTION. 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
27
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. This
includes gas prices under spot purchases as well as
contract supplies, gas prices hedged with financial
derivatives, gas prices from the withdrawal of storage
inventories, and the production of gas reserves, interstate
pipeline demand costs, the application of temporary rate
adjustments, which amortize balances of deferred
regulatory accounts, and the removal of temporary rate
adjustments effective for the previous year.
In October 2012, the OPUC authorized PGA rate changes
effective November 1, 2012. The effect of these rate
changes was to decrease the average monthly bills of
Oregon residential customers by about 7%. This was our
fourth consecutive year of PGA rate decreases, and
cumulatively our Oregon utility residential customer bills
have declined 26% since 2008.
In October 2012, the WUTC PGA rates were allowed to go
into effect on November 1, 2012. However, the WUTC also
ordered a continuing review of all Washington gas
companies' PGA filings. We do not anticipate any changes
to our PGA rates as filed; however, if the WUTC were to find
any of our hedges to be imprudent, rates could be adjusted
as a result of this review. The effect of the ordered PGA
rates was to decrease average monthly bills of Washington
residential customers by about 8%. This was our fourth
consecutive year of PGA rate decreases in Washington, and
cumulatively our Washington utility residential customer bills
have declined 34% since 2008.
Under the current PGA mechanism in Oregon, there is an
incentive sharing provision whereby we are required to
select each year either an 80% deferral or a 90% 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% or 10% of the difference
between actual and estimated gas costs, respectively.
Under the Washington PGA mechanism, we defer 100% of
the higher or lower actual gas costs, and those gas cost
differences are normally passed on to customers through
the annual PGA rate adjustment. See “Customer Credits for
Gas Cost Incentive Sharing” below for a discussion of our
utility’s early refund to customers of deferred gas cost
savings from November 1, 2011 through March 31, 2012.
In addition to the gas cost incentive sharing mechanism, we
are subject to an annual earnings review in Oregon to
determine if the utility is earning above its authorized ROE
threshold. If utility earnings exceed a specific ROE level,
then 33% of the amount above that level is required to be
deferred for refund to customers. Under this provision, if we
select the 80% deferral option, then we retain all of our
earnings up to 150 basis points above the currently
28
authorized ROE. If we select the 90% deferral option, then
we retain all of our earnings up to 100 basis points above
the currently authorized ROE. We selected the 90% deferral
option for the 2010-2011, 2011-2012 and 2012-2013 PGA
years. The ROE threshold is subject to adjustment annually
based on movements in long-term interest rates. For
calendar years 2010 and 2011, the ROE threshold after
adjustment for long-term interest rates was 11.02% and
10.92%, respectively. We refunded $0.2 million to
customers based on the 2010 utility earnings test, and
based on the recently approved PGA, we are refunding $0.7
million to customers based on the 2011 utility earnings test.
We do not expect to be subject to a refund for the 2012
earnings test year.
GAS RESERVES. In 2011 the OPUC approved the Encana
gas reserve transaction to provide long-term gas price
protection for our utility customers and determined that the
Company's costs under the agreement will be recovered,
plus a rate base return on our investment, on an ongoing
basis through our annual PGA mechanism, including the
regulatory deferral and incentive sharing process for the
commodity cost of gas. Gas produced from our interests is
sold by Encana at then prevailing market prices with
revenues from such sales, net of associated production
costs, credited to our cost of gas. Annually, a forecast is
established for the amounts related to costs, revenues, and
volumes expected, and any variances between forecasted
and actual results are subject to our PGA incentive sharing
in Oregon, up to a maximum variance of $10 million of
which 10% (or $1 million maximum) would be recognized in
current income. Annual variances in excess of $10 million,
both negative and positive, are deferred and passed
through to customers in full in future rates.
DECOUPLING. Decoupling 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.
The Oregon decoupling mechanism was reauthorized in the
Oregon general rate case with the difference between our
2003 baseline consumption and the consumption decided in
our 2012 general rate case being calculated within base
rates. The conservation tariff employs a use-per-customer
decoupling mechanism, which adjusts margin revenues to
account for the difference between actual and expected
customer volumes. 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 annual PGA filing. Baseline
consumption reflects forecasted customer consumption data
used in the Oregon general rate case. In Washington,
customer use is not covered by such a tariff. See “Business
Segments—Local Gas Distribution "Utility" Operations”
below.
WEATHER NORMALIZATION TARIFF. In Oregon, we have an
approved weather normalization mechanism, which is
applied to residential and commercial customer bills. 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 bills
between December and May 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. This weather
normalization mechanism was reauthorized in the 2012
Oregon general rate case without an expiration date.
Customers in Oregon are allowed to opt out of the weather
normalization mechanism, and as of December 31, 2012,
9% had opted out. We do not have a weather normalization
mechanism approved for Washington customers, which
account for about 10% of our utility volumes and revenues.
See “Business Segments—Local Gas Distribution "Utility"
Operations” below.
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,
among other things, 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. Since 2002, various laws
requiring minimum standards for integrity management
programs and SIPs for natural gas distribution pipelines
have been enacted. Most recently, in January 2012 the
“Pipeline Safety, Regulatory Certainty, and Job Creation Act
of 2011” was signed into law and requires increased civil
penalties for pipeline safety violations, improvements in
prevention programs for pipelines, and additional review
and analysis of various aspects of gas transmission lines.
We are working diligently with industry associations and
federal and state regulators to ensure our compliance with
the provisions of this new law.
The OPUC has approved specific accounting treatment and
cost recovery for our transmission pipeline integrity
management program, SIP, and the related rules adopted
by the U.S. Department of Transportation’s Pipeline and
Hazardous Materials Safety Administration (PHMSA) and
provided a two-year extension of our capital expenditure
tracking mechanism to recover capital costs related to SIP.
We record the costs related to the integrity management
program as either capital expenditures or regulatory assets,
accumulate the costs over each 12-month period, and
recover the revenue requirement associated with these
costs, subject to audit, through rate changes effective with
the Oregon annual PGA. 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 through 2014. We do
not have any special accounting or rate treatment for our
SIP costs incurred in the state of Washington.
ENVIRONMENTAL COSTS. The OPUC has authorized us to
defer environmental costs associated with certain named
sites and to accrue a carrying cost on amounts deferred,
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 accrual of carrying costs was extended
through January 2012. In January 2013, we filed a request
with the OPUC to continue our deferral of these
environmental costs. See Note 15 for further discussion of
our regulatory and insurance recovery of environmental
costs.
A new SRRM, authorized in the 2012 Oregon general rate
case, allows the Company to recover prudently incurred
environmental site remediation costs. This SRRM will allow
recovery of one-fifth of the Company's current and future
deferred expenses each year in rates on a rolling basis until
all such expenses are recovered, subject to an annual
prudence review. Recovery of these incurred costs will also
be subject to an earnings test, which has not yet been
defined but a docket has been opened on the matter. This
earnings test could include deadbands, or other limitations
based on our earnings in a year, which could reduce the
amounts we are allowed to recover. At this time, the OPUC
has not ruled on how this separate earnings test will
function.
The WUTC has also authorized the deferral of
environmental costs, if any, that are appropriately charged
to Washington customers. This order was effective January
26, 2011 with cost recovery and a carrying charge to be
determined in a future proceeding. A decision regarding
allocation of costs to each state is pending. See Note 15 for
further discussion of our regulatory and insurance recovery
of environmental costs.
PENSION COST DEFERRAL. Effective January 1, 2011, the
OPUC approved our request to defer annual pension
expenses above the amount set in rates, with recovery of
these deferred amounts through the implementation of a
balancing account, which includes the expectation of higher
and lower pension expenses in future years. Our recovery
of these deferred balances includes accrued interest on the
account balance at the utility’s authorized rate of return,
which is currently 7.78%. Future years’ deferrals will depend
on changes in plan assets and projected benefit liabilities
based on a number of key assumptions, and our pension
contributions. See “Application of Critical Accounting
Policies and Estimates,” below. As noted above, the
Company continues to seek rate treatment for amounts
invested in prepaid pension assets.
CUSTOMER CREDITS FOR GAS COST INCENTIVE
SHARING. For the period between November 1, 2011 and
March 31, 2012, our actual gas costs were significantly
lower than the gas costs currently embedded in customer
rates. As a result, our PGA incentive sharing mechanism
recorded 90% of gas cost savings during this period,
attributed to Oregon customers, and 100% of the savings
attributed to Washington customers, to a regulatory liability
account for credit to customers. Ordinarily, these credits
would be refunded in customer rates starting in November
under the next year’s PGA filing, but in April 2012 the
29
Company requested regulatory approval to immediately
refund $35.1 million and $4.2 million to our Oregon and
Washington customers, respectively, through billing credits.
These credits were approved, and we began crediting these
amounts to customer bills in June of 2012. See “Purchased
Gas Adjustment,” above.
•
operations and maintenance expense and depreciation
and amortization expense; and
a $2.7 million one-time tax charge related to the
Oregon general rate case. See "Application of Critical
Accounting Policies and Estimates—Regulatory
Accounting" below.
CUSTOMER CREDITS FOR GAS STORAGE SHARING. As we
are able and get approval from the OPUC and WUTC, we
credit amounts to both Oregon and Washington customers
as part of our regulatory incentive sharing mechanism
related to gas storage and asset management services of
pipeline capacity and gas storage at Mist. Generally
amounts are credited to Oregon customers in June and
credits are given to customers in Washington through their
annual PGA filing in November. See “Business Segments—
Gas Storage” below.
The following table presents the credits to customers:
In millions
2012
2011
2010
Oregon utility customer
credit
Washington utility
customer credit
$
9.2
$
12.5
$
11.0
0.8
0.9
1.2
Business Segments - Local Gas Distribution "Utility"
Operations
Our utility margin results are largely affected by customer
growth and, to a certain extent, by changes in volume due
to weather and customers’ gas usage patterns because a
significant portion of our utility margin is derived from natural
gas sales to residential and commercial customers. In
Oregon, we have a conservation tariff, which adjusts utility
margin up or down through deferred accounting to offset
changes resulting from increases or decreases in average
use by residential and commercial customers. We also have
a weather normalization tariff in Oregon, which adjusts
customer bills up or down to offset changes in utility margin
resulting from above- or below-average temperatures during
the winter heating season. Both mechanisms are designed
to reduce the volatility of our utility’s earnings and customer
charges. See “Regulatory Matters—Rate Mechanisms”
above.
Utility segment highlights include:
Dollars and therms in
millions, except EPS data
and as otherwise noted
2012
2011
2010
Utility net income
EPS - utility segment
$
$
55.1
2.05
$
$
60.5
2.26
$
$
66.3
2.49
Gas sold and delivered
(in therms)
Utility margin(1)
1,112
1,152
1,062
$
344.5
$
343.0
$
346.1
(1) See Utility Margin Table below for a reconciliation and additional
detail.
2012 COMPARED TO 2011. The primary factors contributing
to the $5.4 million or $0.21 per share decrease in net
income were as follows:
•
an $8.4 million increase in operating expenses,
excluding cost of gas, primarily due to higher
These factors were partially offset by:
•
a $1.6 million net increase in utility margin primarily due
to:
•
a $7.4 million one-time, pre-tax charge in 2011
related to the repeal of Senate Bill (SB) 408, which
did not reoccur in 2012;
a 0.9% increase in customers over last year;
a $3.4 million increase from the allowed return on
our gas reserves investment;
a $2.5 million increase in other margin
adjustments; and
a $1.7 million increase in contribution from our gas
cost incentive sharing mechanism.
•
•
•
•
These increases in margin were partially offset by a
$9.3 million decrease in our residential and commercial
margin primarily reflecting:
•
a $3.9 million decrease due to timing differences
from the new billing rate structure resulting from
the Oregon general rate case;
an $8.4 million decrease due to weather from the
following three items: (1) positive margin impact
realized in the second quarter of 2011 when colder
weather was not fully offset by our Oregon weather
normalization mechanism, (2) warmer weather
during 2012 in Washington, which does not have
normalization mechanisms in place, and (3) the
effect of warmer weather on margin for Oregon
customers that opt out of weather normalization;
and
a $0.5 million decrease in operating revenues
primarily due to rate case impacts including a
decrease in our authorized return on equity.
•
•
•
•
a $1.5 million decrease in utility interest expense due to
lower interest rates on both short-term and long-term
debt balances.
a $3.5 million decrease, excluding the $2.7 million one-
time tax charge mentioned above, in income taxes due
to lower pre-tax utility income.
Total utility volumes sold and delivered in 2012 decreased
3.5% over last year primarily due to the impact of warmer
weather on residential and commercial use.
2011 COMPARED TO 2010. The primary factors contributing
to the decrease in our utility segment net income of $5.8
million, or $0.23 per share, were as follows:
•
a reduction in utility margins of $14.9 million related to
the repealed Oregon legislative rule SB 408 on utility
income taxes paid, including a $7.4 million write-off in
2011 plus a $7.7 million revenue accrual recognized in
2010; and
a net gain of $6.1 million recognized in 2010 related to
a refund of property taxes plus accrued interest from a
favorable tax ruling.
•
30
These factors were partially offset by:
•
increases in residential and commercial customer utility
margins of $11.3 million, including the effects of
weather normalization and decoupling mechanisms;
a slight gain in industrial customer utility margins of
$0.2 million; and
an increase in gas cost incentive sharing of $0.5
million.
•
•
Total utility volumes sold and delivered in 2011 increased
9% over 2010 primarily due to the impact of colder weather
on residential and commercial use.
UTILITY MARGIN TABLE. The following table summarizes the composition of utility gas volumes and revenues for the years
ended December 31, 2012, 2011, and 2010. Certain prior year amounts in the following table have been reclassified to conform
with the current year’s presentation. These reclassifications reflect amounts moved into residential, commercial, and industrial
categories where such amounts were specifically attributable to that customer category. Utility volumes and margin in total were
not affected by these reclassifications.
In thousands, except degree day and customer data
2012
2011
2010
Favorable/(Unfavorable)
2012 vs.
2011
2011 vs.
2010
Utility volumes - therms:
Residential and commercial sales
Industrial sales and transportation
637,885
473,884
681,621
470,733
596,543
465,426
(43,736)
3,151
Total utility volumes sold and delivered
1,111,769
1,152,354
1,061,969
(40,585)
85,078
5,307
90,385
Utility operating revenues - dollars:
Residential and commercial sales
Industrial sales and transportation
Regulatory adjustment for income taxes paid(1)
Other revenues
Less: Revenue taxes
Total utility operating revenues
Less: Cost of gas
Utility margin
Utility margin:(2)
Residential and commercial sales
Industrial sales and transportation
Miscellaneous revenues
Gain from gas cost incentive sharing
Other margin adjustments
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
Percent colder (warmer) than average weather(3)
$ 642,337
$
744,355
$ 696,439
$ (102,018)
$ 47,916
70,020
—
5,935
18,430
699,862
355,335
$ 344,527
$ 306,382
$
$
81,313
(7,162)
3,713
20,741
801,478
458,508
82,300
(11,293)
(987)
7,721
4,173
19,991
770,642
424,494
7,162
2,222
(2,311)
(101,616)
(103,173)
(14,883)
(460)
750
30,836
34,014
342,970
$ 346,148
$
1,557
$
(3,178)
315,688
$ 304,371
$
(9,306)
$ 11,317
28,586
28,635
28,451
4,452
3,811
1,296
—
4,875
2,107
(1,173)
(7,162)
4,658
1,594
(647)
7,721
(49)
(423)
1,704
2,469
7,162
184
217
513
(526)
(14,883)
$ 344,527
$
342,970
$ 346,148
$
1,557
$
(3,178)
621,399
63,619
923
685,941
4,152
615,670
610,598
5,729
5,072
62,948
925
62,489
910
671
(2)
459
15
679,543
673,997
6,398
5,546
4,652
4,171
(3)%
9%
(2)%
(1) Regulatory adjustment for income taxes paid is described below.
(2) Amounts reported as margin for each category of customers are operating revenues, which are net of revenue taxes, less cost of gas.
(3) Average weather represents the 25-year average degree days, as determined in our Oregon general rate case. For 2012, average weather
represents degree days based on the 25-year average that was set in our 2003 Oregon general rate for the months of January through
October, plus the new 25-year average set in the 2012 Oregon general rate case for the months of November and December. For the years
2011 and 2010, average weather represents the 25-year average degree days as set in our 2003 Oregon general rate case.
31
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% 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 utility
margin and net income is significantly reduced due to our
weather normalization mechanism in Oregon. For more
information on our weather mechanism, see “Regulatory
Matters—Rate Mechanisms—Weather Normalization Tariff”
above.
Residential and commercial sales highlights include:
In millions
Volumes - therms:
Residential sales
Commercial sales
Total volumes
Operating revenues:
2012
2011
2010
395.5
242.4
637.9
424.9
256.7
681.6
368.7
227.8
596.5
Residential sales
$
428.5
$
497.2
$
463.7
Commercial sales
213.8
247.2
232.7
Total operating
revenues
Utility margin:
Residential:
Sales
Weather normalization
Decoupling
Total residential utility
margin
Commercial:
Sales
Weather normalization
Decoupling
Total commercial utility
margin
$
642.3
$
744.4
$
696.4
$
211.6
$
222.5
$
197.0
(0.1)
8.6
(10.2)
16.7
10.5
13.1
220.1
229.0
220.6
84.0
0.2
2.1
86.3
87.0
(2.9)
2.6
86.7
77.8
3.5
2.4
83.7
•
•
•
an $8.4 million decrease due to the following
weather impacts: (1) a $3.0 million of positive
margin impact realized in the second quarter of
2011 when colder weather was not fully offset by
our Oregon weather normalization mechanism, (2)
a $3.2 million decrease due to warmer weather in
Washington, which does not have normalization
mechanisms in place, and (3) a $2.2 million
decrease due to the effect of warmer weather on
margin for Oregon customers that opt out of
weather normalization;
a $0.5 million decrease in operating revenues
primarily due to rate case impacts including a
decrease in our authorized return on equity; and
a $3.4 million margin increase from our gas
reserves investment.
2011 COMPARED TO 2010. The primary factors contributing
to changes in the residential and commercial markets were
as follows:
•
sales volumes increased 85.1 million therms, or 14%,
primarily reflecting 12% colder weather;
operating revenues increased $47.9 million, or 7%,
primarily due to the 14% volume increase; and
utility margin increased $11.3 million, or 4%, primarily
due to customer growth of 0.8% and colder weather,
with colder weather benefits partially offset by weather
normalization adjustments.
•
•
Industrial Sales and Transportation
Operating revenues from industrial customers include the
commodity cost component of gas sold under sales service
but not under transportation service. Therefore, operating
revenues from industrial customers can increase or
decrease when customers switch between sales service
and transportation service, but generally our margins from
these customers are unaffected by these changes because
we do not typically include a profit mark-up for the cost of
gas. As such, we believe volumes delivered and margins
are better measures of performance for the industrial sector.
Industrial sales and transportation highlights include:
In millions
Volumes - therms:
2012
2011
2010
Total utility margin
$
306.4
$
315.7
$
304.3
Industrial - firm sales
34.9
37.6
37.1
2012 COMPARED TO 2011. The primary factors contributing
to changes in the residential and commercial markets were
as follows:
•
sales volumes decreased 43.7 million therms, or 6%,
primarily reflecting 11% warmer weather;
operating revenues decreased $102.0 million, or 14%,
due to a 6% decrease in sales volumes, a 7% decrease
in average gas prices, which flowed through the
Company's PGA rates, and $36.2 million of credits on
customers’ bills in 2012 related to the refund of gas
cost savings; and
utility margin decreased $9.3 million, or 3%, primarily
reflecting the following:
•
a $3.9 million decrease due to timing differences
from the new billing rate structure resulting from
the Oregon general rate case;
•
•
Industrial - firm
transportation
Industrial - interruptible
sales
Industrial - interruptible
transportation
Total volumes
Utility margin:
Industrial - sales and
transportation
131.2
133.0
130.1
59.6
59.1
58.4
248.2
473.9
241.0
470.7
239.8
465.4
$
28.6
$
28.6
$
28.5
2012 COMPARED TO 2011. The primary factors contributing
to changes in the industrial sales and transportation markets
were as follows:
•
sales volumes increased 3.2 million therms, or 1%,
primarily reflecting the impact of customers switching to
natural gas due to the lower prices of natural gas
compared to oil; and
32
•
utility margin remained flat primarily reflecting the loss
of a few large industrial customers in 2011 due to the
economy. Partially offsetting this decrease was an
increase in customers switching to natural gas
throughout 2012 due to its price advantage.
2011 COMPARED TO 2010. The primary factors contributing
to changes in the industrial sales and transportation markets
were as follows:
•
sales volumes increased 5.3 million therms, or 1%,
primarily reflecting increased energy demand, with the
majority of the increased volumes attributable to the
manufacturing sector; and
utility margin increased $0.2 million reflecting an
increase in industrial use of natural gas as a result of
higher costs for oil and propane fuels, which caused
some customers to switch to natural gas. Partially
offsetting this trend was the loss of a few large
industrial customers due to the economy.
•
Regulatory Adjustment for Income Taxes Paid
SB 408 was in effect from 2007 through 2010 and was a
regulatory mechanism for truing up income taxes paid. In
May 2011, SB 967 effectively repealed the SB 408
regulatory adjustment for income taxes paid for the 2010 tax
year and all years thereafter. For the 2010 tax year, we had
originally estimated and accrued $7.1 million. Due to the
repeal, the Company recorded a $7.4 million write-off
including interest. Results related to SB 408 for 2011 were a
pre-tax loss of $7.4 million, compared to a pre-tax gain of
$7.7 million in 2010. For additional information, see
“Application of Critical Accounting Policies and Estimates—
Revenue Recognition” below.
Other Revenues
Other revenues include miscellaneous fee income as well
as regulatory revenue adjustments, which reflect current
period deferrals to and prior year amortizations from
regulatory asset and liability accounts, except for gas cost
deferrals which flow through cost of gas. Decoupling
amortizations and other regulatory amortizations from prior
year deferrals are included in current or future revenues
from residential, commercial and industrial firm customers.
Other revenue highlights include:
Cost of Gas
Cost of gas as reported by the utility 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, production from gas reserves and
company gas use. The OPUC and WUTC generally require
natural gas commodity costs to be billed to customers at the
actual cost incurred, or expected to be incurred, by the
utility. Customer rates are set each year so that if cost
estimates were met we would not earn a profit or incur a
loss on gas commodity purchases; however, in Oregon we
have an incentive sharing mechanism whereby we either
increase or decrease margin results based on a percentage
of actual gas costs as compared to embedded gas costs in
the PGA. Under this provision, our net income can be
affected by differences between actual and expected gas
costs, which occur primarily because of market fluctuations
and volatility affecting unhedged gas purchases in the PGA.
In addition, we entered into a regulatory agreement where
we earn a rate base return on our investment in gas
reserves, which is reflected in utility margin. See
“Regulatory Matters—Rate Mechanisms—Purchased Gas
Adjustment and Gas Reserves” above.
We use natural gas commodity-based hedge contracts
(derivative instruments), primarily fixed-price commodity
swaps, consistent with our financial derivatives policies to
help manage our exposure to rising gas prices. Gains and
losses from these financial hedge contracts are generally
included in our PGA prices and normally do not impact net
income because the hedged prices are reflected in our
annual rate changes, subject to a regulatory prudence
review. However, hedge contracts entered into after the
annual PGA rates are set in Oregon can impact net income
because we would be required to share in any gains or
losses as compared to the corresponding commodity prices
built into rates in the PGA. In Washington, 100% 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” below, “Regulatory
Matters—Rate Mechanisms—Purchased Gas Adjustment”
above, and Note 13.
In millions
2012
2011
2010
Cost of gas highlights include:
Other operating revenues
$
5.9
$
3.7
$
4.2
2012 COMPARED TO 2011. The primary factors contributing
to changes in other revenues were as follows:
•
other revenues increased $2.2 million primarily due to a
net increase in revenues from various regulatory
adjustments of approximately $2.7 million, partially
offset by a decrease of $0.4 million of miscellaneous
fee income.
2011 COMPARED TO 2010. The primary factor contributing to
the change in other revenues was as follows:
•
other revenues decreased $0.5 million primarily due to
a net decrease in revenues from various regulatory
adjustments in 2011.
Dollars and therms in
millions
2012
2011
2010
Cost of gas
$
355.3
$
458.5
$
424.5
Total volumes sold and
delivered (therms)
Average cost of gas
(cents per therm)
Total hedge loss
Gain from gas cost
incentive sharing
1,112
1,152
1,062
$
$
0.54
70.2
3.8
$
0.59
56.5
2.1
0.61
61.0
1.6
2012 COMPARED TO 2011. The primary factors contributing
to changes in cost of gas were as follows:
•
cost of gas decreased $103.2 million, or 23%, including
the $37.7 million of credits applied to customer billings
in 2012 related to the refund of gas cost savings.
Excluding the customer credits, total cost of gas
33
•
•
decreased $65.5 million, or 14%, primarily reflecting
lower usage due to 11% warmer weather and PGA rate
decreases in 2012 and 2011;
average cost of gas collected through rates decreased
5 cents per therm, primarily reflecting lower gas prices
that were passed on to customers through PGA rate
decreases effective November 1, 2011 and 2012; and
hedge losses realized and included in cost of gas
increased $13.7 million, or 24%. Since the underlying
hedge prices were included in our PGA billing rates,
these losses did not impact margin or net income.
2011 COMPARED TO 2010. The primary factors contributing
to changes in cost of gas were as follows:
•
cost of gas increased $34.0 million, or 8%, due to a 9%
increase in total sales volumes on 12% colder weather,
partially offset by a 4% decrease in the average cost of
gas per therm;
average cost of gas collected through rates decreased
2 cents per therm, primarily reflecting lower gas prices
that were passed on to customers through PGA rate
decreases effective November 1, 2010 and 2011; and
hedge losses realized and included in cost of gas
decreased $4.5 million, or 7%. As stated above, the
underlying hedge prices were included in our PGA
billing rates; therefore, these losses did not impact
margin or net income.
•
•
Actual gas costs in 2012, 2011, and 2010 were below those
embedded in rates. The effect on shareholders from the gas
cost incentive sharing mechanism was a contribution to
margin of $3.8 million in 2012, $2.1 million in 2011, and $1.6
million in 2010. For a discussion of our gas cost incentive
sharing mechanism, see “Regulatory Matters—Rate
Mechanisms—Purchased Gas Adjustment” above.
Business Segments - Gas Storage
Our gas storage segment primarily consists of the non-utility
portion of our Mist underground storage facility in Oregon
and our 75% ownership interest in the Gill Ranch
underground storage facility in California.
At Mist, we provide gas storage services to customers in the
interstate and intrastate markets primarily using storage
capacity that has been developed in advance of core utility
customers’ requirements. We also contract with an
independent energy marketing company to provide asset
management services using our utility and non-utility
storage and transportation capacity, the results of which are
included in the gas storage business segment. Pre-tax
income from gas storage at Mist and third-party
management services using our utility's storage or
transportation capacity is subject to revenue sharing with
core utility customers. Under this regulatory incentive
sharing mechanism in Oregon, we retain 80% of pre-tax
income from Mist gas storage services and from asset
management services when the underlying costs of the
capacity being used are not included in our utility rates, and
33% of pre-tax income from such storage and asset
management services when the capacity being used is
included in utility rates. The remaining 20% and 67%,
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 asset management services.
Our 75% undivided ownership interest in the Gill Ranch
facility is held by our wholly-owned subsidiary Gill Ranch,
which is also the operator of the facility. Our portion of the
facility is currently providing 15 Bcf of gas storage capacity.
Gill Ranch commenced operations at the end of 2010, with
the first full storage injection season beginning on April 1,
2011. We also contract with an independent energy
marketing company to manage the value of our storage
assets at the Gill Ranch gas storage facility. See Note 4.
Gas storage segment highlights include:
In millions, except EPS
data
2012
2011
2010
Gas storage net income
$
4.5
$
4.1
$
6.1
EPS - gas storage
segment
0.17
0.15
0.23
2012 COMPARED TO 2011. The primary factors contributing
to changes in our gas storage segment were as follows:
net income increased $0.4 million primarily due to
•
revenue increases at Gill Ranch from additional
contracted storage capacity. This increase was partially
offset by a full year of interest expense from Gill
Ranch's senior secured debt, which was issued in
November 2011.
2011 COMPARED TO 2010. The primary factors contributing
to changes in our gas storage segment were as follows:
•
net income decreased $2.0 million primarily due to a
combination of lower storage and asset management
revenues driven by lower gas prices and less market
volatility.
Business Segments - Other
Our other business segment consists primarily of NNG
Financial's investment in the Kelso-Beaver (KB) Pipeline, an
equity investment in PGH, which in turn has invested in a
cross-Cascade pipeline project, and other miscellaneous
non-utility investments and business activities.
Other business highlights include:
In millions, except EPS data
2012
2011
2010
Assets:
NNG Financial
PGH investment
Net income metrics:
$
1.1
$
1.1
$
13.4
13.5
Other net income (loss)
$
0.2
$
(0.7) $
EPS - other segment
—
(0.02)
1.1
14.8
0.3
0.01
2012 COMPARED TO 2011. The primary factors contributing
to changes in our other business segment were as follows:
total assets at NNG Financial remained flat, primarily
•
reflecting no change in our non-controlling minority
interest in the KB interstate gas transmission pipeline;
our equity investment in PGH remained relatively flat;
and
net income increased $0.9 million as our investment in
PGH had a $1.3 million impairment charge in 2011,
which did not reoccur in 2012.
•
•
2011 COMPARED TO 2010. The primary factors contributing
to changes in our other business segment were as follows:
34
•
•
•
total assets at NNG Financial remained flat, primarily
reflecting no change in our non-controlling minority
interest in the KB interstate gas transmission pipeline;
our equity investment in PGH reflected an
approximately $1.3 million charge taken in 2011; and
net income decreased $1.0 million primarily due an
approximately $1.3 million charge on our investment in
PGH. See Note 12.
Consolidated Operations
Operations and Maintenance
Operations and maintenance highlights include:
In millions
2012
2011
2010
Operations and maintenance
$ 129.5
$ 125.4
$ 121.0
2012 COMPARED TO 2011. Operations and maintenance
expense increased $4.1 million or 3% in 2012 compared to
2011. The following summarizes the major factors that
contributed to this increase:
•
a $3.7 million increase in utility payroll expense primarily
related to an increase in field service employees;
a $1.7 million increase in utility non-payroll expense
including higher costs for new employee training,
expenses related to the Oregon general rate case, higher
costs for information technology system maintenance and
other general customer service cost increases; and
a $0.9 million increase in utility employee benefit expense,
principally related to health care and pension costs, which
were driven by an increase in employee count. See below
for additional discussion on pension costs.
•
•
Partially offsetting the above factors were:
•
a $1.1 million reduction in gas storage general and
administrative expense primarily reflecting lower costs
compared to 2011 when Gill Ranch incurred higher start-
up costs; and
a $0.8 million decrease in utility bad debt expense.
•
2011 COMPARED TO 2010. Operations and maintenance
expense increased $4.3 million or 4% in 2011 compared to
2010. The following summarizes the major factors that
contributed to this increase:
•
a $3.2 million increase in operating expenses at Gill
Ranch related to the first full year of operations;
a $2.3 million increase in utility payroll expense related
to additional field support staff and general pay increases;
a $1.2 million increase in utility health care costs and other
related employee benefit expense;
a $1.5 million increase in other non-payroll expense at
the utility for costs related to the general rate case of $0.7
million, storage leases of $0.3 million, and pipeline
integrity and corporate ethics initiatives of $0.2 million;
and
a $0.2 million increase in utility bad debt expense (see
further discussion below).
Partially offsetting the above factors were:
•
a $1.8 million decrease in performance bonuses at the
utility based on below-target results compared to last
year;
a $1.5 million decrease in pension expense due to the
regulatory deferral of costs above the amount net in rates
(see further discussion below); and
•
•
•
•
•
•
a $1.0 million decrease in specific consulting and legal
fees which were incurred by the utility in 2010 related to
our successful property tax appeal.
Our bad debt expense as a percent of revenues was 0.15%
for the year ended December 31, 2012, compared to 0.23%
in 2011. Our bad debt expense decreased in 2012 partially
due to the positive impact of customer refunds on
delinquent balances during the period. Our bad debt
expense results continue at historically low levels for the
Company despite challenging economic conditions in recent
years. We believe credit risks are still somewhat elevated
due to the continuing weak economy and high
unemployment rates, but we expect our bad debt expense
ratio over the long term to remain below 0.5% of revenues.
Our accounting expense for pension costs increased in
2012 largely due to lower discount rates; however, the
OPUC approved a deferral of our utility pension costs for
amounts in excess of what is currently recovered in
customer rates. The pension cost deferral is recorded to a
regulatory balancing account, which reduces operations and
maintenance expense. For the year ended December 31,
2012 and 2011, we deferred pension expenses totaling $7.9
million and $6.0 million, respectively. See Note 8. As a
result, increased pension costs had a minimal effect on
operations and maintenance expense in 2012 and 2011,
with the increase principally related to the cost allocation to
our Washington operations, which are not covered by the
pension balancing account. For further explanation of the
pension balancing account, see “Regulatory Matters—Rate
Mechanisms—Pension Deferral” above.
General Taxes
General taxes are principally comprised of property and
payroll taxes and regulatory fees.
General tax highlights include:
In millions
General taxes
2012
2011
2010
$
30.6
$
29.3
$
23.9
2012 COMPARED TO 2011. General taxes increased $1.3
million or 4% in 2012 compared to 2011 primarily due to a
$0.7 increase in property taxes at Gill Ranch, which reflect
increased capital investments added to assessed property
tax values duri
ng 2012, as well as a $0.4 increase in payroll tax expense
at the utility.
2011 COMPARED TO 2010. General taxes increased $5.4
million or 23% in 2011 compared to 2010. The major factors
that contributed to the increase are:
•
a $5.2 million increase due to a refund of property taxes
in 2010, which did not reoccur in 2011. See discussion
below; and
a $1.3 million increase in property taxes at Gill Ranch
as a result of the first full year of operations.
•
In 2010, as a result of successful litigation with the Oregon
Department of Revenue (ODOR) regarding property taxes
on inventories held for sale, we recognized a net $6.1
million increase in pre-tax income. This increase consisted
of a $5.2 million property tax refund, $1.9 million of accrued
35
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 in
2010.
Depreciation and Amortization
Depreciation and amortization highlights include:
In millions
2012
2011
2010
Depreciation and amortization
$
73.0
$
70.0
$
65.1
2012 COMPARED TO 2011. Depreciation and amortization
expense for 2012 increased by $3.0 million compared to
2011 primarily due to $2.7 million increase in utility
depreciation expense on investments in utility plant for
system improvements and training facilities.
2011 COMPARED TO 2010. Depreciation and amortization
expense increased $4.9 million in 2011 over 2010 primarily
due to an increase of $3.7 million in Gill Ranch’s
depreciation, plus additional depreciation on investments in
utility plant for customer growth and system improvements.
Other Income and Expense, Net
Other income and expense, net highlights include:
In millions
2012
2011
2010
Gains from company-
owned life insurance
$
Interest income
Income (loss) from equity
investments
Net interest on deferred
regulatory accounts
Gain (loss) on sale of
investments
Other non-operating
Total other income and
expense, net
2.3
0.2
—
4.8
(0.2)
(2.2)
$
$
2.2
0.1
(1.6)
6.0
(0.1)
(2.1)
2.0
2.0
0.6
4.7
0.2
(2.4)
$
4.9
$
4.5
$
7.1
2012 COMPARED TO 2011. The $0.4 million increase in other
income and expense, net for 2012 compared to 2011 was
primarily due to a $1.3 million loss from our equity
investment in PGH in 2011, which did not reoccur in 2012.
This increase was partially offset by $1.2 million of lower
interest from net regulatory account balances, which
reflected lower average regulatory account balances in
2012 due to environmental insurance recoveries received at
the end of 2011 as well as accumulated gas cost savings
from November 2011 through June 2012. The Company’s
refund of gas cost savings increased the regulatory account
balances, which resulted in higher interest in the second
half of 2012 compared to the first half of 2012. See
discussion of Palomar in “Strategic Opportunities—Pipeline
Diversification” above and in Note 12.
2011 COMPARED TO 2010. The $2.6 million decrease in other
income, net for 2011 compared to 2010 was primarily due to
$1.9 million of interest income received from the property
tax refund in 2010, which did not occur in 2011, and a $1.4
million loss from equity investments due to Palomar
charges, partially offset by a $1.3 million increase in interest
and carrying costs from regulatory account balances largely
36
due to smaller balances in gas costs between 2011 and
2010.
Interest Expense, Net
Interest expense, net highlights include:
In millions
2012
2011
2010
Interest expense, net
$
43.2
$
42.1
$
42.6
2012 COMPARED TO 2011. Interest expense, net of amounts
capitalized, in 2012 increased $1.1 million primarily due to a
$2.8 million increase in interest expense at Gill Ranch from
the issuance of $40 million of subsidiary senior secured
debt in November 2011, partially offset by a $1.5 million
decrease in interest expense at the utility due to lower
interest rates on new short-term and long-term debt
issuances.
2011 COMPARED TO 2010. Interest expense, net of amounts
capitalized, in 2011 decreased by $0.5 million compared to
2010. The decrease was primarily due to $1.9 million of
savings in interest expense on long-term debt as a result of
bonds that were redeemed in 2010, partially offset by a $1.1
million increase for gas storage interest expense related to
the Gill Ranch base gas agreement, as well as the issuance
of $50 million of 3.176% Company first mortgage bonds
(FMBs) in September 2011 and the issuance of $40 million
of subsidiary senior secured debt with an average interest
rate of 7.38% for Gill Ranch in November 2011.
Interest expense also reflects a lower average interest rate
used in calculating the allowance for funds used during
construction (AFUDC). AFUDC rates, comprised of short-
term and long-term capital costs as appropriate, were 0.3%
in 2012, 0.5% in 2011 and 0.6% in 2010.
Income Tax Expense
Income tax expense highlights include:
In millions
2012
2011
2010
Income tax expense
$ 44.1
$ 43.4
$ 49.5
Effective tax rate
42.4%
40.4%
40.5%
2012 COMPARED TO 2011. The increase in income tax
expense of $0.7 million or 2% and the increase in the
effective tax rate was primarily due to a one-time $2.7
million tax charge related to the Oregon general rate case.
This increase in taxes was partially offset by lower pre-tax
consolidated earnings.
2011 COMPARED TO 2010. The decrease in income tax
expense of $6.1 million, or 12% was primarily due to lower
pre-tax consolidated earnings.
EFFECTIVE TAX RATES. For the 2012 tax year, the higher
effective tax rate was primarily due to the $2.7 million tax
charge related to the Oregon general rate case. For the
2011 tax year, the lower effective tax rate was primarily due
to a decrease in state tax expense from Measure 67. 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—Application of Critical Accounting Policies and
Estimates,” below) and a lower non-taxable gain on
company-owned life insurance. For more information on our
income taxes, including a reconciliation between the
statutory federal and state income tax rates and the
effective rate, see Note 2 and Note 9.
For the 2012 tax year, we have stated our deferred tax
expense using an estimated blended state tax rate that
takes into account different tax rates, tax brackets, and state
apportionment that impact our estimated future state income
tax liabilities.
FINANCIAL CONDITION
Capital Structure
One of our long-term goals is to maintain a strong
consolidated capital structure, generally consisting of 45%
to 50% common stock equity and 50% to 55% 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 of capital are also used to fund long-term debt
retirements and short-term commercial paper maturities.
See “Liquidity and Capital Resources” below and Note 7.
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:
Common stock equity
Long-term debt
Short-term debt, including current
maturities of long-term debt
Total
December 31,
2012
2011
45.4%
46.5%
42.8
11.8
41.7
11.8
100.0%
100.0%
Liquidity and Capital Resources
At December 31, 2012, we had $8.9 million of cash and
cash equivalents compared to $5.8 million at December 31,
2011. We also had $4.0 million in restricted cash at Gill
Ranch as of both December 31, 2012 and 2011, which is
being held as collateral for its long-term debt outstanding. In
order to maintain sufficient liquidity during periods when
capital markets are volatile, we may elect to maintain higher
cash balances and add short-term borrowing capacity. In
addition, we may also pre-fund utility capital expenditures
when long-term fixed rate environments are attractive. As a
regulated entity, our issuance of equity securities and most
forms of debt securities are subject to approval by the
OPUC and WUTC, and our use of proceeds from utility
specific issuances are restricted to certain utility purposes.
Our use of retained earnings is not subject to those same
restrictions.
For the utility segment, our short-term liquidity is supported
by cash balances, internal cash flow from operations,
proceeds from the sale of commercial paper notes,
borrowings from 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 utility long-term debt proceeds to finance utility capital
37
expenditures, refinance maturing debt of the utility and
provide for general corporate purposes of the utility.
Current market conditions are better than the past few years
as reflected by tighter credit spreads and increased access
to financing for investment grade issuers. Based on our
current debt ratings (see “Credit Ratings” below), we have
been able to issue commercial paper and long-term debt at
attractive rates and have not needed to borrow from our
back-up credit facility. In the event that we are not able to
issue new debt due to market conditions, we expect that our
near term liquidity needs can be met by using cash
balances or, for the utility segment, drawing upon our
committed credit facility. We also have a universal shelf
registration filed with the SEC for the issuance of secured
and unsecured debt or equity securities, subject to market
conditions and certain regulatory approvals. As of
December 31, 2012, we had OPUC approval to issue up to
$75 million of additional long-term debt under the existing
shelf registration for approved purposes.
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 increases in short-term borrowings. If the credit risk-
related contingent features underlying these contracts were
triggered on December 31, 2012, we could have been
required to post $1.6 million of collateral to our
counterparties, assuming our long-term debt ratings were at
non-investment grade levels, which would be a very
significant change from current rating levels for NW Natural.
See Note 13 and “Credit Ratings” below.
In July 2010, the U.S. Congress passed and President
Obama signed into law the “Dodd-Frank Wall Street Reform
and Consumer Protection Act” (Dodd-Frank Act or DFA).
The legislation established a new statutory framework for
the comprehensive regulation of financial institutions that
participate in the swaps market and, among other things,
requires additional government regulation of derivative and
over-the-counter transactions and expanded collateral
requirements. The Company is not currently subject to
regulation as a Swap Dealer under the DFA nor do we
expect that it will be in the future based on current or as yet
unfinalized rules. Further, we believe we are eligible for and
have taken appropriate steps to be exempt from certain
reporting obligations under the DFA. We will continue to
monitor interpretations and Commodity Futures Trading
Commission guidance to determine the impact, if any, on
our hedging policies, procedures, results of operations,
financial position and liquidity.
Other recent developments that may have a significant
impact on our liquidity and capital resources include pension
contribution requirements, tax benefits and liabilities,
environmental expenditures and insurance recoveries, and
customer refunds of gas cost savings.
With respect to pensions, we expect to make significant
contributions to our company-sponsored defined benefit
plan, which is closed to new employees, over the next
several years until we are fully funded under the Pension
Under the debt agreements, Gill Ranch is subject to certain
covenants and restrictions, including but not limited to a
financial covenant that requires Gill Ranch to maintain
minimum adjusted earnings before interest, taxes,
depreciation, and amortization (EBITDA) at various levels
over the term of the debt. The minimum adjusted EBITDA
increases incrementally over the first few years, reaching its
highest level in the 12-month period beginning April 1, 2015.
Under the agreements, Gill Ranch is also subject to a debt
service reserve requirement of 10% of the outstanding
principal amount, initially $4 million, certain prepayment
penalties, restrictions on dividends out of Gill Ranch unless
certain earnings ratios are met, and restrictions on the
incurrence of additional debt. As of and for the year ended
December 31, 2012, we were in compliance with all
covenants and restrictions under the debt agreements.
Based on several factors, including our current credit
ratings, our commercial paper program, current cash
reserves, committed credit facilities, and our expected ability
to issue long-term debt in the capital markets, we believe
our liquidity is sufficient to meet anticipated near-term cash
requirements, including all contractual obligations, investing
and financing activities discussed below.
Dividend Policy
We have paid quarterly dividends on our common stock
each year since 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 at 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, we
have no material off-balance sheet financing arrangements.
See “Contractual Obligations” below.
Protection Act rules, including the new rules issued under
the MAP-21 Act. See "Application of Critical Accounting
Policies—Accounting for Pensions and Postretirement
Benefits" below.
With respect to federal income tax liabilities, extensions
have been granted allowing us to take 100% bonus
depreciation on qualified expenditures during 2011 and 50%
bonus depreciation on a majority of our capital expenditures
in 2012 and 2013, which significantly reduces our tax
liability for those tax years and is expected to provide cash
flow benefits in subsequent years.
With respect to environmental expenditures, we expect to
continue using cash resources to fund our environmental
liabilities, but we also anticipate recovering amounts through
insurance and utility rates over the next several years,
although the amount and timing of these expenditures and
recoveries is uncertain. See Note 15, "Results of Operations
—Regulatory Matters—Environmental Costs" above.
With respect to customer refunds or credits, gas prices were
significantly lower than the gas prices embedded in
customer rates between November 1, 2011 and March 31,
2012. As a result, our PGA incentive sharing mechanism
deferred 90% of these gas cost savings attributed to
Oregon, and 100% of the savings attributed to Washington,
into a regulatory account for refund back to customers. See
"Results of Operations—Regulatory Matters—Regulatory
Mechanisms—Purchased Gas Adjustment” above.
Ordinarily, these refunds would be credited to customer
rates in the next year’s PGA filing, but in the second quarter
of 2012 the Company received regulatory approval to
immediately credit $35 million to Oregon customers and $4
million to Washington customers through billing credits. In
addition, the Company also received approval to provide its
Oregon utility customers with a $9 million interstate storage
credit from our regulatory incentive sharing mechanism
related to gas storage and asset management services.
These credits were applied to customer bills in June and
July of 2012.
Our gas storage segment’s short-term liquidity is supported
by cash balances, internal cash flow from operations,
external financing, and, to a certain extent, funding from its
parent company. Gill Ranch has limited operational history,
having begun operations in October 2010. Although we
anticipate operating cash flows to be sufficient for liquidity
purposes, the amount and timing of these cash flows are
uncertain. In November 2011, Gill Ranch issued $40 million
of senior secured debt, with a fixed interest rate on $20
million and a variable interest rate on the remaining $20
million. The average combined interest rate on the debt was
7.38% per annum through December 31, 2012. This debt is
secured by all of the membership interests in Gill Ranch and
is nonrecourse to NW Natural and other entities of the
consolidated group. The maturity date of the debt is
November 30, 2016.
38
Contractual Obligations
The following table shows our contractual obligations at December 31, 2012 by maturity and type of obligation:
In millions
Commercial paper
Long-term debt maturities
Interest on long-term debt
Postretirement benefit payments(1)
Capital leases
Operating leases
Gas purchases(2)
Gas pipeline capacity commitments
Gas reserves(3)
Other purchase commitments(4)
Other long-term liabilities(5)
Payments Due in Years Ending December 31,
2013
2014
2015
2016
2017
Thereafter
Total
$
190.3
$
— $
— $
— $
— $
— $
—
40.1
21.7
0.6
5.4
104.4
94.3
56.6
—
15.3
60.0
40.0
22.3
0.3
5.7
12.2
86.1
49.2
0.5
—
40.0
38.5
22.9
0.2
5.5
—
72.7
41.8
0.1
—
65.0
35.5
23.7
—
5.5
—
61.4
—
—
—
40.0
30.3
24.5
—
5.5
—
48.5
—
—
—
486.7
249.7
140.1
—
33.1
—
240.9
—
13.6
—
190.3
691.7
434.1
255.2
1.1
60.7
116.6
603.9
147.6
14.2
15.3
Total
$
528.7
$
276.3
$
221.7
$
191.1
$
148.8
$
1,164.1
$
2,530.7
(1)
The majority of these estimated postretirement benefit payments are related to our qualified defined benefit pension plans, which are funded
by plan assets and future cash contributions. See Note 8.
(2) Gas purchases include contracts which use price formulas tied to monthly index prices, plus hedged derivative liabilities. Commitment amounts
are based on futures prices as of December 31, 2012. For a summary of derivatives, see Note 13. For a summary of gas purchase and gas
pipeline capacity commitments, see Note 14.
(3) Gas reserves payments reflect contractual obligations to invest in additional gas reserves. The contracts for such reserves include termination
provisions, under which investments in additional reserves would not be required, if conditions for such provisions were met. We have assumed
no cancellation for disclosure of gas reserve commitments.
(4) Other purchase commitments primarily consist of base gas requirements and remaining balances under existing purchase orders.
(5) Other long-term liabilities includes accrued vacation liabilities for management employees and deferred compensation plan liabilities for
executives and directors. The timing of these payments are uncertain; however, these payments are unlikely to all occur in the next twelve
months.
In addition to known contractual obligations listed in the
above table, we have also recognized liabilities for future
environmental remediation or action. The exact timing of
payments beyond 12 months with respect to those liabilities
cannot be reasonably estimated due to numerous
uncertainties surrounding the course of environmental
remediation and the preliminary nature of site investigations.
See Note 15 for a further discussion of environmental
remediation cost liabilities.
At December 31, 2012, 623 of our utility employees were
members of the Office and Professional Employees
International Union (OPEIU) Local No. 11. In July 2009,
these union employees and the Company agreed to a new
five-year labor agreement called the Joint Accord. The Joint
Accord provides for a 1% automatic wage increase each
year, plus the potential for up to an additional 2% based on
wage inflation and other factors. It also provides competitive
health benefits while limiting the cost increases for these
benefits to the same level as the annual wage increases.
The current 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 purchases 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, 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. At
December 31, 2012 and 2011, our utility had commercial
paper outstanding of $190.3 million and $141.6 million,
respectively. The effective interest rate on the utility’s
commercial paper outstanding at December 31, 2012 and
2011 was 0.3%.
Credit Agreements
In December 2012, we entered into a new multi-year credit
agreement for unsecured revolving loans totaling $300
million with a maturity date of December 20, 2017 and an
available extension of commitments for two additional one-
year periods, subject to lender approval. Our prior $250
million agreement, dated May 31, 2007, was terminated
upon the closing of this new agreement. All lenders under
the new agreement are major financial institutions with
committed balances and investment grade credit ratings as
of December 31, 2012 as follows:
In millions
Lender rating, by category
Loan Commitment
$
$
123
177
—
300
AA/Aa
A/A
BBB/Baa
Total
39
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.
Our credit agreement allows us to request increases in the
total commitment amount, up to a maximum of $450 million.
The agreement also permits the issuance of letters of credit
in an aggregate amount of up to $200 million. Any principal
and unpaid interest amounts owed on borrowings under the
credit agreements is due and payable on or before the
maturity date. There were no outstanding balances under
this or our prior credit agreement at December 31, 2012 or
2011. Both the current and former credit agreement requires
us to maintain a consolidated indebtedness to total
capitalization ratio of 70% 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, 2012 and 2011, with consolidated
indebtedness to total capitalization ratios of 54.6% and
53.5%, respectively.
The agreement also requires us to 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 or senior secured debt
ratings, as applicable, by such rating agencies. A change in
our debt ratings by S&P or 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. In addition, interest rates on any loans
outstanding under the credit agreements are tied to debt
ratings and therefore a change in the debt rating would
increase or decrease the cost of any loans under the credit
agreements when ratings are changed. See “Credit Ratings”
below.
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. In December 2012, Moody's
downgraded our short-term debt rating from P-1 to P-2. In
February 2013, S&P upgraded our secured long-term first
mortgage bond rating from A+ to AA-. These changes have
not materially impacted our liquidity, access to the short-
term commercial paper markets, or our borrowing costs.
There were no other changes in our credit ratings during
2012.
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
Moody's
A-1
AA-
n/a
A+
P-2
A1
A3
n/a
Stable
Negative
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.
Retirements of Long-Term Debt
The following FMBs were retired:
In millions
Company First Mortgage Bonds
Years Ended December 31,
2012
2011
2010
4.11% Series B due 2010
$
— $
— $
7.45% Series B due 2010
6.665% Series B due 2011
7.13% Series B due 2012
—
—
40
40
$
—
10
—
10
$
$
10
25
—
—
35
Cash Flows
Operating Activities
Year-over-year changes in our operating cash flows are
primarily affected by net income, changes in working capital
requirements, and other cash and non-cash adjustments to
operating results.
Operating activity highlights include:
In millions
2012
2011
2010
Cash provided by operating
activities
$ 168.8
$ 233.5
$ 126.5
2012 COMPARED TO 2011. The significant factors
contributing to the $64.6 million decrease in operating cash
flow for 2012 compared to 2011 are as follows:
• a decrease of $38.1 million in deferred environmental
expenditures, net of recoveries, primarily due to insurance
recoveries for environmental claims received in 2011;
• a decrease of $30.9 million in taxes accrued, primarily due
to federal tax refunds totaling $36.6 million received in 2011;
and
• a decrease of $26.2 million from changes in the deferred
gas cost savings balance, which was reduced when
approximately $39 million was refunded to customers in
June and July 2012.
Partially offsetting these decreases was:
• an increase of $28.4 million from reductions in receivable
balances primarily due to higher receivable balances from
40
colder weather at the end of 2011, which were collected
early in 2012.
Also affecting cash flow from operating activities is the
amount of cash contributions made to the utility’s qualified
defined benefit pension plans. During the year ended
December 31, 2012, we contributed $23.5 million to these
plans, which was significantly higher than the $5.4 million in
non-cash expense recognized on the income statement. In
2011, we contributed $22.0 million and had $7.2 million in
non-cash expense. We expect pension contributions to
exceed non-cash expense for the next few years, but
contribution amounts will be less than previously anticipated
due to funding relief approved under the new MAP-21 Act in
July 2012. The amounts and timing of future contributions
will depend on market interest rates and investment returns
on the plans’ assets. See Note 8.
Also significantly affecting cash flows over the past few
years has been income tax relief, including the Tax Relief,
Unemployment Insurance Reauthorization, and Job
Creation Act of 2010 (the Tax Relief Act). The Tax Relief Act
allowed 100% bonus depreciation on qualified property
placed in service between September 9, 2010 through
December 31, 2011. It also extended the 50% bonus
depreciation deduction to qualifying property placed in
service during 2012. These and other tax benefits resulted
in a net operating tax loss for 2010, which was carried back
to the tax year 2009 and resulted in a federal income tax
refund of $22.3 million received in 2011 and an additional
$2.1 million received in 2012. We generated taxable income
in 2011 that was fully offset by net operating loss (NOL)
carried forward from 2010. We continued to generate NOL
carryforwards during 2012. As of December 31, 2012, we
had an estimated federal income tax receivable balance of
$2.3 million and an estimated NOL carryforward balance of
$83.4 million to 2013. In 2011, Oregon conformed with
federal bonus depreciation, contributing to a state NOL
carryforward of $76.6 million to 2013. We anticipate being
able to use the full amount of the both NOL carryforward
balances in future years prior to expiration. The NOLs would
otherwise expire in 20 years for federal and 15 years for
Oregon.
2011 COMPARED TO 2010. The significant factors
contributing to the $107.0 million increase in operating cash
flow for 2011 compared to 2010 are as follows:
•
an increase of $85.7 million from accrued taxes, primarily
related to bonus depreciation which resulted in federal
tax refunds of $36.6 in 2011 and a NOL carryforward;
an increase of $34.7 million from changes in deferred gas
costs, which reflects a higher level of gas cost savings
which will be refunded to utility customers in subsequent
years’ PGA;
an increase of $33.4 million from insurance recoveries for
environmental claims, net of deferred environmental
expenditures in 2011; and
an increase of $12.0 million from changes in accounts
payable due to decreased construction activity at Gill
Ranch.
•
•
•
Partially offsetting these increases was:
•
a decrease of $29.5 million from changes in deferred tax
liabilities primarily reflecting higher tax benefits in 2010
compared to 2011, largely driven by utility and Gill Ranch
41
•
•
bonus depreciation for investments placed in service
during 2010;
a decrease of $22.1 million from changes in receivables
primarily due to higher balances at the end of 2009, which
benefited cash flows in 2010; and
a decrease of $12.0 million from higher pension
contributions due to a decline in interest rates and asset
values, which increased pension funding requirements.
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
“Financial Condition—Contractual Obligations” above and
Note 14.
Investing Activities
Investing activity highlights include:
In millions
2012
2011
2010
Total cash used in investing
activities
Capital expenditures
Utility gas reserves
$ 184.7
$ 153.1
$ 212.9
132.0
54.1
100.5
50.6
248.5
—
2012 COMPARED TO 2011. The $31.6 million increase in cash
used in investing activities was due to higher capital
expenditures reflecting expenditures relating to a new utility
training and back-up emergency operations facility, and
several upgrades to existing building facilities. In addition,
we also invested additional monies in utility gas reserves.
2011 COMPARED TO 2010. The $59.8 million decrease in
cash used in investing activities was due to lower capital
expenditures primarily due to decrease in non-utility
construction activity in 2011 as our Gill Ranch facility was
primarily constructed in 2010. Offsetting this decrease was
our investment in utility gas reserves.
Over the five-year period 2013 through 2017, total utility
capital expenditures are estimated to be between $600 and
$700 million and utility expenditures under the existing gas
reserves agreement are estimated to be $150 million. The
estimated level of utility capital expenditures over the next
five years reflects assumptions for continued customer
growth, technology, distribution system improvements and
gas storage facilities. 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.
In 2013, we expect to spend between $10 and $15 million
on non-utility capital projects. Non-utility spend for gas
storage and other investments after 2013 will depend
largely on future decisions about potential expansion
opportunities in gas storage and pipeline projects. Gas
storage segment capital expenditures in 2013 are expected
to be paid primarily from working capital, and potentially with
additional funds from NW Natural.
benefit pension plans were underfunded by $154.4 million at
December 31, 2012. We plan to make contributions during
2013 of up to $15 million.
We also contribute to a multiemployer pension plan for our
union employees (the Union Plan, or otherwise known as
Western States Plan) pursuant to our collective bargaining
agreement. We made contributions totaling $0.4 million to
the Union Plan in both 2012 and 2011. See Note 8 for
further pension disclosures.
Ratios of Earnings to Fixed Charges
For the years ended December 31, 2012, 2011, and 2010,
our ratios of earnings to fixed charges, computed using the
Securities and Exchange Commission (SEC) method,
were 3.30, 3.41, and 3.73, 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 Part II, Item 7,
“Application of Critical Accounting Policies and Estimates”
below. At December 31, 2012, we had a regulatory asset of
$126.5 million for deferred environmental costs, which
includes $69.7 million for additional costs expected to be
paid in the future and $23.4 million of accrued interest. 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 and "Results of Operations—
Regulatory Matters—Rate Mechanisms—Environmental
Costs" above.
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.
Financing Activities
Financing activity highlights include:
In millions
2012
2011
2010
Total cash provided by (used
in) financing activities
$
18.9
$
(78.0) $
81.4
Change in short-term debt
Change in long-term debt
48.7
10.0
Cash dividend payments
(48.0)
(46.7)
(115.8)
155.4
80.0
(35.0)
(44.7)
2012 COMPARED TO 2011. The $97.0 million increase to
cash provided by financing activity was primarily due to
changes in our short-term debt balances, which increased
$48.7 million in 2012 compared to a decrease of $115.8
million in 2011. In 2012, we retired $40 million of long-term
debt and issued $50 million of long-term debt. We continue
to use long-term debt proceeds to finance capital
expenditures, refinance maturing short-term or long-term
debt maturities, and to fund other general corporate
purposes.
2011 COMPARED TO 2010. The $159.4 million increase to
cash used in financing activities is primarily due to our short-
term debt balances, which decreased $115.8 million. We
retired $10 million of long-term debt and issued $50 million
of utility long-term debt and $40 million of subsidiary long-
term debt by Gill Ranch.
We have a stock repurchase program approved through
May 2013 which provides authorization to repurchase up to
2.8 million shares of NW Natural common stock or up to
$100 million. The purchases may be made in the open
market or through privately negotiated transactions. No
repurchases were made in 2012, 2011 or 2010 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.
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” below. Pension
expense for our qualified defined benefit plan, which are
allocated between operation and maintenance expenses,
capital expenditures and the deferred regulatory balancing
account, totaled $19.1 million in 2012, an increase of $2.8
million from 2011.
The fair market value of pension assets in this plan
increased to $249.6 million at December 31, 2012 from
$216.0 million at December 31, 2011. The increase was due
to a return on plan assets of $26.7 million plus $23.5 million
in employer contributions, partially offset by benefit
payments of $16.5 million.
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
42
APPLICATION OF CRITICAL ACCOUNTING POLICIES
AND ESTIMATES
In preparing our financial statements using GAAP,
management exercises judgment in the selection and
application of accounting principles, including making
estimates and assumptions that affect reported amounts of
assets, liabilities, revenues, expenses and related
disclosures in the financial statements. Management
considers our critical accounting policies to be those which
are most important to the representation of our financial
condition and results of operations and which require
management’s most difficult and subjective or complex
judgments, including accounting estimates that could result
in materially different amounts if we reported under different
conditions or used different assumptions. Our most critical
estimates and judgments include accounting for:
• regulatory cost recovery and amortizations;
• revenue recognition;
• derivative instruments and hedging activities;
• pensions and postretirement benefits;
• income taxes; and
• environmental contingencies.
Management has discussed its current estimates and
judgments used in the application of critical accounting
policies with the Audit Committee of the Board. Within the
context of our critical accounting policies and estimates,
management is not aware of any reasonably likely events or
circumstances that would result in materially different
amounts being reported. For a description of recent
accounting pronouncements that could have an impact on
our financial condition, results of operations or cash flows,
see Note 2.
Regulatory Accounting
Our utility is regulated by the OPUC and WUTC, which
establish the rates and rules governing utility services
provided to customers, and, to a certain extent, set forth
special 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—Purchased Gas Adjustment”
above. There are other expenses and 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 are 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 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 our utility satisfies all three conditions, we continue
to apply regulatory accounting to 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 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 utility
activities, and that all of our regulatory assets and liabilities
at December 31, 2012 and 2011 are reasonably likely to be
recovered or refunded through future customer rates. 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 in the period such determination is made. The net
balance in regulatory asset and liability accounts as of
December 31, 2012 and 2011 was $131.4 million and
$156.6 million, respectively. See Note 2 “Industry
Regulation”.
Revenue Recognition
Utility and non-utility revenues, which are derived primarily
from the sale, transportation and storage of natural gas, are
recognized upon the delivery of gas commodity or services
rendered to customers.
ACCRUED UNBILLED REVENUE. Revenues are accrued for
gas delivered and services rendered to customers, but not
yet billed, based on estimates from the last meter reading
date to month end (accrued unbilled revenue). Accrued
unbilled revenue is based on a percentage estimate of
amounts unbilled each month, which is dependent upon a
number of factors, some of which require management’s
judgment. These factors include:
•
•
•
• weather.
total gas receipts and deliveries;
customer meter reading dates;
customer usage patterns; and
Accrued unbilled revenue estimates are reversed the
following month when actual billings occur. Estimated
unbilled revenue at December 31, 2012 and 2011 was
$57.0 million and $61.9 million, respectively. The decrease
in accrued unbilled revenue at year-end 2012 was primarily
due to lower volumes in December 2012, reflecting warmer
weather late in the month, and lower customer billing rates.
43
accumulated other comprehensive income (AOCI) under
common stock equity on the balance sheet. Our derivative
contracts outstanding at December 31, 2012 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 derivative activities
being subject to regulatory deferral treatment. For estimated
fair value of unrealized gains and losses, 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” above. 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 AOCI 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, 2012, 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 gains and
losses realized from commodity price, interest rate and
currency hedge transactions for the last three years:
In millions
2012
2011
2010
Net utility gain (loss) on:
Commodity-price swaps
$
(69.5) $
(53.8) $
(60.4)
Commodity-price options
Subtotal
Foreign currency forward
purchases
(0.7)
(70.2)
(2.7)
(56.5)
(0.6)
(61.0)
—
(0.1)
0.1
Total net loss realized
$
(70.2) $
(56.6) $
(60.9)
Realized gains (losses) from commodity hedges and foreign
currency forward purchase contracts shown above were
recorded as reductions (increases) to cost of gas and were
included in our annual PGA rates.
The following table presents changes in key metrics if the
estimated percentage of unbilled volume at December 31,
2012 was adjusted up or down by 1%:
In millions
2012
Up 1%
Down 1%
Unbilled revenue increase (decrease)
$
2.0
$
(1.9)
Utility margin decrease
Net income decrease
(0.4)
(0.2)
0.4
0.2
SENATE BILL 408 AND 967. From 2007 through 2010, utility
revenues included the recognition of a regulatory
adjustment for income taxes paid (commonly referred to as
SB 408). Under SB 408, utilities were required to
automatically implement a rate refund, or a rate surcharge,
to utility customers on an annual basis. The refund or
surcharge amount was based on estimated differences
between income taxes paid and income taxes collected in
customer rates. We recorded the refund, or surcharge, each
quarter based on the annual amount to be recognized. In
2011 SB 967 effectively repealed SB 408. The new law
required utilities in Oregon to reverse amounts accrued for
the 2010 and 2011 tax years, which resulted in us recording
a one-time pre-tax charge to earnings in the second quarter
of 2011 in the amount of $7.4 million ($4.4 million after-tax
or 17 cents per share). For further discussion, see “Results
of Operations—Business Segments-Local Gas Distribution
"Utility Operations—Regulatory Adjustment for Income
Taxes Paid” above.
NON-UTILITY REVENUES. Non-utility revenues, derived
primarily from our gas storage segment, are recognized
upon delivery of service to customers. Revenues from our
asset management partner are recognized as earned based
on multiple revenue elements, which is generally over the
period of each asset management deal, except for contracts
with a guaranteed amount, which are amortized pro-rata
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 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
44
Accounting for Pensions and Postretirement
Benefits
We maintain a qualified non-contributory defined benefit
pension plan covering a majority of our utility employees,
several non-qualified supplemental pension plans for
eligible executive officers and certain key employees, and
other postretirement employee benefit plans covering
certain non-union employees. We also have a qualified
defined contribution plan (Retirement K Savings Plan) for all
eligible employees. Only the qualified defined benefit
pension plan and Retirement K Savings Plan have plan
assets, which are held in qualified trusts to fund the
respective retirement benefits. Effective December 31,
2012, the defined benefit pension plans for union and non-
union employees were merged into one plan. The qualified
defined benefit retirement plans for union and non-union
employees were closed to new participants several years
ago. These plans were not available to employees at any of
our subsidiary companies. We currently offer our utility and
subsidiary employees an enhanced Retirement K Savings
Plan benefit. The postretirement Welfare Benefit Plan for
non-union employees was also closed to new participants
several years ago.
Net periodic pension and postretirement benefit costs
(retirement benefit costs) and projected benefit obligations
(benefit obligations) are determined 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 8. 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 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 related 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
benefit expenses. We also 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”.
In 2011, we received regulatory approval from the OPUC
and began deferring a portion of our pension expense
above or below the amount set in rates to a regulatory
balancing account on the balance sheet. In 2012, the
cumulative amount deferred for future pension cost recovery
was $15.0 million. The regulatory balancing account earns a
carrying cost at the authorized cost of capital rate set by the
OPUC.
A number of factors are considered in developing pension
and postretirement benefit assumptions, including
evaluations of relevant discount rates, an evaluation of
expected long-term investment returns, 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, 2012
measurement date, we reviewed and updated:
•
our weighted-average discount rate assumptions for
pensions and other postretirement benefits, which went
from 4.51% to 3.85% and from 4.33% to 3.56%,
respectively. The new rate assumptions were
determined for each plan based on a matching of
benchmark interest rates to the estimated cash flows,
which reflects the timing and amount of future benefit
payments. Benchmark interest rates are drawn from the
Citigroup Above Median Curve, which consists of high
quality bonds rated AA- or higher by S&P or Aa3 or
higher by Moody’s;
our expected annual rate of future compensation
increases, which remained unchanged at a range of
3.25% to 5.0%;
our expected long-term return on qualified defined
benefit plan assets, which was reduced from 8.00% to
7.50%; and
other key assumptions, which were based on actual
plan experience and actuarial recommendations.
•
•
•
At December 31, 2012, our net pension liability (benefit
obligations less market value of plan assets) for the
qualified defined benefit plan increased $7.4 million
compared to 2011. The increase in our net pension liability
is primarily due to the $41.1 million increase in our pension
benefit obligation, offset by an increase of $33.6 million in
plan assets. The liability for non-qualified plans increased
$3.7 million, and the liability for other postretirement benefits
increased $3.1 million in 2012.
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, 2012, the actual annualized returns on plan
assets, net of management fees, for the past one-year, five-
years, 10-years and since inception were 12.4%, 0.9%,
7.1% and 10.0%, respectively.
45
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:
Impact on
2012
Retirement
Benefit
Costs
Impact on
Retirement
Benefit
Obligations
at Dec. 31,
2012
Change in
Assumption
(0.25)%
$
1.2
$
—
0.1
13.6
0.9
0.9
(0.25)
0.6
N/A
Dollars in millions
Discount rate:
Qualified defined
benefit plans
Non-qualified plans
Other
postretirement
benefits
Expected long-term
return on plan assets:
Qualified defined
benefit plans
In July 2012, President Obama signed into law the Moving
Ahead for Progress in the 21st Century Act (MAP-21 Act).
This legislation changes several provisions affecting
pension plans, including temporary funding relief and
Pension Benefit Guaranty Corporation (PBGC) premium
increases, which reduces the level of minimum required
contributions in the near-term but generally increases
contributions in the long-run as well as increasing the
operational costs of running a pension plan. Prior to the
MAP-21 Act, we were using interest rates based on a 24-
month average yield of investment grade corporate bonds
(also referred to as “segment rate”) to calculate minimum
contribution requirements. MAP-21 Act established a new
minimum and maximum corridor for segment rates based
on a 25-year average of bond yields, which is to be used in
calculating contribution requirements. For 2013, the new
corridor will be set at no less than 85% and no more than
115% of the corresponding 25-year average segment rate.
In 2014, the corridor widens to 80% to 120% of the 25-year
average, and the corridor continues to widen by 5% each
year thereafter until reaching 70% to 130%. Under current
market conditions, we estimate the segment rate for the
2013 Plan Year will increase from approximately 4.90% to
6.25%, and this 1.35% increase in interest rates would
reduce our minimum contribution requirement by
approximately $15 million, from roughly $26 million under
the unadjusted 24-month segment rate to roughly $11
million under the adjusted 24-month segment rate using the
85% to 115% corridor.
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, 2012 and 2011, our net long-
term deferred tax liability totaled $446.6 million and $413.2
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 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, 2012, we did not
record a valuation allowance due to our expectation that all
of these assets and liabilities 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.
As part of the Oregon general rate case, the OPUC ruled
that we cannot recover deferred amounts that represent the
increase in deferred income taxes caused by the 2009
Oregon tax rate change. As a result, we have recognized a
one time, after tax charge of $2.7 million in 2012 to write off
the regulatory asset related to this rate change. At
December 31, 2012 and 2011, we had regulatory assets
representing differences between book and tax basis
related to pre-1981 property of $60.3 million and $68.5
million, respectively, and recorded an offsetting deferred tax
liability. We are currently recovering these pre-1981
deferred tax assets over a period of approximately 25 years.
See Note 2 and Note 9.
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, 2012, we had no reserves for uncertain tax positions.
In 2012, the Company settled an examination of tax years
2006 through 2009 with the state of Oregon. This settlement
resulted in an additional $0.2 million state tax expense due
to Oregon, including interest. However, the Company also
filed an amended tax return with the state of California for
tax year 2007 in which it claimed a refund of $0.2 million
and recognized a reduction in state tax expense of $0.2
million. The net effect of these two state tax changes was
negligible.
Interest and penalties related to any future income tax
deficiencies would be recorded in income tax expense in
our consolidated statements of income.
Accounting for Environmental 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
46
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” above. It is possible,
however, that the range of potential liabilities could be
significantly different than amounts currently accrued and
disclosed, with the result that our financial condition and
results of operations could be materially affected by
changes in the assumptions or estimates related to these
contingencies.
With respect to environmental liabilities and related costs,
we develop estimates based on a review of information
available from 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 $69.7 million as of December 31, 2012.
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 low 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 continue to seek recovery of such costs through
insurance and through customer rates, and we believe
recovery of these costs is probable. Pursuant to the 2012
Oregon general rate case, environmental cost deferrals will
be recovered under the new SRRM subject to a reduction
for separate insurance recoveries, a prudence review, and
an earnings test that will be defined in a separate regulatory
proceeding, which is currently open. As there is uncertainty
surrounding the outcome of this proceeding, we will
continue to carefully assess these environmental assets for
recoverability. 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 "Results of Operations—
Rate Matters—Rate Mechanisms—Environmental Costs"
above and Note 15.
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.
47
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 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 substantially mitigate credit exposure to our
physical gas counterparties.
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 supply and demand. In addition to managing
storage positions through a combination of short- and long-
term fixed price contracts, we use commodity-price financial
swap and option contracts (financial hedge contracts) to
convert certain natural gas supply contracts from floating
prices to fixed or capped prices. We also hedge with
physical gas reserves from a long-term investment in
working interests in gas leases operated by Encana. These
financial hedge contracts and gas reserve volumes are
generally included in our annual PGA filing for recovery,
subject to a regulatory prudence review. We also regularly
monitor and manage the financial exposure and liquidity risk
of our storage position.
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 for our commodity and
commodity related demand charges paid in Canadian
dollars. At December 31, 2012 and 2011, notional amounts
under foreign currency forward contracts totaled $13.2
million and $12.3 million, respectively. As of December 31,
2012, all foreign currency forward contracts mature within
one year. If all of the foreign currency forward contracts had
been settled on December 31, 2012, a gain of $0.1 million
would have been realized. See Note 13.
Credit Risk
CREDIT EXPOSURE TO NATURAL GAS SUPPLIERS. Certain
gas suppliers 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
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
or provided 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 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. We have a weather
normalization mechanism for residential and commercial
customers, which 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, 2012,
approximately 9% 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% 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% of all
residential and commercial customers. See "Results of
Operations—Regulatory Matters—Rate Mechanism—
Weather Normalization Tariff" above.
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 expect these costs would be subject to our 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, 2012, 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 (see table below). However, changes in
natural gas prices could result in counterparties owing us
money. 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, 2012, 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:
In millions
AAA/Aaa
AA/Aa
A/A
BBB/Baa
Total
Financial Derivative Position by Credit Rating
Unrealized Fair Value Loss
2012
2011
$
$
— $
(5.0)
—
—
(5.0) $
—
(57.6)
(5.9)
—
(63.5)
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
48
[THIS PAGE INTENTIONALLY LEFT BLANK]
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 Comprehensive Income for the Years Ended December 31, 2012, 2011, and 2010
Consolidated Balance Sheets at December 31, 2012 and 2011
Consolidated Statements of Shareholders’ Equity for the Years Ended December 31, 2012, 2011, and 2010
Consolidated Statements of Cash Flows for the Years Ended December 31, 2012, 2011, and 2010
Notes to Consolidated Financial Statements
Quarterly Financial Information (Unaudited)
Supplementary Data for the Years Ended December 31, 2012, 2011, and 2010:
Financial Statement Schedule
Schedule II – Valuation and Qualifying Accounts and Reserves
Supplemental Schedules Omitted
Page
50
51
52
53
55
56
57
81
81
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.
49
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, 2012. 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, 2012.
The effectiveness of internal control over financial reporting as of December 31, 2012 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/ Stephen P. Feltz
Stephen P. Feltz
Senior Vice President and Chief Financial Officer
March 1, 2013
50
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, 2012 and 2011, and the
results of their operations and their cash flows for each of the three years in the period ended December 31, 2012 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, 2012, 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
March 1, 2013
51
NORTHWEST NATURAL GAS COMPANY
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
In thousands, except per share data
Operating revenues
Operating expenses:
Cost of gas
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
Other comprehensive income:
Change in employee benefit plan liability, net of taxes of $1,339 for 2012, $1,161
for 2011, and $674 for 2010
Amortization of non-qualified employee benefit plan liability, net of taxes of ($434)
for 2012, ($383) for 2011, and ($257) for 2010
Comprehensive income
Average common shares outstanding:
Basic
Diluted
Earnings per share of common stock:
Basic
Diluted
Dividends declared per share of common stock
Year Ended December 31,
2012
2011
2010
$ 730,607
$ 828,055
$ 792,115
355,335
129,477
30,598
73,017
588,427
142,180
4,936
43,157
458,508
125,417
29,281
70,004
683,210
144,845
4,523
42,088
424,494
121,020
23,872
65,124
634,510
157,605
7,102
42,578
103,959
107,280
122,129
44,104
59,855
43,382
63,898
49,462
72,667
(2,156)
(1,779)
(1,027)
665
583
391
$
58,364
$
62,702
$
72,031
26,831
26,907
26,687
26,744
26,589
26,657
$
$
2.23
2.22
1.79
$
2.39
2.39
1.75
2.73
2.73
1.68
See Notes to Consolidated Financial Statements
52
NORTHWEST NATURAL GAS COMPANY
CONSOLIDATED BALANCE SHEETS
In thousands
Assets:
Current assets:
Cash and cash equivalents
Accounts receivable
Accrued unbilled revenue
Allowance for uncollectible accounts
Regulatory assets
Derivative instruments
Inventories
Gas reserves
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
Gas reserves
Regulatory assets
Derivative instruments
Other investments
Restricted cash
Other non-current assets
Total non-current assets
Total assets
As of December 31,
2012
2011
$
8,923
$
61,229
56,955
(2,518)
52,448
1,950
67,602
14,966
2,552
19,592
283,699
5,833
77,449
61,925
(2,895)
94,673
2,853
74,363
4,463
7,045
22,980
348,689
2,786,008
2,661,102
812,396
767,226
1,973,612
1,893,876
84,693
387,888
3,639
67,667
4,000
13,555
47,451
371,392
—
68,263
4,000
12,903
2,535,054
2,397,885
$
2,818,753
$
2,746,574
See Notes to Consolidated Financial Statements
53
NORTHWEST NATURAL GAS COMPANY
CONSOLIDATED BALANCE SHEETS
In thousands
Liabilities and equity:
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
Long-term debt
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 14 and Note 15)
Equity:
Common stock - no par value; authorized 100,000 shares; issued and outstanding 26,917
and 26,756 at December 31, 2012 and 2011, respectively
Retained earnings
Accumulated other comprehensive loss
Total equity
Total liabilities and equity
See Notes to Consolidated Financial Statements
As of December 31,
2012
2011
$
190,250
$
141,600
—
85,613
9,588
5,953
20,792
10,796
45,444
368,436
691,700
446,604
288,113
215,792
578
74,497
1,025,584
—
40,000
86,300
10,747
5,857
31,046
57,317
41,597
414,464
641,700
413,209
278,382
201,530
6,536
76,265
975,922
—
356,571
385,753
(9,291)
733,033
348,383
373,905
(7,800)
714,488
$
2,818,753
$
2,746,574
54
NORTHWEST NATURAL GAS COMPANY
CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY
In thousands
Balance at Dec. 31, 2009
Comprehensive income
Dividends paid on common stock
Tax expense from employee stock option plan
Stock-based compensation
Issuance of common stock
Balance at Dec. 31, 2010
Comprehensive income
Dividends paid on common stock
Tax expense from employee stock option plan
Stock-based compensation
Issuance of common stock
Common stock expense
Balance at Dec. 31, 2011
Comprehensive income
Dividends paid on common stock
Tax expense from employee stock option plan
Stock-based compensation
Issuance of common stock
Balance at Dec. 31, 2012
Common
Stock
Retained
Earnings
Accumulated
Other
Comprehensive
Income (Loss)
Total
Equity
$
337,361
$
328,712
$
(5,968) $
660,105
—
—
(125)
554
5,188
342,978
—
—
(26)
1,769
3,632
30
348,383
—
—
(149)
1,291
7,046
72,667
(44,652)
—
—
—
356,727
63,898
(46,690)
—
—
—
(30)
373,905
59,855
(48,007)
—
—
—
(636)
—
—
—
—
(6,604)
(1,196)
—
—
—
—
—
(7,800)
(1,491)
—
—
—
—
72,031
(44,652)
(125)
554
5,188
693,101
62,702
(46,690)
(26)
1,769
3,632
—
714,488
58,364
(48,007)
(149)
1,291
7,046
$
356,571
$
385,753
$
(9,291) $
733,033
See Notes to Consolidated Financial Statements
55
NORTHWEST NATURAL GAS COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
In thousands
Operating activities:
Net income
Adjustments to reconcile net income to cash provided by operations:
Depreciation and amortization
Deferred tax liabilities
Non-cash expenses related to qualified defined benefit pension plans
Contributions to qualified defined benefit pension plans
Deferred environmental expenditures, net of recoveries
Other
Changes in assets and liabilities:
Receivables
Inventories
Taxes accrued
Accounts payable
Interest accrued
Deferred gas costs
Other, net
Cash provided by operating activities
Investing activities:
Capital expenditures
Utility gas reserves
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
Year Ended December 31,
2012
2011
2010
$ 59,855
$ 63,898
$ 72,667
73,017
42,780
5,448
70,004
46,877
7,191
65,124
76,410
8,009
(23,500)
(22,045)
(10,000)
(12,503)
25,586
3,990
280
(7,826)
(2,853)
22,170
(6,246)
15,830
6,761
3,334
(602)
96
6,022
34,189
148
675
572
(51,524)
(11,846)
(253)
(17,644)
8,565
(26,090)
5,636
(1,682)
(1,751)
168,838
233,462
126,469
(132,029)
(100,534)
(248,505)
(54,085)
(50,597)
—
1,437
(3,076)
1,142
—
34,619
1,015
(184,677)
(153,065)
(212,871)
6,758
50,000
3,040
90,000
4,598
—
(40,000)
(10,000)
(35,000)
48,650
(115,835)
155,435
(48,007)
(46,690)
(44,652)
1,528
1,464
18,929
(78,021)
3,090
5,833
2,376
3,457
$
8,923
$
5,833
$
1,046
81,427
(4,975)
8,432
3,457
$ 43,061
$ 41,413
$ 41,037
2,979
1,756
22,600
See Notes to Consolidated Financial Statements
56
NORTHWEST NATURAL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. ORGANIZATION AND PRINCIPLES OF
CONSOLIDATION
The accompanying consolidated financial statements
represent the consolidation of Northwest Natural Gas
Company (NW Natural or the Company) and all companies
that we directly or indirectly control, either through majority
ownership or otherwise. Our direct and indirect wholly-
owned subsidiaries include NW Natural Energy, LLC (NWN
Energy), NW Natural Gas Storage, LLC (NWN Gas
Storage), Gill Ranch Storage, LLC (Gill Ranch), and NNG
Financial Corporation (NNG Financial). Investments in
corporate joint ventures and partnerships that we do not
directly or indirectly control, and for which we are not the
primary beneficiary, are accounted for under the equity
method or the cost method, which includes NWN Energy’s
investment in Palomar Gas Holdings, LLC (PGH) and NNG
Financial's investment in KB Pipeline. NW Natural and its
affiliated companies are collectively referred to herein as
NW Natural. The consolidated financial statements are
presented after elimination of all significant intercompany
balances and transactions, except for amounts required to
be included under regulatory accounting standards to reflect
the effect of such regulation. 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.
Certain prior year balances in our consolidated financial
statements and notes have been reclassified to conform
with the current presentation. Specifically, the consolidated
statement of comprehensive income has been reorganized,
and cost of gas is now included in the section for total
operating expenses. Net operating revenues, which was
primarily used to show profit margins from the sale of gas, is
no longer presented as a subtotal in the statement of
comprehensive income. These changes, including the one
noted above, had no impact on our prior year’s consolidated
results of operations, financial condition or cash flows.
2. SIGNIFICANT ACCOUNTING POLICIES UPDATE
Use of Estimates
The preparation of financial statements in conformity with
generally accepted accounting principles in the United
States of America (GAAP) requires management to make
estimates and assumptions that affect reported amounts in
the consolidated financial statements and accompanying
notes. Actual amounts could differ from those estimates, and
changes would most likely be reported in future periods.
Management believes that the estimates and assumptions
used are reasonable.
57
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 natural gas storage services,
which are regulated by either the Federal Energy Regulatory
Commission (FERC) or 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 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).
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, which
provides for the recovery of revenues or expenses from, or
refunds to, utility customers in future periods, including a
return or a carrying charge in certain cases.
At December 31, 2012 and 2011 the amounts deferred as
regulatory assets and liabilities were as follows:
In thousands
Current:
Regulatory Assets
2012
2011
Unrealized loss on derivatives(1)
$ 10,796
$ 57,317
Pension and other postretirement
benefit liabilities(2)
Other(3)
Total current
Non-current:
Unrealized loss on derivatives(1)
Pension balancing(2)
Income tax asset
Pension and other postretirement
benefit liabilities(2)
Environmental costs(4)
Other(3)
17,247
24,405
15,491
21,865
$ 52,448
$ 94,673
$
578
$
6,536
15,022
55,879
6,008
65,264
182,688
170,512
126,482
105,670
7,239
17,402
Total non-current
$ 387,888
$ 371,392
In thousands
Current:
Gas costs
Unrealized gain on derivatives(1)
Other(3)
Total current
Non-current:
Gas costs
Unrealized gain on derivatives(1)
Accrued asset removal costs
Other(3)
Regulatory Liabilities
2012
2011
$
9,100
$ 17,994
1,950
9,742
2,853
10,199
$ 20,792
$ 31,046
$
— $
8,420
3,639
—
281,213
267,355
3,261
2,607
Total non-current
$ 288,113
$ 278,382
(1) Unrealized gains or losses on derivatives are non-cash items
and therefore do not earn a rate of return or a carrying charge.
These amounts are recoverable through utility rates as part of
the annual Purchased Gas Adjustment (PGA) mechanism
when realized at settlement.
(2) Certain pension costs of the utility are approved for regulatory
deferral, including amounts recorded to the pension balancing
account, to mitigate the effects of higher and lower pension
expenses. Pension costs that are deferred include an interest
component when recognized in net periodic benefit costs or
earn a rate of return or carrying charge. See Note 8.
(3) Other primarily consists of several deferrals and amortizations
under other approved regulatory mechanisms. The accounts
being amortized typically earn a rate of return or carrying
charge.
(4) Environmental costs relate to specific sites approved for
regulatory deferral. In Oregon we earn a rate of return on
amounts paid, whereas amounts accrued but not yet paid do
not earn a rate of return or a carrying charge until expended.
Environmental costs related to Washington were deferred
beginning in 2011, with cost recovery and a carrying charge to
be determined in a future proceeding. In the 2012 rate case,
the OPUC authorized a Site Remediation and Recovery
Mechanism (SRRM) that allows the Company to recover
prudently incurred environmental costs, subject to an earnings
test that will be defined in a future rate proceeding.
The amortization period for our regulatory assets and
liabilities ranges from less than one year to an
indeterminable period. Our regulatory deferrals 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 all cost incurred and deferred at December 31,
2012 are prudent. 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 in the period such
determination is made.
58
New Accounting Standards
Adopted Standards
FAIR VALUE MEASUREMENT. In May 2011, the Financial
Accounting Standards Board (FASB) issued amendments to
the authoritative guidance on fair value measurement. The
amendments are primarily related to disclosure requirements
for Level 3 fair value assets and were effective for periods
beginning after December 15, 2011. The adoption of this
standard did not have a material effect on our financial
statement disclosures.
Recent Accounting Pronouncements
BALANCE SHEET OFFSETTING. In December 2011, the FASB
issued authoritative guidance regarding the offsetting of
assets and liabilities on the balance sheet. The standard is
intended to provide more comparable guidance between the
GAAP and international accounting standards by requiring
entities to disclose both gross and net amounts for assets
and liabilities offset on the balance sheet as well as other
disclosures concerning their enforceable master netting
arrangements. This guidance is effective for annual reporting
periods beginning after January 1, 2013, and we do not
expect this standard to have a material effect on our financial
statement disclosures.
Plant, Property and Accrued Asset Removal Costs
Plant and property are stated at cost, including capitalized
labor, materials and overhead. In accordance with regulatory
accounting standards, the cost of acquiring and constructing
long-lived plant and property 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 constructed assets are subject
to market-based rates rather than cost-based rates, the
financing costs incurred during construction are included in
capitalized interest in accordance with GAAP, not as
regulatory financing costs under AFUDC. See Note 10.
In accordance with long-standing regulatory treatment, our
depreciation rates are comprised of three components: one
based on the average service life of the asset, a second
based on the estimated salvage value of the asset, and a
third based on the asset’s estimated cost of removal. We
collect, through rates, the estimated cost of removal on
certain regulated properties through depreciation expense,
with a corresponding offset to accumulated depreciation.
These removal costs are non-legal obligations as defined by
regulatory accounting guidance. Therefore, we have
included these costs as non-current regulatory liabilities
rather than as accumulated depreciation on our consolidated
balance sheets. In the rate setting process, the liability for
removal costs is treated as a reduction to the net rate base
upon which the regulated utility has the opportunity to earn
its allowed rate of return.
Our provision for depreciation of utility plant and property is
computed under the straight-line method in accordance with
depreciation studies approved by regulatory authorities. The
weighted average depreciation rate for utility assets in
service was approximately 2.8% in 2012, 2011, and 2010,
reflecting the approximate weighted average economic life of
the property. This includes 2012 weighted average
depreciation rates for the following asset categories: 2.7%
for transmission and distribution plant, 2.2% for gas storage
facilities, 4.7% for general plant, and 4.8% for intangible and
other fixed assets.
Allowance for Funds Used During Construction
Certain additions to utility plant include AFUDC, which
represents the net cost of debt and equity funds used during
construction. AFUDC is calculated using actual interest rates
for debt and authorized rates for return on equity (ROE), if
applicable. If short-term debt balances are less than the total
balance of construction work in progress, then a composite
AFUDC rate is used to represent interest on all debt funds,
shown as a reduction to interest charges, and on ROE
funds, shown as other income. While cash is not
immediately recognized from recording AFUDC, it is realized
in future years through rate recovery resulting from the
higher utility cost of service. Our composite AFUDC rates
were 0.3% in 2012, 0.5% in 2011, and 0.6% in 2010.
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, 2012 and 2011, outstanding checks of
approximately $2.3 million and $3.9 million, respectively,
were included in accounts payable.
Revenue Recognition and Accrued Unbilled Revenue
Utility revenues, derived primarily from the sale and
transportation of natural gas, are recognized upon delivery of
gas commodity or service to customers. 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 revenue). Accrued unbilled
revenue is 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 revenue is reversed the following month
when actual billings occur. Our accrued unbilled revenue at
December 31, 2012 and 2011 was $57.0 million and $61.9
million, respectively.
From 2007 through 2010, utility margin also included the
recognition of a regulatory adjustment for income taxes paid
pursuant to a legislative rule (commonly referred to as SB
408) in effect for certain gas and electric utilities in Oregon.
Under SB 408, we were required to automatically implement
a rate refund, or a rate surcharge, to utility customers on an
annual basis. The refund or surcharge amount was based on
the difference between income taxes paid and income taxes
authorized to be collected in customer rates. We recorded
the refund, or surcharge, each quarter based on estimates of
the annual amount to be recognized. In 2011, SB 408 was
repealed and replaced by Senate Bill 967. SB 967 required
utilities to eliminate amounts accrued under SB 408 for the
2010 and 2011 tax years, thereby denying recovery by NW
Natural of the surcharge accrued for 2010, which resulted in
a one-time pre-tax charge of $7.4 million in the second
quarter of 2011. Pursuant to SB 967, we changed our
revenue recognition policy effective January 1, 2011 and no
longer recognize a regulatory adjustment for income taxes
for SB 408.
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 management partner are recognized over the life of
the asset management contract for guaranteed amounts, if
any, and are recognized as earned for amounts above the
guaranteed amount. At Gill Ranch, firm storage 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.
Asset management revenue is recognized using a straight-
line, pro rata methodology over the term of each contract
and provides us with the majority 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 utility
customers, plus amounts due for gas storage services. With
respect to these trade receivables, including accrued
unbilled revenue, 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 a number of factors,
including changes in economic conditions, customer credit
worthiness and the level of natural gas prices. Each quarter
the allowance for uncollectible accounts is adjusted, as
necessary, based on information currently available.
Inventories
Utility gas inventories, which consist of natural gas in storage
for the utility, are 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 storage are charged
to cost of gas during the current period at the weighted
average inventory cost.
Gas storage inventories, which primarily represent
inventories at the Gill Ranch storage facility, exclude cushion
gas and consist of natural gas that we received as fuel-in-
kind from storage customers. Gas storage 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.
Material and supplies inventories, which consist of both utility
and non-utility inventories, are stated at the lower of average
cost or net realizable value.
59
Our utility and gas storage inventories totaled $58.8 million
and $65.6 million at December 31, 2012 and 2011,
respectively, and our materials and supplies inventories
totaled $8.8 million at December 31, 2012 and 2011.
Gas Reserves
Our gas reserves are stated at cost, adjusted for regulatory
amortization, with the associated deferred tax benefits
recorded as liabilities on the balance sheet. Transactional
costs to enter into the agreement and payments by NW
Natural to acquire gas reserves are recognized as gas
reserves on the balance sheet. The current portion is
calculated based on expected gas deliveries within the next
fiscal year. We recognize regulatory amortization of this
asset on a volumetric basis and calculate using the
estimated gas reserves and the therms extracted and sold
each month. The amortization of gas reserves is recorded to
cost of gas along with gas production revenues and
production costs. See Note 11.
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 derivative contracts
are approved by regulatory authorities for recovery or refund
through customer rates. Accordingly, the changes in fair
value of these approved contracts are deferred as regulatory
assets or liabilities pursuant to regulatory accounting
principles. Derivative contracts entered into for utility
customer requirements after the annual PGA rate has been
set are subject to the PGA incentive sharing mechanism.
Effective November 1, 2008, Oregon approved a PGA
sharing mechanism under which we are required to select
either an 80% deferral or 90% deferral of higher or lower gas
costs such that the impact on current earnings from the gas
cost sharing is either 20% or 10% of gas cost differences
compared to PGA prices, respectively. For the PGA years in
Oregon beginning November 1, 2012, 2011 and 2010, we
selected a 90% deferral of gas cost differences. In
Washington, 100% of our gas cost differences are deferred.
See Note 13.
Our financial derivatives policy sets 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
gas prices, 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
60
debt, pension plan assets and our derivative fair value
measurements:
•
•
•
Level 1: Valuation is based upon quoted prices for
identical instruments traded in active markets;
Level 2: Valuation is based upon quoted prices for
similar instruments in active markets, quoted prices for
identical or similar instruments in markets that are not
active, and model-based valuation techniques for which
all significant assumptions are observable in the market;
and
Level 3: Valuation is generated from model-based
techniques that use significant assumptions not
observable in the market. These unobservable
assumptions reflect our own estimates of assumptions
that market participants would use in valuing the asset
or liability.
When developing fair value measurements, it is our policy to
use quoted market prices whenever available, or to
maximize the use of observable inputs and minimize the use
of unobservable inputs when quoted market prices are not
available. Fair values are primarily developed using industry-
standard models that consider various inputs including: (a)
quoted future prices for commodities; (b) forward currency
prices; (c) time value; (d) volatility factors; (e) current market
and contractual prices for underlying instruments; (f) market
interest rates and yield curves; (g) credit spreads; (h) and
other relevant economic measures.
Revenue Taxes
Revenue-based taxes are primarily franchise taxes, which
are collected from customers and remitted to taxing
authorities. Revenue taxes are recorded gross and are
included in operating revenues in the statement of
comprehensive income.
Income Tax Expense
NW Natural and its wholly-owned subsidiaries file
consolidated federal, state, and local 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 9.
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
deferred tax liabilities of $60.3 million and $68.5 million at
December 31, 2012 and 2011, 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. A corresponding regulatory asset has
been recorded which represents the probable future revenue
that will result from inclusion in rates charged to customers
for 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. We do not have any
subsequent events to report.
3. EARNINGS PER SHARE
Basic earnings per share are computed using net income and the weighted average number of common shares outstanding for
each period presented. Diluted earnings per share are computed in the same manner, except it uses the weighted average
number of common shares outstanding plus the 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:
In thousands, except per share data
Net income
Average common shares outstanding - basic
Additional shares for stock-based compensation plans (See Note 6)
Average common shares outstanding - diluted
Earnings per share of common stock - basic
Earnings per share of common stock - diluted
Additional information:
2012
2011
2010
$
59,855
$
63,898
$
26,831
76
26,907
26,687
57
26,744
$
$
2.23
2.22
$
$
2.39
2.39
$
$
72,667
26,589
68
26,657
2.73
2.73
Antidilutive shares not included in net income per diluted common share calculation
1
2
1
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 NWN Gas Storage, which is a
wholly-owned subsidiary of NWN Energy, Gill Ranch, which
is a wholly-owned subsidiary of NWN Gas Storage, the
non-utility portion of our Mist underground storage facility in
Oregon (Mist) and third-party asset management services.
Our “other” segment includes NNG Financial and our equity
investment in PGH, which is pursuing development of 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 and 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, which is approved by the OPUC or
WUTC. Approximately 90% of our customers are located in
Oregon and 10% in Washington. On an annual basis,
residential and commercial customers typically account for
50% to 60% of our utility’s total volumes delivered and 80%
to 90% of our utility’s margin. Industrial customers account
for the remaining 40% to 50% of volumes and 5% to 15% of
utility margin. The remaining 10% or less of utility margin is
derived from miscellaneous services, gains or losses from
an incentive gas cost sharing mechanism and other service
fees.
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 utility margins.
Gas Storage
Our gas storage business segment includes natural gas
storage services provided to customers primarily from two
underground natural gas storage facilities, our Gill Ranch
gas storage facility, which commenced commercial
operation in October 2010, and the non-utility portion of our
Mist gas storage facility. In addition to earning revenue from
61
customer storage contracts, we also use an independent
energy marketing company to provide asset management
services for utility and non-utility capacity under contractual
arrangement, the results of which are included in this
business segment. For the years ended December 31,
2012, 2011 and 2010, this business segment derived a
majority of its revenues from asset management services
and from firm and interruptible gas storage contracts.
Mist Gas Storage Facility
Earnings from non-utility assets at the Mist facility are
primarily related to firm storage capacity revenues.
Earnings for the gas storage segment include revenues, net
of amounts shared with core utility customers, from
management of utility assets at Mist and upstream capacity
when not needed to serve utility customers. In Oregon, the
gas storage segment retains 80% of the pre-tax income
from these services when the costs of the capacity have not
been included in utility rates, or 33% of the pre-tax income
when the costs have been included in utility rates. The
remaining 20% and 67%, respectively, are credited to a
deferred regulatory account for crediting back to utility
customers. We have a similar sharing mechanism in
Washington for revenue derived from storage and third
party asset management services.
Gill Ranch Gas Storage Facility
Gill Ranch has 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% undivided
ownership interest in the facility and is also the operator of
the facility, which offers storage services to the California
market at market-based rates, subject to CPUC regulation
including, but not limited to, service terms and conditions
and tariff regulations.
Other
We have non-utility investments and other business
activities which are aggregated and reported as a business
segment called “other.” Although in aggregate these
investments and activities are currently not material to
consolidated operations, we identify and report them as a
stand-alone segment based on our 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 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.
NNG Financial holds certain non-utility financial
investments, but its assets primarily consist of an active,
wholly-owned subsidiary which owns a 10% interest in an
18-mile interstate natural gas pipeline. NNG Financial’s
total assets were $1.1 million at both December 31, 2012
and 2011.
62
Segment Information Summary
The following table presents summary financial information concerning the reportable segments. Inter-segment transactions are
insignificant.
In thousands
2012
Utility
Gas Storage
Other
Total
Operating revenues
$
699,862
$
30,520
$
225
$
Depreciation and amortization
Income from operations
Net income
Capital expenditures
Total assets at December 31, 2012
2011
66,545
128,854
55,125
130,151
2,511,288
6,472
13,226
4,521
1,541
291,568
—
100
209
337
730,607
73,017
142,180
59,855
132,029
15,897
2,818,753
Operating revenues
$
801,478
$
26,354
$
223
$
Depreciation and amortization
Income from operations
Net income
Capital expenditures
63,843
135,722
60,527
94,049
6,161
9,090
4,101
6,485
—
33
(730)
—
828,055
70,004
144,845
63,898
100,534
Total assets at December 31, 2011
2,435,888
294,637
16,049
2,746,574
2010
Operating revenues
$
770,642
$
21,250
$
223
$
Depreciation and amortization
Income from operations
Net income
Capital expenditures
62,661
145,688
66,262
85,929
2,463
11,855
6,110
161,634
—
62
295
942
792,115
65,124
157,605
72,667
248,505
The following table presents additional summary information concerning utility margin. The gas storage and other segments
emphasize operating revenues and net income growth as opposed to margin growth because these segments do not incur cost
of sales expenses like the utility and, therefore, use revenues and net income to assess performance.
In thousands
Utility margin calculation:
Utility operating revenues
Less: Utility cost of gas
Utility margin
2012
2011
2010
$
$
699,862
$
801,478
$
355,335
458,508
344,527
$
342,970
$
770,642
424,494
346,148
63
5. COMMON STOCK
6. STOCK-BASED COMPENSATION
Common Stock
As of December 31, 2012 and 2011, our common shares
authorized were 100,000,000. As of December 31, 2012, we
had reserved for issuances 137,798 shares of common
stock under the Employee Stock Purchase Plan (ESPP) and
197,112 shares under our Dividend Reinvestment and
Direct Stock Purchase Plan (DRPP). In the second quarter
of 2012, our Restated Stock Option Plan (Restated SOP)
was terminated for new stock option grants. There were
529,925 options outstanding at December 31, 2012, which
were granted prior to termination of the plan. These options
will remain outstanding to the earlier of their forfeiture,
exercise or expiration.
Stock Repurchase Program
We have a share repurchase program under which we may
purchase our common shares on the open market or
through privately negotiated transactions. We currently have
Board authorization through May 2013 to repurchase up to
an aggregate of 2.8 million shares, but not to exceed $100
million. No shares of common stock were repurchased
pursuant to this program during the year ended December
31, 2012. Since the plan’s 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 2012, 2011, and 2010:
In thousands
Balance, December 31, 2009
Sales to employees under ESPP
Exercise of stock options under Restated SOP, net
Balance, December 31, 2010
Sales to employees under ESPP
Exercise of stock options under Restated SOP, net
Sales to shareholders under DRPP
Balance, December 31, 2011
Sales to employees under ESPP
Exercise of stock options under Restated SOP, net
Sales to shareholders under DRPP
Balance, December 31, 2012
Shares
26,533
24
111
26,668
15
24
49
26,756
18
47
96
26,917
Our stock-based compensation plans include a Long-Term
Incentive Plan (LTIP), an ESPP, and a Restated SOP. A
variety of equity programs may be granted under the
LTIP. The Restated SOP was terminated for new stock
option grants in the second quarter of 2012. Together 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. Under the amended LTIP, shares of common
stock are authorized for equity incentive grants in the form
of stock, restricted stock, restricted stock units, stock
options, or performance shares. An aggregate of 600,000
shares were authorized for issuance as of December 31,
2011. An additional 250,000 shares were authorized for
issuance as stock options in 2012. Shares awarded under
the LTIP may be purchased on the open market or issued
as new shares.
Of the 850,000 shares authorized for any LTIP award at
December 31, 2012, 311,571 shares of common stock were
available for any type of award under the LTIP, assuming
that market, performance, and service based grants
currently outstanding are awarded at the target level.
Additionally, the 250,000 shares of common stock added in
2012 were available for option grants at December 31,
2012. There were no outstanding grants of restricted stock
or stock options under the LTIP at December 31, 2012 or
2011. The LTIP stock awards are compensatory awards for
which compensation expense is based on the fair value of
stock awards, with expense being recognized over the
performance and vesting period for the outstanding awards.
Performance Shares
Since the LTIP’s inception in 2001, performance shares
which incorporate market, performance, and service-based
factors, have been granted annually based on three-year
performance periods. At December 31, 2012, certain
performance share measures had been achieved for the
2010-12 award period. Accordingly, participants are
estimated to receive 9,022 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, 2011 and
2010, we awarded 8,428 and 8,007 shares of common
stock, respectively, for the 2009-11 and 2008-10 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. In 2011 and
2010, we expensed $0.4 million and $0.2 million,
respectively, for both the 2009-11 and 2008-10 performance
share award periods, and on a cumulative basis we accrued
a total of $0.8 million and $0.7 million, respectively, related
to the 2009-11 and 2008-10 performance periods.
64
At December 31, 2012, the aggregate number of performance shares granted and outstanding at the target and maximum levels
were as follows:
Performance Period
Target
Maximum
Performance Shares Awards Outstanding
2012
Expense
Cumulative Expense
At Dec. 31, 2012
2010-12
2011-13
2012-14
Total
$
$
41,500
$
83,000
$
452
$
37,950
35,340
75,900
70,680
114,790
$
229,580
$
294
635
1,381
1,170
570
635
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)
2011
2010
2.0%
4.5
2.3%
4.7
Expected market price volatility factor
24.5%
23.2%
Expected dividend yield
Forfeiture rate
3.8%
3.1%
3.8%
3.2%
Weighted average grant date fair value
$ 6.73
$ 6.36
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.
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 the accounting
standard for stock compensation based on performance
levels achieved and an estimated fair value using a Black-
Scholes or binomial model. The weighted-average grant
date fair value of unvested shares at December 31, 2012
and 2011 was $51.42 and $25.06 per share,
respectively. The weighted-average grant date fair value of
shares vested during the year was $45.05 per share and for
shares granted during the year was $22.35 per share.
Restricted Stock Units
In 2012, the Company began granting RSUs under the LTIP
instead of stock options under the Restated SOP. RSUs
include a performance based threshold and a vesting period
of four years from the grant date. An RSU obligates the
Company upon vesting to issue the RSU holder one share
of common stock plus a cash payment equal to the total
amount of dividends paid per share between the grant date
and vesting date of the RSU. During the year ended
December 31, 2012, the Company granted 25,224 RSUs
under the LTIP with grant date fair values ranging from
$44.43 to $48.25 per share.
Restated Stock Option Plan
The Restated SOP was terminated for new option grants in
2012; however, options that had been granted before the
Restated SOP was terminated will remain outstanding until
the earlier of their expiration, forfeiture or exercise. Any new
grants of stock options would be made under the LTIP. No
new stock options were granted during 2012.
At December 31, 2012, a total of 529,925 shares of
common stock remained reserved for issuance under the
Restated SOP with none available for grant. Options under
the Restated SOP were granted only to officers and key
employees designated by a committee of our Board of
Directors. All options were granted at an option price equal
to the closing market price on the date of grant and may be
exercised for a period up to 10 years and 7 days from the
date of grant. Option holders may exchange shares they
have owned for at least six months, valued at the current
market price, to purchase shares at the option price.
65
Information regarding the Restated SOP activity for the
three years ended December 31, 2012 is summarized as
follows:
7. DEBT
Weighted -
Average
Price Per
Share
Intrinsic
Value
(In millions)
Option
Shares
Balance outstanding,
Dec. 31, 2009
484,935
$
39.57
$
Granted
Exercised
Forfeited
Balance outstanding,
Dec. 31, 2010
Granted
Exercised
Forfeited
Balance outstanding,
Dec. 31, 2011
Exercised
Forfeited
Balance outstanding,
Dec. 31, 2012
Exercisable,
Dec. 31, 2012
119,750
(111,525)
(2,700)
490,460
122,700
(24,185)
(9,750)
579,225
(46,825)
(2,475)
44.25
39.01
43.00
40.82
45.74
33.88
44.38
42.09
40.62
43.78
529,925
42.22
366,887
41.16
2.7
n/a
0.9
n/a
2.8
n/a
0.3
n/a
3.4
0.4
n/a
1.3
1.2
In the year ended December 31, 2012, cash of $0.7 million
was received for option shares exercised and $0.1 million
related tax benefit was realized. For the years ended
December 31, 2012, 2011, and 2010, the total fair value of
options that vested was $0.6 million, $0.6 million and $0.5
million, respectively. The weighted average remaining life of
options exercisable and outstanding at December 31, 2012
was 5.1 years and 5.8 years, respectively. As of December
31, 2012, there was $0.5 million of unrecognized
compensation cost related to the unvested portion of
outstanding stock option awards expected to be recognized
over a period extending through 2014.
Employee Stock Purchase Plan
The ESPP allows employees to purchase common stock at
85% 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
$21,244 worth of stock through payroll deductions over a
12-month period, with shares issued at the end of the 12-
month subscription period.
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:
In thousands
2012
2011
2010
Operations and maintenance
expense, for stock-based
compensation
Income tax benefit
$ 1,668 $ 1,477 $ 1,032
(707)
(597)
(418)
Net stock-based compensation
effect on net income
Amounts capitalized for stock-based
compensation
$
$
961 $
880 $
614
294 $
261 $
182
66
Short-Term Debt
Our primary source of short-term funds is from the sale of
commercial paper and bank loans. In addition to issuing
commercial paper or bank loans to meet seasonal working
capital requirements, 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. At December 31, 2012 and 2011, the amounts of
commercial paper debt outstanding were $190.3 million and
$141.6 million, respectively, and the average interest rate
was 0.3% at year end for both periods. The carrying cost of
our commercial paper approximates fair value using Level 2
inputs, due to the short-term nature of the notes. See Note 2
for a description of the fair value hierarchy. At December 31,
2012, our commercial paper had a maximum maturity of 254
days and an average maturity of 84 days. There were no
bank loans outstanding at December 31, 2012 or 2011.
On December 20, 2012, NW Natural entered into a five year
$300 million credit agreement. The agreement has a
maturity date of December 20, 2017, pursuant to which we
may extend commitments for two additional one-year
periods subject to lender approval. The credit agreement
allows us to request increases in the total commitment
amount up to a maximum amount of $450 million and
permits letters of credit in an aggregate amount of up to
$200 million. Any principal and unpaid interest owed on
borrowings under the agreement are due and payable on or
before the expiration date. NW Natural's prior $250 million
agreement, dated May 31, 2007, was terminated upon the
closing of this new credit agreement. There were no
outstanding balances under the agreement and no letters of
credit issued or outstanding at December 31, 2012 and
2011.
The credit agreement requires that we maintain credit
ratings with Standard & Poor’s (S&P) and Moody’s Investors
Service, Inc. (Moody’s) and notify the lenders of any change
in our senior unsecured debt ratings or senior secured debt
ratings, as applicable, by such rating agencies. A change in
our debt ratings is not an event of default, nor is the
maintenance of a specific minimum level of debt rating a
condition of drawing upon the credit facility. However,
interest rates on any loans outstanding under the credit
facility are tied to debt ratings, which would increase or
decrease the cost of any loans under the credit facility when
ratings are changed.
The credit agreement also requires us to maintain a
consolidated indebtedness to total capitalization ratio of
70% 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,
2012 and 2011.
First Mortgage Bonds
NW Natural issued $50 million of FMBs in October 2012
with a coupon rate of 4.00% and a maturity date of
October 31, 2042. In September 2011, the utility issued $50
million of FMBs due September 15, 2021.
Subsidiary Senior Secured Debt
In November 2011, Gill Ranch issued $40 million of senior
secured debt, which consists of $20 million of fixed rate debt
with an interest rate of 7.75% and $20 million of variable
interest rate debt with an interest rate of LIBOR plus 5.50%,
or 7.00%, whichever is higher. At December 31, 2012, the
variable interest rate was 7.00%. This debt is secured by all
of the membership interests in Gill Ranch and is
nonrecourse to NW Natural. The maturity date of this debt is
November 30, 2016.
Under the debt agreements, Gill Ranch is subject to certain
covenants and restrictions including, but not limited to, a
financial covenant that requires Gill Ranch to maintain
minimum adjusted earnings before interest, taxes,
depreciation and amortization (EBITDA) at various levels
over the term of the debt. The minimum adjusted EBITDA
increases incrementally over the first few years, reaching its
highest level in the 12-month period beginning April 1, 2015.
Under the debt agreements, Gill Ranch is also subject to a
debt service reserve requirement of 10% of the outstanding
principal amount, initially $4 million, certain prepayment
penalties, restrictions on dividends out of Gill Ranch unless
certain earnings ratios are met, and restrictions on
incurrence of additional debt. Gill Ranch was in compliance
with all existing debt provisions and covenants for the year
ended December 31, 2012.
Fair Value of Long-Term Debt
As our outstanding debt does not trade in active markets,
we estimated the fair value of our outstanding long-term
debt using outstanding debt issuances that actively trade in
public markets and companies that have similar credit
ratings, terms and remaining maturities to our debt. These
valuations are based on Level 2 inputs as defined in the fair
value hierarchy. See Note 2.
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:
In thousands
Carrying amount
Estimated fair value
December 31,
2012
2011
$
$
691,700
$
834,664
681,700
808,724
Long-Term Debt
The issuance of first mortgage bonds (FMBs), which
includes our medium-term notes, 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. In addition, our Gill
Ranch subsidiary senior secured debt is secured by all of
the membership interests in Gill Ranch as well as Gill
Ranch’s debt service reserve account.
Retirement of long-term debt for each of the 12-month
periods through December 31, 2017 amount to: none in
2013; $60 million in 2014; $40 million in 2015; $65 million in
2016; and $40 million in 2017.
The following table presents our debt outstanding as of
December 31, 2012, 2011, and 2010:
In thousands
First Mortgage Bonds
2012
2011
6.665% Series B due 2011
$
— $
—
7.13 % Series B due 2012
8.26 % Series B due 2014
3.95 % Series B due 2014
4.70 % Series B due 2015
5.15 % Series B due 2016
7.00 % Series B due 2017
6.60 % Series B due 2018
8.31 % Series B due 2019
7.63 % Series B due 2019
5.37 % Series B due 2020
9.05 % Series A due 2021
3.176 % Series B due 2021
5.62 % Series B due 2023
7.72 % Series B due 2025
6.52 % Series B due 2025
7.05 % Series B due 2026
7.00 % Series B due 2027
6.65 % Series B due 2027
6.65 % Series B due 2028
7.74 % Series B due 2030
7.85 % Series B due 2030
5.82 % Series B due 2032
5.66 % Series B due 2033
5.25 % Series B due 2035
4.00 % Series due 2042
—
10,000
50,000
40,000
25,000
40,000
22,000
10,000
20,000
75,000
10,000
50,000
40,000
20,000
10,000
20,000
20,000
19,700
10,000
20,000
10,000
30,000
40,000
10,000
50,000
40,000
10,000
50,000
40,000
25,000
40,000
22,000
10,000
20,000
75,000
10,000
50,000
40,000
20,000
10,000
20,000
20,000
19,700
10,000
20,000
10,000
30,000
40,000
10,000
—
Subsidiary Senior Secured Debt
Gill Ranch debt due 2016
Less: Current maturities of long-term
debt
651,700
641,700
40,000
40,000
691,700
681,700
—
40,000
Total long-term debt
$ 691,700
$ 641,700
67
8. PENSION AND OTHER POSTRETIREMENT BENEFIT COSTS
We maintain qualified non-contributory defined benefit pension plans covering a majority of our utility employees with more than
one year of service, a few non-qualified supplemental pension plans for eligible executive officers and other key employees, and
other postretirement employee benefit plans. We also have qualified defined contribution plans (Retirement K Savings Plan) for
all eligible employees. Only the qualified defined benefit pension plan and Retirement K Savings Plan have plan assets, which
are held in qualified trusts to fund retirement benefits. Effective December 31, 2012, the defined benefit pension plans for non-
union and union employees were merged. We will begin to refer to these plans as one plan in future filings. The qualified defined
benefit retirement plan for non-union and union employees was closed to new participants effective January 1, 2007. The
postretirement benefits plan for non-union employees was closed to new participants effective January 1, 2010. These plans
were not available to employees of our non-utility subsidiaries. Non-union and union employees hired or re-hired after December
31, 2006 and 2009, respectively, and employees of NW Natural subsidiaries are provided an enhanced Retirement K Savings
Plan benefit.
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, excluding the Retirement K Savings Plan, for the years ended December 31,
2012 and 2011, and a summary of the funded status and amounts recognized in the consolidated balance sheets using
measurement dates as of December 31, 2012 and 2011:
In thousands
Reconciliation of change in benefit obligation:
Obligation at January 1
Service cost
Interest cost
Net actuarial (gain) or loss
Benefits paid
Obligation at December 31
Reconciliation of change in plan assets:
Fair value of plan assets at January 1
Actual return on plan assets
Employer contributions
Benefits paid
Fair value of plan assets at December 31
Funded status at December 31
Postretirement Benefit Plans
Pension Benefits
Other Benefits
2012
2011
2012
2011
$
391,127
$
339,338
$
30,049
$
27,676
8,047
17,295
37,615
7,122
18,134
44,802
592
1,267
3,182
614
1,404
2,225
(18,195)
(18,269)
(1,971)
(1,870)
$
435,889
$
391,127
$
33,119
$
30,049
$
215,970
$
219,014
$
26,683
25,145
(18,195)
(6,684)
21,909
(18,269)
— $
—
1,971
(1,971)
249,603
$
215,970
$
— $
—
—
1,870
(1,870)
—
(186,286) $
(175,157) $
(33,119) $
(30,049)
$
$
Our qualified defined benefit pension plan has an aggregate benefit obligation of $404.0 million and $362.9 million at December
31, 2012 and 2011, respectively, and fair values of plan assets of $249.6 million and $216.0 million, respectively.
The following table presents amounts recognized in regulatory assets or in the statement of comprehensive income for the years
ended December 31, 2012, 2011 and 2010:
In thousands
Net actuarial loss
Amortization of:
Transition obligation
Prior service cost
Actuarial loss
Regulatory Assets
Other Comprehensive Income
Pension Benefits
Other Postretirement Benefits
Pension Benefits
2012
2011
2010
2012
2011
2010
2012
2011
2010
$ 26,504
$ 66,404
$ 17,115
$ 3,182
$
2,225
$
2,387
$ 3,511
$
2,948
$
1,716
—
(230)
—
(230)
—
(230)
(14,482)
(10,731)
(6,740)
(411)
(197)
(435)
(411)
(197)
(289)
(411)
(197)
(131)
—
35
(1,150)
—
(122)
(854)
—
43
(707)
Total
$ 11,792
$ 55,443
$ 10,145
$ 2,139
$
1,328
$
1,648
$ 2,396
$
1,972
$
1,052
68
The following table presents amounts recognized in regulatory assets and accumulated other comprehensive income (AOCI) at
December 31, 2012 and 2011:
In thousands
2012
2011
2012
2011
2012
2011
Regulatory Assets
AOCI
Pension Benefits
Other Postretirement Benefits
Pension Benefits
Net transition obligation
$
— $
— $
— $
411
$
1,097
188,278
1,328
176,255
882
9,681
1,079
6,934
$
189,375
$
177,583
$
10,563
$
8,424
$
15,315
$
— $
(12)
15,327
—
(48)
12,966
12,918
Prior service cost
Net actuarial loss
Total
The following is our pension plan asset target allocation at
December 31, 2012:
Asset Category
U.S. large cap equity
U.S. small/mid cap equity
Non-U.S. equity
Emerging markets equity
Long government/credit
High yield
Emerging market debt
Real estate funds
Absolute return strategy
Real return strategy
Target Allocation
13.0%
8.5%
13.0%
3.5%
30.0%
5.0%
5.0%
6.0%
11.0%
5.0%
Our non-qualified supplemental defined benefit plan
obligations were $31.9 million and $28.2 million at
December 31, 2012 and 2011, 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 actuarial gains and losses, prior
service costs and transition assets or obligations for these
plans were recognized as a regulatory asset.
Net periodic benefit costs consist 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, of which the differences 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.
In 2013, an estimated $17.2 million will be amortized from
regulatory assets to net periodic benefit costs, consisting of
$16.8 million of actuarial losses, and $0.4 million of prior
service costs. A total of $1.3 million will be amortized from
AOCI to earnings related to actuarial losses.
Our 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), which uses high quality corporate bonds rated AA-
or higher by S&P or Aa3 or higher by Moody’s. The discount
rate curve was applied to match the estimated cash flows in
each of the Company's plans to reflect the timing and
amount of expected future benefit payments for these plans.
Our assumed expected long-term rate of return on plan
assets was developed using a weighted average of the
expected returns 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 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
outside 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, portfolio risk, and
return expectation. 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.
69
The following tables provide the components of net periodic benefit cost for the Company's pension and other postretirement
benefit plans for the years ended December 31, 2012, 2011, and 2010 and the assumptions used in measuring these costs and
benefit obligations:
In thousands
Service cost
Interest cost
Expected return on plan assets
Amortization of transition obligations
Amortization of prior service costs
Amortization of net actuarial loss
Net periodic benefit cost
Amount allocated to construction
Amount deferred to regulatory balancing account(1)
Pension Benefits
Other Postretirement Benefits
2012
2011
2010
2012
2011
2010
$
8,047
$
7,122
$
6,688
$
592
$
614
$
17,295
(19,082)
—
195
15,631
22,086
(5,820)
(7,876)
18,134
18,029
1,267
1,404
(17,867)
(18,207)
—
352
11,584
19,325
(4,905)
(6,008)
—
187
7,447
14,144
(3,729)
—
—
411
197
435
2,902
(882)
—
—
411
197
289
2,915
(878)
—
588
1,436
—
411
197
131
2,763
(904)
—
Net amount charged to expense
$
8,390
$
8,412
$
10,415
$
2,020
$
2,037
$
1,859
(1) Effective January 1, 2011, the OPUC approved the deferral of certain pension expenses above or below the amount set in rates, with recovery
of these deferred amounts through the implementation of a balancing account, which includes the expectation of lower net periodic benefit costs
in future years. Deferred pension expense balances include accrued interest at the utility’s authorized rate of return. See Note 2.
Net periodic benefit costs above are reduced by amounts capitalized to utility plant based on approximately 30% to 40% payroll
overhead charge to construction work orders. In addition, a certain amount of net periodic benefit costs are recorded to the
regulatory balancing account for pensions, with the remaining net amount charged to expense and recognized in current
earnings.
Pension Benefits
Other Postretirement Benefits
2012
2011
2010
2012
2011
2010
Assumptions for net periodic benefit cost:
Weighted-average discount rate
4.51%
5.49%
6.01%
4.33%
5.16%
5.78%
Rate of increase in compensation
3.25-5.0%
3.25-5.0%
3.25-5.0%
Expected long-term rate of return
8.00%
8.25%
8.25%
n/a
n/a
n/a
n/a
n/a
n/a
Assumptions for year-end funded status:
Weighted-average discount rate
3.85%
4.51%
5.49%
3.56%
4.33%
5.16%
Rate of increase in compensation
3.25-5.0%
3.25-5.0%
3.25-5.0%
Expected long-term rate of return
7.50%
8.00%
8.25%
n/a
n/a
n/a
n/a
n/a
n/a
The impact of a change in retirement benefit costs on
operating results would be less than the amounts shown
above because 30% to 40% of these amounts would be
capitalized to utility plant as payroll overhead charges to
construction work orders, and a certain amount of increases
or decreases would be recorded to the regulatory balancing
account for pensions, with the remaining amount recognized
in current earnings.
The assumed annual increase in health care cost trend
rates used in measuring other postretirement benefits as of
December 31, 2012 were 8.5% for medical and 10.5% for
prescription drugs. Medical costs and prescription drugs are
assumed to decrease gradually each year to a rate of 5.0%
by 2023.
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:
In thousands
1% Increase
1% Decrease
Effect on net periodic
postretirement health care
benefit cost
Effect on the accumulated
postretirement benefit obligation
$
65
$
(58)
943
(841)
70
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, 2012 and 2011, and estimated future contributions and
payments:
In thousands
Pension Benefits
Other Benefits
Employer Contributions:
2011
2012
2013 (estimated)
Benefit Payments:
2010
2011
2012
Estimated Future
Benefit Payments:
2013
2014
2015
2016
2017
$
22,325
$
25,559
13,803
18,645
18,269
18,195
19,732
20,244
20,788
21,490
22,245
1,870
1,971
2,004
1,476
1,870
1,971
2,004
2,080
2,108
2,169
2,213
2018-2022
128,609
11,514
Employer Contributions to Company-Sponsored
Defined Benefit Pension Plans
We make contributions to our qualified defined benefit
pension plans based on actuarial assumptions and
estimates, tax regulations and funding requirements under
federal law. The Pension Protection Act of 2006 (the Act)
established new funding requirements for defined benefit
plans. The Act establishes a 100% funding target over
seven years for plan years beginning after December 31,
2008. In addition, in July 2012 the Moving Ahead for
Progress in the 21st Century Act (MAP-21). This legislation
changes several provisions affecting pension plans,
including temporary funding relief and Pension Benefit
Guaranty Corporation (PBGC) premium increases, which
reduces the level of minimum required contributions in the
near-term but generally increases contributions in the long-
run as well as increasing the operational costs of running a
pension plan. Our qualified defined benefit pension plans
are currently underfunded by $154.4 million at December
31, 2012. Including the impacts of MAP-21, we expect to
make contributions during 2013 of up to $15 million.
Multiemployer Pension Plan
In addition to the Company-sponsored defined benefit plans
referred to above, we contribute to a multiemployer pension
plan for our utility's union employees known as the Western
States Office and Professional Employees International
Union Pension Fund (Western States Plan) in accordance
with our collective bargaining agreement. The employer
identification number of the plan is 94-6076144. The cost of
this plan, and corresponding future liabilities, are in addition
to pension amounts in the tables above. The Western
States Plan is managed by a board of trustees that includes
equal representation from participating employers and labor
unions. Contribution rates are established by collective
bargaining agreements, and benefit levels are set by the
71
board of trustees based on the advice of an independent
actuary regarding the level of benefits that agreed-upon
contributions are expected to support.
The Western States Plan has reported an accumulated
funding deficit for the current plan year and remains in
critical status. A plan is considered to be in critical status if
its funded status is below 65%. Federal law requires
pension plans in critical status to adopt a rehabilitation plan
designed to restore the financial health of the plan.
Rehabilitation plans may specify benefit reductions,
contribution surcharges, or a combination of the two. The
Western States Plan trustees adopted a rehabilitation plan
that reduced benefit accrual rates and adjustable benefits
for active employee participants and increased future
employer contribution rates. These changes are expected to
improve the funded status of the plan. Our contributions to
the Western States Plan amounted to $0.4 million in 2012,
2011, and 2010 which is approximately 5% of the total
contributions to the plan by all employer participants.
Under the terms of our current collective bargaining
agreement, which became effective in July 2009, we can
withdraw from the Western States Plan at any time.
However, if the plan is underfunded at the time we withdraw,
we would be assessed a withdrawal liability. In accordance
with accounting rules for multiemployer plans, we have not
recognized these potential withdrawal liabilities on the
balance sheet. Currently, we have no intent to withdraw
from the plan, so we have not recorded a withdrawal liability.
Defined Contribution Plan
The Retirement K Savings Plan provided to our employees
is a qualified defined contribution plan under Internal
Revenue Code Section 401(k). Employer contributions to
this plan totaled $2.2 million in 2012, $2.4 million in 2011,
and $2.1 million in 2010. The Retirement K Savings Plan
includes an Employee Stock Ownership Plan.
Deferred Compensation Plans
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.
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 and U.S. SMALL/MID CAP
EQUITY. These are level 1 and 2 assets. The level 1 assets
consist of directly held stocks, and mutual funds with a
published net asset value (NAV). The level 2 assets consist
of a mutual fund where NAV is not publicly published but the
investment can be readily disposed of at NAV or market
value. Directly held stocks are valued at the closing price
reported in the active market on which the individual
security is traded, and mutual funds are valued at NAV. This
REAL RETURN STRATEGY. These are level 1 assets
representing a mutual fund with a published NAV. This
mutual fund is valued at NAV. 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
representing mutual funds without published NAV's but the
investment can be readily disposed of at NAV. The mutual
funds are valued at the net asset value of the shares held
by the plan at the valuation date. This asset class primarily
includes money market mutual funds.
The preceding valuation methods may produce a fair value
calculation that is not indicative of net realizable value or
reflective of future fair values. 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.
asset class includes investments primarily in U.S. common
stocks.
NON-U.S. EQUITY. These are level 1 and 2 assets. The level
1 assets consist of directly held stocks, and the level 2
assets consist of an open-end mutual fund and a
commingled trust where the NAV/unit price is not publicly
published but the investment can be readily disposed of at
the NAV/unit price. Directly held stocks are valued at the
closing price reported in the active market on which the
individual security is traded, and the mutual fund is valued
at NAV, while the commingled trust is valued at the unit
price of the trust. This asset class includes investments
primarily in foreign equity common stocks.
EMERGING MARKET EQUITY. These are level 1 assets
representing mutual funds with published NAV's. These
mutual funds are valued at NAV. This asset class includes
investments primarily in common stocks in emerging
markets.
FIXED INCOME. This is a level 2 asset consisting of a mutual
fund, valued at NAV, where NAV is not publicly published.
This asset class includes investments primarily in
investment grade debt and fixed income securities.
LONG GOVERNMENT/CREDIT. These are level 1 and 2
assets. The level 1 assets consist of a fixed-income mutual
fund with a published NAV. This mutual fund is valued at
NAV. The level 2 assets consist of directly held fixed-
income securities whose values are determined by closing
prices if available and by matrix prices for illiquid securities.
This asset class includes long duration fixed income
investments primarily in U.S. treasuries, U.S. government
agencies, municipal securities, mortgage-backed securities,
asset-backed securities, as well as U.S. and international
investment-grade corporate bonds.
HIGH YIELD BONDS. These are level 2 assets consisting of a
limited partnership where valuation is not publicly published
but the investment can be readily disposed of at market
value. This asset class includes investments primarily in
high yield bonds.
EMERGING MARKET DEBT. These are level 1 assets
consisting of a mutual fund with a published NAV. This
mutual fund is valued at NAV. This asset class includes
investments primarily in emerging market debt.
REAL ESTATE FUNDS. These are level 1 assets consisting of
a mutual fund with a published NAV. This mutual fund is
valued at NAV. This asset class includes investments
primarily in real estate investment trust (REIT) securities.
ABSOLUTE RETURN STRATEGY. These are level 2 assets
consisting of a hedge fund of funds where valuation is not
publicly published but the investment can be readily
disposed of at unit price. The hedge fund of funds is valued
at the weighted average value of investments in various
hedge funds which in turn are valued at the closing price of
the underlying securities. This asset class includes
investments primarily in common stocks and fixed income
securities.
72
The following table presents the fair value of plan assets, including outstanding receivables and liabilities, of the Retirement
Trust Fund as of December 31, 2012 and 2011:
In thousands
Investments
U.S. large cap equity
U.S. small/mid cap equity
Non-U.S. equity
Emerging markets equity
Fixed income
Long government/credit
High yield bonds
Emerging market debt
Real estate funds
Absolute return strategy
Real return strategy
Cash and cash equivalents
Total investments
Investments
U.S. large cap equity
U.S. small/mid cap equity
Non-U.S. equity
Emerging markets equity
Fixed income
Long government/credit
Real estate funds
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
December 31, 2012
Level 1
Level 2
Level 3
Total
$
29,047
$
1,891
$
— $
21,624
13,931
8,004
—
30,098
—
11,421
15,992
—
12,932
—
1,312
15,812
—
8,824
29,249
12,017
—
—
32,078
—
1,459
—
—
—
—
—
—
—
—
—
30,938
22,936
29,743
8,004
8,824
59,347
12,017
11,421
15,992
32,078
12,932
1,459
$
143,049
$
102,642
$
— $
245,691
December 31, 2011
Level 1
Level 2
Level 3
Total
$
36,236
$
— $
— $
—
22,158
10,208
19,121
—
—
—
15,475
—
27,310
11,587
—
—
18,897
—
30,475
—
9,290
—
—
—
—
—
15,317
—
—
—
36,236
27,310
33,745
10,208
19,121
18,897
15,317
30,475
15,475
9,290
$
103,198
$
97,559
$
15,317
$
216,074
December 31,
2012
2011
$
388
$
4,459
$
4,847
$
$
$
935
249,603
$
$
414
321
735
839
215,970
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, 2012:
In thousands
January 1, 2012 balance
Sales
December 31, 2012 balance
Level 3 Assets
Real Estate Funds
$
$
15,317
(15,317)
—
73
9. INCOME TAX
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:
Dollars in thousands
2012
2011
2010
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
Regulatory asset
impairment
Other, net
$ 36,386
$ 37,550
$ 42,745
4,773
4,945
5,803
(350)
(442)
(525)
1,718
1,647
1,647
(800)
(786)
(715)
2,700
(323)
—
468
—
507
Total provision for income
taxes
$ 44,104
$ 43,382
$ 49,462
Effective tax rate
42.4%
40.4%
40.5%
The increase in the effective income tax rate for 2012
compared to the same period in 2011 was primarily due to
the one-time, after-tax charge of $2.7 million in 2012 related
to the OPUC's rate case order that the Company could not
recover deferred amounts resulting from the 2009 Oregon
tax rate change.
The provision (benefit) for current and deferred income
taxes consists of the following:
In thousands
Current
Federal
State
Deferred
Federal
State
2012
2011
2010
$
1,693
$
130
$ (28,592)
99
1,792
31,767
10,545
42,312
(929)
(799)
1,441
(27,151)
35,481
8,700
44,181
69,159
7,454
76,613
Total provision for
income taxes
$ 44,104
$ 43,382
$ 49,462
Total income taxes paid
$
2,979
$
1,756
$ 22,600
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:
In thousands
Regulated utility:
Current
Deferred
Deferred investment
and energy tax credits
Non-utility business
segments:
Current
Deferred
2012
2011
2010
$
1,909
$
(4,646) $
(1,464)
39,864
50,152
47,741
(350)
(422)
(525)
41,423
45,084
45,752
(117)
3,846
(25,687)
2,798
2,681
(5,548)
(1,702)
29,397
3,710
Total provision for income
taxes
$ 44,104
$ 43,382
$ 49,462
The following table summarizes the tax effect of significant
items comprising our deferred income tax accounts for the
two years ended December 31:
In 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
2012
2011
$ 322,527
$ 292,235
—
60,253
51,424
43,824
2,106
65,755
35,638
43,373
$ 478,028
$ 439,107
$
(7,724) $
4,727
6,024
(1,235)
1,986
32,997
32,048
5,119
1,161
1,626
14,255
26,888
Deferred income tax liabilities, net
445,980
412,219
Deferred investment tax credits
624
990
Deferred income taxes and investment
tax credits
$ 446,604
$ 413,209
We have determined that we are more likely than not to
realize all recorded deferred tax assets as of December 31,
2012.
On December 17, 2010, President Obama signed into law
the Tax Relief, Unemployment Insurance Reauthorization,
and Job Creation Act of 2010 (Tax Relief Act), which allows
100% bonus depreciation for qualified property placed in
service between September 9, 2010 through December 31,
2011. It also extended the 50% bonus depreciation
deduction to qualifying property placed in service through
2012. On January 2, 2013, President Obama signed into
law the American Taxpayer Relief Act of 2012 (“the Act”).
74
This Act extended 50% bonus depreciation under §168(k)
through 2013 for MACRS property with a recovery period of
20 years or less.
The Company estimates that it has net operating loss (NOL)
carryforwards to 2013 of $83.4 million for federal and $76.6
million for Oregon. The NOL carryforwards will be carried
forward to reduce our current tax liability in future years. We
anticipate that we will be able to utilize the entire NOL
carryforwards before they expire in 20 years for federal and
15 years for Oregon.
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, 2012, we had no reserves for uncertain tax positions.
The Company settled the Oregon Department of Revenue
(ODOR) examination of tax years 2006 through 2009. This
settlement resulted in an additional $0.2 million state tax
expense, including interest, but that amount was offset by a
corresponding refund claim with the state of California. As of
December 31, 2012, the Company is subject to examination
by the Internal Revenue Service for the years 2009 through
2012.
Interest and penalties related to any future income tax
deficiencies are recorded within income tax expense in the
consolidated statements of income.
10. PROPERTY, PLANT, AND EQUIPMENT
The following table sets forth the major classifications of our
property, plant, and equipment and accumulated
depreciation at December 31:
In thousands
2012
2011
Utility plant in service
$2,435,886
$2,323,467
Utility construction work in progress
46,831
36,051
Less: Accumulated depreciation
789,201
749,603
Utility plant, net
1,693,516
1,609,915
$267.4 million at December 31, 2012 and 2011,
respectively. These accrued asset removal costs are
reflected on the balance sheets as regulatory liabilities. See
Note 2.
11. GAS RESERVES
Our gas reserves are stated at cost, net of regulatory
amortization, with the associated deferred tax benefits
recorded as liabilities on the balance sheet.
We entered into agreements with Encana to develop and
produce physical gas reserves. These agreements are
intended to provide long-term gas price protection for our
utility customers rather than serving as a source of gas
supply. Encana began drilling in 2011 under these
agreements, and gas which is currently being produced
from our working interests in these gas fields is sold by
Encana at then prevailing market prices, with revenues from
such sales, net of associated production costs, credited to
our cost of gas. The cost of gas, including a carrying cost for
the net rate base investment, is part of our annual Oregon
PGA filing, which allows us to recover our costs through
customer rates in a manner previously approved by the
OPUC. This transaction acted to hedge the cost of gas for
approximately 4% of our gas supplies for the year ended
December 31, 2012. The following table outlines our net gas
reserves investment at December 31:
In thousands
Gas reserves, current
Gas reserves, non-current
Less: Accumulated amortization
Total gas reserves
Less: Deferred taxes on gas reserves
2012
2011
$ 14,966
$ 4,463
92,179
48,597
7,486
99,659
28,329
1,146
51,914
15,630
Net investment in gas reserves
$ 71,330
$ 36,284
Variable Interest Entity Analysis
We concluded that the arrangement with Encana qualifies
as a variable interest entity (VIE), but that we are not the
primary beneficiary of these activities as defined by the
authoritative guidance related to consolidations due to the
fact that our interest represents a minor portion of total
extraction activities. We account for our investment in this
VIE on the cost basis, and it is included under gas reserves
on our balance sheet. Our maximum loss exposure related
to this VIE is limited to our current investment balance.
296,781
293,205
12. INVESTMENTS
Non-utility plant in service
Non-utility construction work in
progress
Less: Accumulated depreciation
6,510
23,195
8,379
17,623
Non-utility plant, net
280,096
283,961
Total property, plant, and equipment
$1,973,612
$1,893,876
The weighted average depreciation rate for utility assets
was 2.8% in 2012, 2011, and 2010. The weighted average
depreciation rate for non-utility assets was 2.2% in 2012
and 2011, and 2.5% in 2010.
Accumulated depreciation does not include the accumulated
provision for asset removal costs of $281.2 million and
75
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 other
investments at December 31:
In thousands
2012
2011
Investments in life insurance policies
$ 51,439
$ 51,911
Investments in gas pipeline joint ventures
14,216
14,340
Other
Total other investments
2,012
2,012
$ 67,667
$ 68,263
Investment in Life Insurance Policies
We have invested in key person life insurance contracts to
provide an indirect funding vehicle for certain long-term
employee and director benefit plan liabilities. The amount in
the above table is reported as cash surrender value, net of
policy loans.
not viable or will not go forward, then we could be required
to recognize a maximum charge of up to approximately
$13.2 million based on the current amount of our equity
investment net of cash and working capital at Palomar. We
will continue to monitor and update our impairment analysis
as required.
Equity Method Investments
Palomar, a wholly-owned subsidiary of PGH, is pursuing the
development of a new gas transmission pipeline that would
provide an interconnection with our utility distribution
system. PGH is owned 50% by NWN Energy and 50% by
TransCanada American Investments Ltd., an indirect wholly-
owned subsidiary of TransCanada Corporation.
Variable Interest Entity Analysis
PGH is a development stage VIE. As of December 31,
2012, there were no changes to our VIE analysis and, as
such, we continue to report Palomar under equity method
accounting based on the determination that we are not the
primary beneficiary of PGH’s activities, as defined by the
authoritative guidance related to consolidations, due to the
fact that we have a 50% share and there are no stipulations
that allow disproportionate influence over the entity. Our
investment in PGH and Palomar are 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% owner.
Impairment Analysis
Our investments in nonconsolidated entities accounted for
under the equity method are reviewed for impairment at
each reporting period and following updates to our
corporate planning assumptions. When it is determined that
a loss in value is other than temporary, a charge is
recognized for the difference between the investment’s
carrying value and its estimated fair value. Fair value is
based on quoted market prices when available, or on the
present value of expected future cash flows. Differing
assumptions could affect the timing and amount of a charge
recorded in any period.
In 2011, Palomar withdrew its original application with the
FERC for a proposed natural gas pipeline in Oregon and
informed FERC that it intended to re-file an application to
reflect changes in the project scope aligning the project with
the region’s current and future gas infrastructure needs.
Palomar continues working with customers in the Pacific
Northwest to further understand their gas transportation
needs and determine the commercial support for a revised
pipeline proposal. A new FERC certificate application is
expected to be filed to reflect a revised scope based on
these regional needs.
Due to project scope changes in 2011, a portion of the
assets were impaired and, as a result, we recorded a pre-
tax charge of $1.3 million for our share of these costs at
December 31, 2011. There have been no significant
changes to the project since this impairment, and we have
determined that our remaining equity investment was not
impaired at December 31, 2012 as the fair value of
expected cash flows from planned development exceeded
our remaining equity investment of $13.4 million at
December 31, 2012. However, if we learn that the project is
76
13. DERIVATIVE INSTRUMENTS
We enter into swap, option and combinations of option
contracts for the purpose of hedging natural gas. We
primarily use these derivative financial instruments to
manage commodity price variability related to our natural
gas purchase requirements. A small portion of our derivative
hedging strategy involves foreign currency exchange
transactions related to purchases of natural gas from
Canadian suppliers.
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 utility
customers. We also enter into financial derivatives, up to
prescribed limits, to hedge price variability related to these
physical gas supply contracts. The following table presents
the absolute notional amounts related to open positions on
derivative instruments:
Dollars in thousands
Open position absolute notional amount:
At December 31,
2012
2011
Natural gas (in millions of therms)
39.5
35.9
Foreign exchange
$ 13,231
$ 12,313
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 is set for the current gas contract year
are subject to our PGA incentive sharing mechanism, which
provides for either an 80% or 90% deferral of any gains and
losses as regulatory assets or liabilities, with the remaining
10% or 20% recognized in current income. All of our
commodity hedging for the 2012-13 gas year was
completed prior to the start of the gas year, and these hedge
prices were included in the Company's PGA filing.
Certain natural gas purchases from Canadian suppliers are
payable in Canadian dollars, including both commodity and
demand charges, which expose us to adverse changes in
foreign currency rates. Foreign currency forward contracts
are used to hedge the fluctuation in foreign currency
exchange rates for our commodity and commodity-related
demand charges paid in Canadian dollars. Foreign currency
contracts for commodity costs are purchased on a month-to-
month basis because the Canadian cost is priced at the
average noon-day exchange rate for each month. Foreign
currency contracts for demand costs have terms ranging up
to 12 months. The gains and losses on the shorter-term
currency contracts for commodity costs are recognized
immediately in cost of gas. The gains and losses on the
currency contracts for demand charges are not recognized
in current income because they are subject to a regulatory
deferral tariff and, as such, are recorded as a regulatory
asset or liability. The mark-to-market adjustment at
December 31, 2012 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.
Derivative hedge contracts are subject to a hedge
effectiveness test to determine the financial statement
treatment of each specific derivative. As of December 31,
2012, all of our derivatives were effective economic hedges
and either qualified or were expected to qualify for
regulatory deferral or hedge accounting treatment. The
effectiveness test applied to financial derivatives is
dependent on the type of derivative and its use. 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. All derivatives were
effective as of December 31, 2012.
The following table reflects the income statement presentation for the unrealized gains and losses from our derivative
instruments for the years ended December 31, 2012 and 2011. 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 standards.
In thousands
Cost of sales
Other comprehensive income (loss)
Less:
Amounts deferred to regulatory accounts on balance sheet
Total impact on earnings
2012
2011
Natural gas
commodity(1)
Foreign
exchange (2)
Natural gas
commodity(1)
Foreign
exchange (2)
$
$
(5,850) $
— $
(60,799) $
—
65
—
5,850
— $
(65)
— $
60,799
— $
—
(201)
201
—
(1) 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.
(2) 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.
No collateral was posted with or by our counterparties as of December 31, 2012 or 2011. We attempt to minimize the potential
exposure to collateral calls by counterparties to manage our liquidity risk. Counterparties generally allow a certain credit limit
threshold before requiring us to post collateral against loss positions. Given our counterparty credit limits and portfolio
diversification, we have not been subject to collateral calls in 2011 or 2012. Our collateral call exposure is set forth under credit
support agreements, which generally contain credit limits. We could also 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 adverse change. Based upon current contracts outstanding, which reflect
unrealized losses of $5.8 million at December 31, 2012, we have estimated the level of collateral demands, with and without
potential adequate assurance calls, using current gas prices and various credit downgrade rating scenarios for NW Natural as
follows:
In thousands
(Current
Ratings) A+/A3
BBB+/Baa1
BBB/Baa2
BBB-/Baa3
Speculative
With Adequate Assurance Calls
Without Adequate Assurance Calls
$
$
— $
— $
— $
— $
— $
— $
— $
— $
1,623
1,457
Credit Rating Downgrade Scenarios
As of December 31, 2012 and 2011, we realized net losses
of $70.2 million and $56.5 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 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 with
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
77
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, 2012 currently does not extend beyond
February 2016.
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 prudence review. All of our existing counterparties
currently have investment-grade credit ratings.
Fair Value
In accordance with fair value accounting, we include
nonperformance risk in calculating fair value adjustments.
This includes a credit risk adjustment based on the credit
spreads of our counterparties when we are in an unrealized
gain position, or on our own credit spread when we are in an
unrealized loss position. The inputs in our valuation
techniques include natural gas futures, volatility, credit
default swap spreads and interest rates. Additionally, 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, 2012. As of December 31, 2012
and 2011, the fair value was a liability of $5.8 million and
$61.0 million, respectively, using significant other
observable, or level 2, inputs. We have used no level 3
inputs in our derivative valuations. We did not have any
transfers between level 1 or level 2 during the years ended
December 31, 2012 and 2011.
14. COMMITMENTS AND CONTINGENCIES
Leases
We lease land, buildings and equipment under agreements
that expire in various years through 2108. Rental expense
under operating leases was $4.8 million, $5.4 million and
$5.1 million for the years ended December 31, 2012, 2011
and 2010, respectively. The table below reflects the future
minimum lease payments due under non-cancelable leases
at December 31, 2012. These commitments relate
principally to the lease of our office headquarters,
underground gas storage facilities, vehicles and computer
equipment.
In thousands
2013
2014
2015
2016
2017
Thereafter
Total
Operating
leases
Capital
leases
$
5,415
$
547
$
5,655
5,498
5,478
5,474
33,187
335
136
42
1
—
Minimum
lease
payments
5,962
5,990
5,634
5,520
5,475
33,187
$
60,707
$
1,061
$
61,768
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, 2012:
In thousands
2013
2014
2015
2016
2017
Thereafter
Total
Less: Amount
representing
interest
Total at present
value
Gas
Purchase
Agreements
Pipeline
Capacity
Purchase
Agreements
Pipeline
Capacity
Release
Agreements
$
104,443
$
90,823
$
3,464
12,166
—
—
—
—
116,609
86,119
72,707
61,398
48,503
240,929
600,479
—
—
—
—
—
3,464
129
87,263
—
$
116,480
$
513,216
$
3,464
Our total payments for fixed charges under capacity
purchase agreements were $94.3 million in 2012, $94.2
million in 2011, and $91.4 million in 2010. Included in the
amounts were reductions for capacity release sales of $4.2
million for 2012, $3.1 million for 2011, and $4.2 million for
2010. 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
See Note 15 Environmental Matters for a discussion of
environmental commitments and contingencies.
78
15. ENVIRONMENTAL MATTERS
We own, or previously owned, properties that may require
environmental remediation or action. We estimate the range
of loss for environmental liabilities based on current
remediation 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.
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 possible loss and the fact that the high end of the
range cannot be reasonably estimated. Unless there is an
estimate within a range of possible losses that is more likely
than other cost estimates within that range, we record the
liability at the low 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 our
continued evaluation and clarification concerning our
responsibility, the complexity of environmental laws and
regulations and the determination by regulators of
remediation alternatives.
Environmental site remediation costs are deferred under
regulatory approval from the OPUC and WUTC. In addition,
the OPUC authorized an SRRM that allows the Company to
recover prudently incurred environmental site remediation
costs, subject to an earnings test that will be defined in a
future proceeding. Actual cost recovery under SRRM will
depend upon future insurance recoveries, future
expenditures, annual prudence reviews, and the impacts of
any earnings test the OPUC may adopt in a subsequent
proceeding. Cost recovery and carrying charges on
amounts deferred for costs associated with services
provided to Washington customers will be determined in a
future proceeding. We annually review all regulatory assets
for recoverability and more often if circumstances warrant. If
we should determine that all or a portion of these regulatory
assets 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 in the
period such determination is made.
In December 2010, NW Natural commenced litigation
against certain of its historical liability insurers in Multnomah
County Circuit Court, State of Oregon (see Item 3. Legal
Proceedings). NW Natural seeks damages in excess of $50
million in losses it has incurred to date, as well as
declaratory relief for additional losses it expects to incur in
the future.
The following table summarizes information regarding liabilities related to environmental sites, which are recorded in other
current liabilities and other noncurrent liabilities on the balance sheet at December 31:
Thousands
Portland Harbor site:
Gasco/Siltronic Sediments
Other Portland Harbor
Gasco Upland site
Siltronic Upland site
Central Service Center site
Front Street site
Oregon Steel Mills
Total
Current Liabilities
Non-Current Liabilities
2012
2011
2012
2011
$
2,207
$
1,614
$
36,087
$
35,797
1,767
18,722
637
140
993
—
1,893
14,092
887
—
1,697
—
3,160
5,028
379
396
—
185
7,066
8,900
128
495
—
120
$
24,466
$
20,183
$
45,235
$
52,506
In addition, the following table presents information
regarding the total amount of cash paid for environmental
sites and the total regulatory asset deferred as of December
31:
Thousands
Cash paid
2012
2011
$
71,124
$
55,553
Total regulatory asset deferral(1)
126,482
105,670
(1) Total regulatory asset deferral includes cash paid, remaining
liability, interest, and insurance reimbursement.
PORTLAND HARBOR SITE. The Portland Harbor is an
EPA listed Superfund site that is approximately 11 miles
long on the Willamette River and is adjacent to NW
Natural's Gasco upland and Siltronic upland sites. We have
been notified that we are a potentially responsible party to
the Superfund site and we have joined with other potentially
responsible parties (the Lower Willamette Group or LWG) to
develop a Portland Harbor Remedial Investigation/
Feasibility Study (RI/FS). The LWG submitted a draft
Feasibility Study (FS) to EPA in March 2012 that provides a
range of remedial costs for the entire Portland Harbor
Superfund Site, which includes the Gasco/Siltronic
Sediment site, discussed below. The range of costs
estimated for various remedial alternatives for the entire
Portland Harbor, as provided in the draft FS, is $169 million
to $1.8 billion. NW Natural's potential liability is a portion of
the costs of the remedy EPA will select for the entire
79
Portland Harbor Superfund site. The cost of that remedy is
expected to be allocated among more than 100 potentially
responsible parties. NW Natural is participating in a non-
binding allocation process in an effort to settle this potential
liability. We manage our liability related to the Superfund
site as two distinct remediation projects, the Gasco/Siltronic
Sediment and Other Portland Harbor projects.
Gasco/Siltronic Sediments. In 2009, NW Natural and Siltronic
Corporation entered into a separate Administrative Order on
Consent with EPA to evaluate and design specific remedies
for sediments adjacent to the Gasco upland and Siltronic
upland sites. NW Natural submitted a draft Engineering
Evaluation/Cost Analysis (EE/CA) to the EPA in May 2012 to
provide the estimated cost of potential remedial alternatives
for this site. At this time, the estimated costs for the various
sediment remedy alternatives in the draft EE/CA range from
$38.3 million to $350 million. We have recorded a liability of
$34.0 million for the sediment clean-up, which reflects the
low end of the EE/CA range. We have recorded an
additional liability of $4.3 million for the additional studies
and design work needed before the clean-up can occur, and
for regulatory oversight throughout the clean-up. At this
time, we believe sediments at this site represent the largest
portion of our liability related to the Portland Harbor site,
discussed above.
Other Portland Harbor. NW Natural incurs costs related to its
membership in the LWG which is performing the RI/FS for
EPA. NW Natural also incurs costs related to natural
resource damages. In 2008, the Portland Harbor Natural
Resource Trustee Council advised a number of potentially
responsible parties that it intended to pursue natural
resource damage claims at the Portland Harbor Superfund
site. The Company and other parties have signed a
cooperative agreement with the Natural Resource Trustees
to participate in a phased natural resource damage
assessment to estimate liabilities to support an early
restoration-based settlement of natural resource damage
claims. We have accrued a liability for these claims which is
at the low end of the range of the potential liability. This
liability is not included in the range of costs provided in the
draft FS for the Portland Harbor.
Gasco upland site. NW Natural owns a former gas
manufacturing plant that was closed in 1956 (Gasco site)
and is adjacent to the Portland Harbor site described above.
The Gasco site has been under investigation by us for
environmental contamination under the ODEQ Voluntary
Clean-Up Program. It is not included in the range of
remedial costs for the Portland Harbor site. We manage the
Gasco site in two parts, the uplands portion and the
groundwater source control action.
In May 2007, we completed a revised Remedial
Investigation Report for the uplands portion and submitted it
to ODEQ for review. We have recognized a liability for this
portion of the site remediation which is at the low end of the
range of potential liability.
In 2012, ODEQ approved our final design remediation plan
for the groundwater source control portion and we began
construction in October 2012. Based on the information
currently available for groundwater source control at the
80
Gasco site and our current assumptions regarding the
effectiveness of the source control system, we have
estimated a range of liability between $14 million and $30
million, for which we have recorded an accrued liability
which is at the low end of the range of the potential
liability. We are uncertain about the range due to potential
additional ODEQ requirements and actions needed to meet
those requirements, including uncertainty about how to meet
the agreed standards set by ODEQ subsequent to the initial
testing of the system and as part of the final remedy for the
upland portion of the Gasco site.
Other sites. In addition to those sites above, we have
environmental exposures at four other sites, Siltronic,
Central Service Center, Front Street, and Oregon Steel
Mills. Due to the uncertainty of the design of remediation,
regulation, timing of the liabilities, and in the case of the
Oregon Steel Mills site, pending litigation, liabilities for each
of these sites has been recognized at their respective low
end of the range of potential liability and the high end of the
range cannot be reasonably estimated.
Siltronic upland site. Siltronic is the location of a
manufactured gas plant formerly owned by NW Natural.
We are currently conducting an investigation of
manufactured gas plant wastes on the uplands at this site
for the ODEQ.
Central Service Center site. We are currently performing an
environmental investigation of the property under the
ODEQ's Independent Cleanup Pathway. This site is on
ODEQ's list of sites in which releases of hazardous
substances have been confirmed and cleanup is necessary.
Front Street site. The Front Street site was the former
location of a gas manufacturing plant we operated. Studies
for source control investigation have been presented to
ODEQ and a final sampling plan required by ODEQ is
currently being developed.
Oregon Steel Mills site. See “Legal Proceedings,” below.
Legal Proceedings
NW Natural is 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, NW Natural
does 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 as we would expect to
receive insurance recovery or rate recovery. See also Part
II, Item 1, “Legal Proceedings.”
OREGON STEEL MILLS SITE. In 2004, NW Natural was
served with a third-party complaint by the Port of Portland
(the 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. 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.
NORTHWEST NATURAL GAS COMPANY
QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
Quarter ended
In thousands, except share data
March 31
June 30
Sept. 30
Dec. 31
2012
Operating revenues
Net income (loss)
Basic earnings (loss) per share(1)
Diluted earnings (loss) per share(1)
2011
Operating revenues
Net income (loss)
Basic earnings (loss) per share(1)
Diluted earnings (loss) per share(1)
$
309,639
$
103,991
$
87,501
$
40,607
1.52
1.51
1,409
0.05
0.05
(10,558)
(0.39)
(0.39)
$
315,133
$
157,354
$
90,916
$
40,773
1.53
1.53
2,193
0.08
0.08
(8,312)
(0.31)
(0.31)
229,476
28,397
1.06
1.05
264,652
29,244
1.09
1.09
(1) Quarterly earnings (loss) per share are based upon the average number of common shares outstanding during each quarter. Variations in
earnings between quarterly periods are due primarily to the seasonal nature of our business.
NORTHWEST NATURAL GAS COMPANY
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
COLUMN A
COLUMN B
COLUMN C
Additions
COLUMN D
COLUMN E
Deductions
In thousands (year ended December 31)
2012
Reserves deducted in balance sheet from
assets to which they apply:
Balance at
beginning of
period
Charged to
costs and
expenses
Charged to
other accounts
Net write-offs
Balance at end
of period
Allowance for uncollectible accounts
$
2,895
$
1,130
$
— $
1,507
$
2,518
2011
Reserves deducted in balance sheet from
assets to which they apply:
Allowance for uncollectible accounts
2,950
1,919
2010
Reserves deducted in balance sheet from
assets to which they apply:
Allowance for uncollectible accounts
3,125
1,717
—
—
1,974
2,895
1,892
2,950
81
ITEM 9. CHANGES IN AND DISAGREEMENTS
WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None.
periods specified in the Securities and Exchange
Commission (SEC) 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.
ITEM 9A. CONTROLS AND PROCEDURES
(b) Changes in Internal Control Over Financial Reporting
(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
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, 2012 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.
82
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 23, 2013 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 23, 2013 Annual Meeting of Shareholders is hereby incorporated by reference.
Name
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
David A. Weber
Age at
Dec. 31,
2012
55
51
58
57
59
59
57
55
57
56
53
Positions held during last five years
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).
Executive Vice President Operations and Regulation (2013- ); Senior
Vice President and Chief Financial Officer (2004-2013).
Senior Vice President and General Counsel (2013- ); Vice President
and General Counsel (2005-2013).
Senior Vice President and Chief Administrative Officer (2013- ); Senior
Vice President (2008- ); Vice President, Human Resources
(2000-2007).
Vice President, Business Development and Energy Supply/Chief
Strategic Officer (2007- ); Managing Director, Gas Operations and
Wholesale Services (2005-2006); Managing Director and Chief
Strategic Officer (2003-2005).
Vice President, Utility Services (2007- ); Director of Utility Operations,
Districts and Managed Labor Relations (2004-2006).
Vice President, Utility Operations (2007- ); Managing Director, Utility
Services (2005-2006); Director, Utility Services (2004-2005).
Vice President Regulation and Treasurer (2013- ); Vice President,
Finance and Regulation (2009-2013); Assistant Treasurer (2008- );
General Manager of Rates and Regulatory Affairs (2002-2009).
Senior Vice President and Chief Financial Officer (2013- ); Assistant
Secretary (2007- ); Treasurer and Controller (1999-2013).
Vice President Legal, Risk and Land (2013- ); Deputy General
Counsel (2010-2013); Chief Governance Officer and Corporate
Secretary (2008- ); Chief Compliance Officer and Assistant General
Counsel, Tektronix, Inc. (2005-2008).
President and Chief Executive Officer, NW Natural Gas Storage, LLC
and Gill Ranch Storage, LLC (2012- ); Interim President and Chief
Executive Officer, NW Natural Gas Storage LLC, and Gill Ranch
Storage, LLC (2011-2012); Chief Operating Officer NW Natural Gas
Storage, LLC and Gill Ranch Storage LLC (November 2010 - January
2011); Managing Director of Information Services and Chief
Information Officer (2005 - 2011); Director of Information Services and
Chief Information Officer (2001-2005).
Each executive officer serves successive annual terms;
present terms end on May 23, 2013. 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 that is 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.
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 23, 2013 Annual Meeting of Shareholders is hereby
incorporated by reference. Information related to Executive
Officers as of December 31, 2012 is reflected in Part III,
Item 10, above.
83
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, 2012 (see Note 6 to the Consolidated Financial Statements):
Plan Category
Equity compensation plans approved by security holders:
LTIP Performance Share Awards (Target Award)(1)(2)
LTIP Restricted Stock Units (Target Award)(1)(2)
LTIP Stock Options(2)
Restated Stock Option Plan
Employee Stock Purchase Plan
Equity compensation plans not approved by security holders:
Executive Deferred Compensation Plan (EDCP)(3)
Directors Deferred Compensation Plan (DDCP)(3)
Deferred Compensation Plan for Directors and Executives (DCP)(4)
Total
(a)
(b)
(c)
Number of securities
to be issued upon
exercise of
outstanding options,
warrants and rights
Weighted-average
exercise price of
outstanding options,
warrants and rights
Number of securities
remaining available
for future issuance
under equity
compensation plans
(excluding securities
reflected in column
(a))
114,707
24,864
—
529,925
$
17,560
2,748
59,324
125,282
874,410
n/a
n/a
—
42.22
39.56
n/a
n/a
n/a
451,922
451,922
250,000
—
120,238
n/a
n/a
n/a
822,160
(1) Shares issued pursuant to performance share awards and restricted stock units under 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, 2012, the number of shares shown in column (a) would increase by 114,707 shares and the number of shares shown in column
(c) would decrease by the same amount of shares.
The aggregate 451,922 shares available for future issuance under the LTIP as Restricted Stock Units or Performance Share Awards are also
available for issuance of LTIP Stock Options. Therefore, a total of 701,922 shares are available for LTIP Stock Option issuance at December
31, 2012. The 250,000 shares available for LTIP Stock Options at December 31, 2012 are not available for issuance of LTIP Restricted Stock
Units or Performance Share Awards.
(2)
(3) Prior to January 1, 2005, deferred amounts were credited, at the participant’s election, to either a “cash account” or a “stock account.” If deferred
amounts were credited to stock accounts, such accounts were credited with a number of shares of NW Natural common stock based on the
purchase price of the common stock on the next purchase date under our Dividend Reinvestment and Direct Stock Purchase Plan, and such
accounts were credited with additional shares based on the deemed reinvestment of dividends. Cash accounts are credited quarterly with
interest at a rate equal to Moody’s Average Corporate Bond Yield plus two percentage points, subject to a 6% 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.
(4) Effective January 1, 2005, the EDCP and DDCP were closed to new participants and replaced with 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.
The information captioned “Beneficial Ownership of Common Stock by Directors and Executive Officers” contained in our
definitive Proxy Statement for the May 23, 2013 Annual Meeting of Shareholders is incorporated herein by reference.
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 23, 2013 Annual
Meeting of Shareholders is hereby incorporated by
reference.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND
SERVICES
The information captioned “2012 and 2011 Audit Firm Fees”
in the Company’s definitive Proxy Statement for the May 23,
2013 Annual Meeting of Shareholders is hereby
incorporated by reference.
84
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
(a) The following documents are filed as part of this report:
PART IV
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 87.
85
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the
Securities Exchange Act of 1934, the registrant has duly
caused this report to be signed on its behalf by the
undersigned, thereunto duly authorized.
NORTHWEST NATURAL GAS COMPANY
By: /s/ Gregg S. Kantor
Gregg S. Kantor
President and Chief Executive Officer
Date: March 1, 2013
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons
on behalf of the registrant and in the capacities and on the date indicated.
Signature
/s/ Gregg S. Kantor
Gregg S. Kantor
President and Chief Executive Officer
/s/ Stephen P. Feltz
Stephen P. Feltz
Senior Vice President and Chief Financial Officer
/s/ Brody J. Wilson
Brody J. Wilson
Acting 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
Title
Date
Principal Executive Officer and Director
March 1, 2013
Principal Financial Officer
March 1, 2013
Principal Accounting Officer
March 1, 2013
)
)
)
)
)
)
)
)
)
)
)
)
)
)
March 1, 2013
)
)
)
)
)
)
)
)
)
)
)
Director
Director
Director
Director
Director
Director
Director
Director
Director
86
NORTHWEST NATURAL GAS COMPANY
Exhibit Index to Annual Report on Form 10-K
For the Fiscal Year Ended December 31, 2012
Exhibit Number Document
*3a.
*3b.
*4a.
*4b.
*4c.
*4d.
*4e.
*4f.
*4g.
*4h.
*4i.
*4j.
Restated Articles of Incorporation, as filed and effective May 31, 2006 and amended June 3, 2008 (incorporated
herein by reference to Exhibit 3.1 to Form 10-Q for the period ending June 30, 2008, File No. 1-15973).
Bylaws as amended May 24, 2012 (incorporated herein by reference to Exhibit 3.1 to Form 8-K dated May 24, 2012,
File No. 1-15973).
Copy of Mortgage and Deed of Trust, dated as of July 1, 1946, to Bankers Trust and R. G. Page (to whom Stanley
Burg is now successor), Trustees (incorporated herein by reference to Exhibit 7(j) in File No. 2-6494); and copies of
Supplemental Indentures Nos. 1 through 14 to the Mortgage and Deed of Trust, dated respectively, as of June 1,
1949, March 1, 1954, April 1, 1956, February 1, 1959, July 1, 1961, January 1, 1964, March 1, 1966, December 1,
1969, April 1, 1971, January 1, 1975, December 1, 1975, July 1, 1981, June 1, 1985 and November 1, 1985
(incorporated herein by reference to Exhibit 4(d) in File No. 33-1929); Supplemental Indenture No. 15 to the Mortgage
and Deed of Trust, dated as of July 1, 1986 (filed as Exhibit 4(c) in File No. 33-24168); Supplemental Indentures Nos.
16, 17 and 18 to the Mortgage and Deed of Trust, dated, respectively, as of November 1, 1988, October 1, 1989 and
July 1, 1990 (incorporated herein by reference to Exhibit 4(c) in File No. 33-40482); Supplemental Indenture No. 19 to
the Mortgage and Deed of Trust, dated as of June 1, 1991 (incorporated herein by reference to Exhibit 4(c) in File No.
33-64014); and Supplemental Indenture No. 20 to the Mortgage and Deed of Trust, dated as of June 1, 1993
(incorporated herein by reference to Exhibit 4(c) in File No. 33-53795).
Copy of Indenture, dated as of June 1, 1991, between the Company and Bankers Trust Company, Trustee, relating to
the Company’s Unsecured Medium-Term Notes (incorporated herein by reference to Exhibit 4(e) in File No.
33-64014).
Officers’ Certificate dated June 12, 1991 creating Series A of the Company’s Unsecured Medium-Term Notes
(incorporated herein by reference to Exhibit 4e. to Form 10-K for 1993, File No. 0-994).
Officers’ Certificate dated June 18, 1993 creating Series B of the Company’s Unsecured Medium-Term Notes
(incorporated herein by reference to Exhibit 4f. to Form 10-K for 1993, File No. 0-994).
Officers’ Certificate dated January 17, 2003 relating to Series B of the Company’s Unsecured Medium-Term Notes
and supplementing the Officers’ Certificate dated June 18, 1993 (incorporated herein by reference to Exhibit 4f.(1) to
Form 10-K for 2002, File No. 0-994).
Form of Secured Medium-Term Notes, Series B (incorporated herein by reference to Exhibit 4.1 to Form 8-K dated
October 4, 2004, File No. 1-15973).
Form of Unsecured Medium-Term Notes, Series B (incorporated herein by reference to Exhibit 4.2 to Form 8-K dated
October 4, 2004, File No. 1-15973).
Gill Ranch Note Purchase Agreement, dated November 30, 2011, among Gill Ranch Storage, LLC and the parties
listed thereto (incorporated herein by reference to Exhibit 4m. to Form 10-K for 2011, File No. 1-15973).
Twenty-First Supplemental Indenture, providing, among other things, for First Mortgage Bonds, 4.00% Series Due
2042, dated as of October 15, 2012, by and between Northwest Natural Gas Company, Deutsche Bank Trust
Company Americas (formerly known as Bankers Trust Company), and Stanley Burg (Successor to R.G. Page and
J.C. Kennedy) (incorporated herein by reference to Exhibit 4.1 to Form 8-K dated October 26, 2012, File No.1-15973).
Form of Credit Agreement among Northwest Natural Gas Company and the parties thereto, with JPMorgan Chase
Bank, N.A. as administrative agent and U.S. Bank, N.A. and Wells Fargo Bank, N.A. as co-syndication agents, dated
as of December 20, 2012 (incorporated herein by reference to Exhibit 4.1 to Form 8-K dated December 20, 2012, File
No.1-15973).
87
12
21
23
Statement re computation of ratios of earnings to fixed charges.
Subsidiaries of Northwest Natural Gas Company.
Consent of PricewaterhouseCoopers LLP.
31.1
Certification of Principal Executive Officer Pursuant to Rule 13a-14(a)/15-d-14(a), Section 302 of the Sarbanes-Oxley
Act of 2002.
31.2
Certification of Principal Financial Officer Pursuant to Rule 13a-14(a)/15-d-14(a), Section 302 of the Sarbanes-Oxley
Act of 2002.
32.1
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.
Executive Supplemental Retirement Income Plan 2010 Restatement (incorporated herein by reference to Exhibit 10b.
to Form 10-K for 2009, File No. 1-15973).
*10c.
Supplemental Executive Retirement Plan, effective September 1, 2004 restated 2011 (incorporated herein by
reference to Exhibit 10.1 to Form 10-Q for the quarter ended September 30, 2011, File No. 1-15973).
*10d.
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).
*10e.
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).
*10f.
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).
*10g.
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).
*10h.
Form of Restated Stock Option Plan Agreement (incorporated herein by reference to Exhibit 10h. to Form 10-K for
2009, File No. 1-15973).
*10i.
Executive Deferred Compensation Plan, effective as of January 1, 1987, restated as of February 26, 2009
(incorporated herein by reference to Exhibit 10e. to Form 10-K for 2008, File No. 1-15973).
*10j.
Directors Deferred Compensation Plan, effective June 1, 1981, restated as of February 26, 2009 (incorporated herein
by reference to Exhibit 10f. to Form 10-K for 2008, File No. 1-15973).
*10k.
Deferred Compensation Plan for Directors and Executives effective January 1, 2005, restated as of January 1, 2012
(incorporated herein by reference to Exhibit 10k. to Form 10-K for 2011, File No. 1-15973).
*10l.
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).
*10l.(1) 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).
88
*10m. 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).
*10n.
Executive Annual Incentive Plan, effective February 23, 2012 (incorporated herein by reference to Exhibit 10n. to
Form 10-K for 2011, File No. 1-15973).
*10o.
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).
*10p.
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).
*10q.
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).
10r.
Northwest Natural Gas Company Long-Term Incentive Plan, as amended and restated effective May 24, 2012.
*10s.
Form of Long-Term Incentive Award Agreement under the Long-Term Incentive Plan (2010-2012) (incorporated herein
by reference to Exhibit 10t. to Form 10-K for 2011, File No. 1-15973).
*10t.
Form of Long-Term Incentive Award Agreement under the Long-Term Incentive Plan (2011-2013) (incorporated herein
by reference to Exhibit 10u. to Form 10-K for 2011, File No. 1-15973).
*10u.
Form of Long-Term Incentive Award Agreement under the Long-Term Incentive Plan (2012-2014) (incorporated herein
by reference to Exhibit 10v. to Form 10-K for 2011, File No. 1-15973).
10v.
Form of Long-Term Incentive Award Agreement under the Long-Term Incentive Plan (2013-2015).
*10w.
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).
*10x.
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).
*10y.
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).
10aa.
Form of Restricted Stock Unit Award Agreement under the Long-Term Incentive Plan (2013).
*10bb. Form of Restricted Stock Unit Award Agreement under the Long-Term Incentive Plan (2012) (incorporated herein by
reference to Exhibit 10.1 to Form 8-K dated December 14, 2011, File No. 1-15973).
10cc.
Annual Incentive Plan for NW Natural Gas Storage, LLC, as amended February 2, 2012.
10dd.
Long Term Incentive Plan for NW Natural Gas Storage, LLC.
10ee.
Form of Change in Control Severance Agreement between the Company and an executive officer.
101.
The following materials from Northwest Natural Gas Company Annual Report on Form 10-K for the fiscal year ended
December 31, 2012, formatted in Extensible Business Reporting Language (XBRL):
(i) Consolidated Statements of Income;
(ii) Consolidated Balance Sheets;
(iii) Consolidated Statements of Cash Flows; and
(iv) Related notes.
*Incorporated herein by reference as indicated
89
NORTHWEST NATURAL GAS COMPANY
Ratios of Earnings to Fixed Charges
(Unaudited)
EXHIBIT 12
In thousands, except share data
Fixed Charges, as defined:
Interest on Long-Term Debt
Other Interest
Amortization of Debt Discount and Expense
Interest Portion of Rentals
Total Fixed Charges, as defined
Earnings, as defined:
Net Income
Taxes on Income
Fixed Charges, as above
Total Earnings, as defined
Ratios of Earnings to Fixed Charges
Year Ended December 31,
2012
2011
2010
2009
2008
$
$
$
39,175
2,314
1,848
1,864
45,201
37,515
2,976
1,729
2,213
44,433
$
39,198
1,587
1,766
2,130
44,681
$
37,447
1,937
1,503
1,735
42,622
33,605
4,022
700
1,551
39,878
59,855
44,104
45,201
$ 149,160
3.30
63,898
43,382
44,433
$ 151,713
3.41
72,667
49,462
44,681
$ 166,810
3.73
75,122
46,671
42,622
$ 164,415
3.86
69,525
40,678
39,878
$ 150,081
3.76
90
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, 333-139819 and 333-180350) and in the Registration Statement on Form S-3 (No. 333-171596) of
Northwest Natural Gas Company of our report dated March 1, 2013 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
March 1, 2013
91
CERTIFICATION
I, Gregg S. Kantor, certify that:
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: March 1, 2013
/s/ Gregg S. Kantor
Gregg S. Kantor
President and Chief Executive Officer
92
CERTIFICATION
I, Stephen P. Feltz, certify that:
EXHIBIT 31.2
1. I have reviewed this annual report on Form 10-K for 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: March 1, 2013
/s/ Stephen P. Feltz
Stephen P. Feltz
Senior Vice President and Chief Financial Officer
93
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 STEPHEN P. FELTZ, the Senior
Vice President and Chief Financial Officer, of NORTHWEST NATURAL GAS COMPANY (the Company), DOES HEREBY
CERTIFY that:
1. The Company’s Annual Report on Form 10-K for the year ended December 31, 2012 (the Report) fully complies with
the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and
2. 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 1st day of March
2013.
/s/ Gregg S. Kantor
Gregg S. Kantor
President and Chief Executive Officer
/s/ Stephen P. Feltz
Stephen P. Feltz
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.
94
[THIS PAGE INTENTIONALLY LEFT BLANK]
Corporate iNformatioN
inveStor & ShAreholder inFormAtion
robert hess
Director, Investor Relations
(800) 422-4012, Ext. 2388
rsh@nwnatural.com
chu lee
Manager, Shareholder Services
(800) 422-4012, Ext. 3412
c4l@nwnatural.com
Stock trAnSFer Agent
And regiStrAr
truStee And bond pAying Agent
For all bond issues:
For the common stock:
Deutsche Bank Trust Company Americas
American Stock Transfer & Trust Company
60 Wall Street
6201 15th Avenue
Brooklyn, NY 11219
(888) 777-0321
web: amstock.com
email: info@amstock.com
New York, NY 10005
(800) 735-7777
community And SuStAinAbility
report
low-income weAtherizAtion
progrAm
energy-eFFiciency progrAmS
NW Natural partners with Energy Trust of
Learn more about NW Natural’s community
NW Natural offers a program to our low-
Oregon to offer our Oregon and Washington
involvement and philanthropic contributions,
income customers designed to reduce their
customers energy-efficiency programs and
environmental stewardship, employee safety
natural gas use through the installation of
services. Learn more about the results of
efforts and other company initiatives.
energy-efficient equipment and weather-
these programs and the benefits to our
View the Community & Sustainability
innovative Oregon program.
Annual Report at nwnatural.com/
View the Energy Trust of Oregon
aboutnwnatural/community
View the Low-Income Energy-Efficiency
Annual Report at nwnatural.com/
ization measures. Find out more about this
customers.
Program Annual Report at nwnatural.com/
aboutnwnatural/environmentalstewardship
aboutnwnatural/environmentalstewardship
N
W
N
a
t
u
r
a
l
2
0
1
2
A
n
n
u
a
l
R
e
p
o
r
t
•
S
m
a
l
l
S
t
e
p
s
A
d
d
U
p
.
220 NW Second Avenue
Portland, Oregon 97209
nwnatural.com
NYSE: NWN