AN ENVIRONMENT RICH WITH
POSSIBILITIES
2013 ANNUAL REPORT
CORPORATE PROFILE
NW Natural (NYSE: NWN) is a
155-year-old natural gas local
distribution and storage company
headquartered in Portland, Oregon.
NW Natural serves about 695,000
utility customers in Oregon and
OVERVIEW
FINANCIAL
Financial facts ($000):
Operating revenues
Utility margin
Net income
Southwest Washington, and provides
Financial ratios (%):
gas storage to customers on the
Return on average common equity
West Coast. In keeping with its steady
Capital structure at year-end:
growth, the company has increased
dividends paid to shareholders for
58 consecutive years.
SERVICE TERRITORY
AND STORAGE FACILITIES
WASHINGTON
ASTORIA
MIST STORAGE
VANCOUVER
GASCO LNG
PORTLAND
TRAINING
CENTER
LINCOLN CITY
SALEM
ALBANY
NEWPORT LNG
Long-term debt
Common stock equity
COMMON STOCK
Shareholder data (000):
Average shares outstanding – diluted
Year-end shares outstanding
Per share data ($):
Diluted earnings
Dividends paid
Book value at year-end
Market value at year-end
Degree days
Customers at year-end
Employees at year-end
THE DALLES
OPERATING
Gas sales and transportation deliveries (000 therms)
1,146,431
1,111,769
EUGENE
OREGON
DIVIDENDS PAID ON COMMON STOCK (per share)
February 15
COOS BAY
KEY
NW NATURAL SERVICE TERRITORY
TRAINING CENTER
REGIONAL RESOURCE CENTER
LNG PLANT
MIST STORAGE
GILL RANCH STORAGE
HEADQUARTERS
May 15
August 15
November 15
Total dividends paid
$ 1.825
$ 1.790
2013
2012
PERCENT
INCREASE
(DECREASE )
4
3
3
-
(2 )
2
-
1
3
2
2
(3 )
3
5
1
(1 )
758,518
353,884
60,538
730,607
344,527
58,779
8.2
47.6
52.4
27,027
27,075
2.24
1.83
27.77
42.82
8.2
48.7
51.3
26,907
26,917
2.18
1.79
27.11
44.20
4,379
694,873
1,081
4,152
685,941
1,092
$ 0.455
$ 0.445
0.455
0.455
0.460
0.445
0.445
0.455
NEVADA
DILUTED EARNINGS PER SHARE
(in dollars)
DIVIDENDS PAID PER SHARE
(in dollars)
SAN FRANCISCO
GILL RANCH
FRESNO
CALIFORNIA
$3.00
$2.50
$2.00
$1.50
$1.00
$0.50
$0.00
LOS ANGELES
2009
2010
2011
2012
2013
Diluted earnings per share were $2.24 in 2013,
up 3% over 2012.
$1.85
$1.80
$1.75
$1.70
$1.65
$1.60
$1.55
$1.50
$1.45
2009
2010
2011
2012
2013
Annual dividends paid per share in 2013
increased for the 58th consecutive year. The
current indicated annual dividend is $1.84 per
share.
3
LETTER TO SHAREHOLDERS
Gregg Kantor,
President and CEO
We were one of the nation’s first utilities to replace all of our cast iron pipes, and will be one of the first to replace all bare steel pipes.
In 2013, NW Natural delivered earnings of $2.24 per share, achieved a number of important
operating milestones and worked to bring its customers the many economic and environmental
opportunities that natural gas offers.
The Pacific Northwest is known for its ability to foster
economic progress in ways that support a vibrant,
healthy environment. And it’s that intersection of en-
vironmental stewardship and the drive for economic
growth that provide new and exciting opportunities
for natural gas and NW Natural.
No other energy option today can match the advantages
that clean, affordable natural gas provides for homes,
businesses, vehicle transportation or the power genera-
tion sector. But to capitalize on these opportunities
NW Natural must continue to execute effectively,
maintaining our focus on providing safe, reliable and
affordable service.
2013 HIGHLIGHTS
(cid:116) Reported net income of $61 million or $2.24 per share,
compared to $59 million or $2.18 per share in 2012.
(cid:116) Posted the highest score in the nation among large
utilities in the J.D. Power and Associates’ Gas Utility
Residential Customer Satisfaction Study.
(cid:116) Invested $54 million in long-term gas reserves, bringing
our cumulative three-year investment to $161 million.
(cid:116) Grew utility revenues by adding customers and invest-
ments driven by a strong price advantage for natural gas
To that end, last year we made significant investments
and industry-leading online tools.
in our system. We completed several major system
reinforcement projects and continued our proactive
pipe replacement efforts. With the support of regula-
tors and customer advocates, we were one of the first
(cid:116) Received Public Utility Commission of Oregon (OPUC)
approval to earn on $40 million of working gas inventory
in rate base, effective Nov. 1, 2013.
utilities in the country to have replaced all cast iron in
(cid:116) Increased common stock dividends paid for the 58th
our system, and we will soon complete the removal
consecutive year, one of the longest dividend increase
of all bare steel pipe as well. Currently, we have about
records of any company on the NYSE.
10 miles of bare steel pipe left, and we expect to
eliminate it by the end of 2015.
But system safety doesn’t end with pipe replacement.
We also advanced many of our other safety initia-
4
LETTER TO SHAREHOLDERS
tives, including the completion
of our new training center in
Sherwood, Oregon. Last year,
hundreds of company field em-
ployees and several municipal
fire departments participated
in hands-on, scenario-based
safety training at our new facil-
ity. And we hosted a number
of emergency preparedness
events for families and organiza-
tions in local venues throughout
our service territory.
Ensuring the safety of our
system is job one, but providing
excellent customer service is
a close second. We are proud
to say that our commitment to
BARE STEEL AND CAST IRON REPLACEMENT
materialized in two impor-
1,250
1,000
L
E
E
T
S
E
R
A
B
F
O
S
E
L
M
I
750
500
250
0
1986
1991
1996
2001
2006
2013
BARE STEEL
CAST IRON
250
200
150
100
50
0
N
O
R
I
T
S
A
C
F
O
S
E
L
M
I
The company has only about 10 miles of bare steel main left in its system.
All cast iron pipe was removed by 2000.
tant ways.
The Portland metropolitan
area’s unemployment rate
dropped to a five-year low
of 6.6 percent, with the
labor market expanding
by 1.6 percent over 12
months. That positive mo-
mentum was also reflected
in the housing sector
numbers. By December,
home sales were up 14
percent and average home
prices rose 13 percent. And
with more movement of
existing housing stock, new
construction activity also
safety and service continues to be recognized by
rebounded. Housing permits in 2013 were up 46 percent compared to 2012.
our customers.
These gains helped drive an uptick in our customer growth rate to 1.3 percent
For the third time in six years, NW Natural ranked
in 2013.
first in the West among large utilities, and posted
the highest score in the nation in J.D. Power and
Associates’ Gas Utility Residential Customer Satis-
faction Study. We’ve worked hard to be an organi-
zation focused on continuous improvement, and
these consistently strong results are a testament to
To better position us for the housing recovery, NW Natural has developed new
tools to more aggressively compete in the residential housing market. With the
price of natural gas as much as 60 percent less expensive than oil and elec-
tricity in our high-growth areas, we plan to leverage this advantage by ensuring
gas service is convenient and easy to access.
that work and to our talented workforce.
Last year, we launched the new Customer Connection Portal that provides a
(cid:58)(cid:83)(cid:86)(cid:94)(cid:3)(cid:73)(cid:92)(cid:91)(cid:3)(cid:90)(cid:91)(cid:76)(cid:72)(cid:75)(cid:96)(cid:3)(cid:89)(cid:76)(cid:74)(cid:86)(cid:93)(cid:76)(cid:89)(cid:96)
In recent years, we’ve seen slow but consistent
progress toward economic recovery in our service
territory. In 2013, improvement in the local economy
unique online resource for potential customers. This web-based portal auto-
mates and enhances a prospective customer’s shopping experience.
Now, potential customers can go online from a computer, smartphone or
tablet to learn within a few clicks if they can get natural gas to their home.
As part of our commitment to safety, we built a new center that provides hands-on, scenario-based training for employees. The site also allows us to
partner with first responders, including local fire departments, to conduct emergency preparedness exercises.
5
LETTER TO SHAREHOLDERS
Last year we implemented the Customer Connection Portal, allowing consumers to check for gas availability and schedule a contractor, all from the
convenience of a smartphone, computer or tablet.
NW Natural will analyze these inquiries to see where demand for gas service goes
Last fall, we received OPUC approval to add $40
beyond our existing system, so we can more effectively plan for future growth.
million of working gas inventory to rate base, clos-
Using the portal, consumers can also find everything they need to connect to
gas: special offers on equipment, contractor information and a tool to compare
the cost of natural gas to oil and electricity.
In 2014, we will be expanding the portal to provide special features for our
trade allies. Through a secure, personalized account, builders and HVAC con-
tractors will be able to go online to order service, track the progress of their
orders and manage multiple projects.
A full regulatory agenda
Last year, we continued to work through a number of regulatory dockets stem-
ing that docket. The associated costs were placed
into rates on Nov. 1.
We also announced an all-parties settlement that
addressed several implementation issues related to
our new environmental cost recovery mechanism.
In reviewing the settlement, the Commission voiced
support for certain aspects of it, but also expressed
a desire to reassess how an earnings test would be
applied. As a result, we will be working through the
remainder of that proceeding this year.
ming from our recent rate case. Specifically, the OPUC opened proceedings: to
Through a separate stipulation, the OPUC did
resolve implementation issues related to our new environmental cost recovery
rule on one aspect of the environmental docket,
mechanism; to determine whether working gas inventory balances should be
allowing $19 million of capital costs related to the
added to rate base; to review the current revenue-sharing agreement for inter-
construction of a water treatment plant associated
state storage and optimization services; and to determine whether prepaid
with our cleanup efforts to be placed into rates
pension assets should be added to rate base.
on Nov. 1.
UTILITY CUSTOMERS AT YEAR-END
OREGON & WASHINGTON RESIDENTIAL RATES
(in dollars per therm)
720,000
700,000
680,000
660,000
640,000
620,000
600,000
580,000
560,000
540,000
2009
2010
2011
2012
2013
$1.60
$1.40
$1.20
$1.00
$0.80
$0.60
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
INDUSTRIAL
COMMERCIAL
RESIDENTIAL
OREGON RESIDENTIAL RATES
WASHINGTON RESIDENTIAL RATES
We added 8,932 new customers in 2013, and now serve 694,873
customers.
Today’s residential rates are lower than they were 10 years ago.
6
LETTER TO SHAREHOLDERS
Abundant, domestic natural gas is providing new economic
and environmental opportunities, benefitting homes and
businesses nationwide.
On a related matter, we made significant progress on
a lawsuit the company filed in 2010 against several
insurance carriers to recover on claims for the envi-
ronmental cleanup effort. By the end of last year, we
reached settlements or agreements-in-principle with all
but three of the insurers in the litigation. This January
In 2014, we will continue to work through the remaining regulatory proceed-
ings carried over from our 2012 rate case. We expect these issues to be
resolved this year.
New avenues for growth
Without question, abundant, domestic supplies of natural gas have created
an environment rich with possibilities.
Last year, we continued to reap the long-term advantages of low natural gas
prices through our gas reserves investment in Wyoming. Through year-end,
our cumulative investment totaled $161 million. These investments are ex-
pected to provide stable prices for a portion of our utility gas supply for
years to come.
Today, like never before, low natural gas prices make it possible to reduce
environmental emissions while decreasing our country’s dependence on
foreign oil. For example, by switching to compressed natural gas (CNG), fleet
operators can cut their fuel costs nearly in half while significantly reducing
greenhouse gas emissions.
Given these cost and environmental benefits, it’s no surprise that many com-
petitively minded Northwest businesses have been looking for a way to move
their vehicles to CNG. Unfortunately, there is little refueling infrastructure
currently available in the Pacific Northwest that would allow them to make
the switch.
we concluded the litigation effort with signed settle-
In response, NW Natural proposed a new tariff to provide high-pressure
ments from those remaining insurers.
natural gas service to business customers interested in switching their fleet
We are pleased with this outcome. Including all
settlements to date, we now have recovered
$150 million for investigation and remediation of
vehicles to CNG. The tariff was approved by the OPUC in January of this year.
We believe it provides an important first step in allowing local businesses to
save on fuel costs and transition to a cleaner, domestic energy resource.
environmental sites, while avoiding the significant
Generating power with natural gas is another opportunity to further the North-
costs associated with trials and the potential for
west’s greenhouse gas reduction goals. By 2025, the two coal plants operating
years of appeals.
in the Northwest are scheduled to be shut down. These significant moves
NW Natural is working to meet the demand for CNG refueling infrastructure. A new tariff allows us to provide high-pressure natural gas service, which will help
businesses save fuel costs and transition to a cleaner, domestic fuel.
7
LETTER TO SHAREHOLDERS
We believe storage will play an important role in serving demand growth as the nation turns increasingly to natural gas for power generation, transpor-
tation and manufacturing.
away from coal will drive the region’s electric generation mix to even more
new, proactive way for NW Natural to invest in proj-
renewables and a much greater reliance on natural gas.
ects that have quantifiable environmental benefits for
Supporting that generation shift is a possible expansion at NW Natural’s Mist
underground storage facility. The concept is to use new storage capacity at
customers – projects that otherwise would not
move forward.
Mist to provide a flexible, on-demand fuel source for a local electric utility’s
The bill took effect Jan. 1, 2014, and a rule-making
gas-fired generating plants – plants designed to integrate wind resources into
effort with the OPUC to establish project and invest-
the electric system.
Last year, we worked through many of the engineering details for this potential
expansion, which would include new storage wells, a compressor station, and
additional pipeline facilities. In 2014, we’ll be working to refine cost estimates
and determine whether the expansion will move forward.
While the Northwest storage situation continues to offer near-term potential,
storage values in many other parts of the country remained low in 2013. Despite
these conditions, we continue to work hard to find opportunities that add
value to our Gill Ranch facility in California.
ment criteria is under way. We are pleased to have
this framework in place, and we look forward to
finding those untapped opportunities where natural
gas can provide significant environmental benefits
for Oregon.
The shale gas revolution is clearly a transforma-
tional change for our country, one that offers great
economic and environmental opportunities. Now
it’s our job to make sure NW Natural is positioned
to thrive in this new environment, and to deliver
California’s renewable portfolio standard requires that 33 percent of the state’s
those opportunities to our customers and the com-
power be generated by renewables by 2020. This change in California’s gen-
munities we serve, as well as to our shareholders.
eration mix is increasing the need for flexible power resources to handle the
That remains our focus in 2014 – and beyond.
intermittency of wind and solar energy. Our Gill Ranch facility has the potential
to support this type of flexible resource.
Once again, thank you for the confidence and trust
you place in NW Natural. We look forward to con-
Overall, we continue to believe that as the nation moves increasingly to natural
tinuing to work on your behalf.
gas for power generation, transportation and industrial processes, storage will
provide long-term value. And whether it’s through storage, in vehicles or at the
burner tip, the environmental and economic advantages natural gas provides
has caught the interest of policymakers.
Last year, Oregon’s Governor and one of the state’s Public Utility Commis-
sioners led the effort to get Senate Bill 844 passed. We believe this innovative
legislation (known as the greenhouse gas emission reduction bill) provides a
Gregg S. Kantor
President and CEO
8
CORPORATE OFFICERS
Front
MARGARET D. KIRKPATRICK
Senior Vice President and
General Counsel
Back
GRANT M. YOSHIHARA
Vice President
Utility Operations
DAVID H. ANDERSON
Executive Vice President
and Chief Operating Officer
GREGG S. KANTOR
President and Chief
Executive Officer
LEA ANNE DOOLITTLE
Senior Vice President and
Chief Administrative Officer
STEPHEN P. FELTZ
Senior Vice President and
Chief Financial Officer
MARDILYN SAATHOFF
Vice President Legal,
Risk and Compliance
and Corporate
Secretary
C. ALEX MILLER
Vice President
Regulation and
Treasurer
DAVID R. WILLIAMS
Vice President
Utility Services
J. KEITH WHITE
Vice President Business
Development and
Energy Supply and
Chief Strategic Officer
BRODY J. WILSON
Controller and
Chief Accounting
Officer
BOARD OF DIRECTORS
TIMOTHY P. BOYLE
President and Chief
Executive Officer
Columbia Sportswear
Company
MARTHA L.
“STORMY” BYORUM
Director, Tecnoglass, 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
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 Trans-
mission Corporation
KENNETH THRASHER
Chairman
of the Board
Compli Corporation
9
SHAREHOLDER INFORMATION
Notice of annual meeting
The 2014 Annual Meeting will be held at 2 p.m., Thursday, May 22, at the company’s headquarters, One Pacific Square, 220 NW 2nd Ave.,
4th floor, Portland, Oregon 97209. 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 showing that you owned NW Natural Common Stock as of the
record date, April 3, 2014, and we will provide you with an admission ticket. A form of government-issued photograph identification will
be required for both you and your guest to enter the meeting.
Contact the NW Natural Board
the Corporate Secretary at NW Natural’s
Dividend reinvestment and
direct stock purchase plan
Concerns may be directed to the non-
Participants may make an initial invest-
management directors by writing to
ment in company stock and common
NW Natural Board of Directors,
shareholders of record may reinvest all or
c/o Corporate Secretary.
part of their dividends in additional shares
under the company’s plan. Cash pur-
Forward-looking statements
address: Annual Report; Form 10-K; Form
10-Q; Corporate Governance Standards;
Director Independence Standards; Code
of Ethics; and Board Committee Charters.
These publications, as well as other filings
made with the SEC, are also available on
our website at nwnatural.com. Our SEC fil-
ings are also available by request through
the SEC by mail at U.S. Securities and
Exchange Commission, Office of FOIA/PA
Operations, 100 F Street, N.E., Wash-
ington, D.C. 20549, or online at 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.
COMPARISON OF FIVE-YEAR
CUMULATIVE TOTAL RETURN
(Based on $100 invested on 12/31/2008)
$250
$200
$150
$100
$50
$0
2008
2009
2010
2011
2012
2013
S&P 500 INDEX
S&P UTILITIES INDEX
NWN
chases may also be made. Participants in
the plan bear the cost of brokerage fees
and commissions for shares purchased
on the open market to fulfill purchases
under the plan. A prospectus will be sent
upon request.
Scheduled dividend payment dates
February 14, 2014
May 15, 2014
August 15, 2014
November 14, 2014
Certifications
The Chief Executive Officer certified to
the NYSE on June 24, 2013, that, as of
that date, he was not aware of any viola-
tion by the company of NYSE’s corporate
governance listing standards, and the
company had filed with the Securities and
Exchange Commission (SEC), as exhibits
31.1 and 31.2 to its Annual Report on
Form 10-K for the year ended December 31,
2012, the certificates of the Chief Execu-
tive Officer and the Chief Financial Officer
of the company certifying the quality of
the company’s public disclosure. For
the year ended December 31, 2013, the
certificates of the Chief Executive Officer
and Chief Financial Officer are attached
as exhibits 31.1 and 31.2 to the Form
10-K included in this Annual Report.
The statements made in this Annual
Report that are not purely historical,
including statements regarding strategy,
growth, future demand for gas, com-
modity costs, fuel savings, revenues, gas
supplies and reserves, investments and
returns, business development, potential
projects and project timelines, pipeline
replacement and safety programs, system
reliability, storage performance values,
recovery and expansion, governmental
policy and legislation, regulatory cost
recovery mechanisms, regulatory prudence
reviews, regulatory proceedings and ac-
tions, economic recovery factors, market
trends and the competitive environment are
forward-looking statements within the “safe
harbor” provisions of the Private Securities
Litigation Reform Act of 1995. NW Natural’s
actual results could differ materially from
those anticipated in these forward-looking
statements as a result of risks and uncer-
tainties, including those described in the
attached report on Form 10-K.
For a more complete description of these
risks and uncertainties, please refer to
our filings with the SEC on Forms 10-K
and 10-Q.
Request for publications
The following publications may be
obtained without charge by contacting
Total shareholder return (annualized) over the five
years ending December 31, 2013, for NW Natural
was 3.2%, compared to Standard & Poor’s (S&P)
Utilities Index return of 10.2%, and the S&P 500
Index return of 17.9%.
10
LIVING OUR MISSION & 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
Page 3 - Gregg Kantor: Todd Eckelman.
Page 4 - Get Ready Safety: Corky Miller; Sherwood Training Facility: Courtesy Judd Girard.
Page 6 - CNG Refilling Station: Corky Miller.
Page 7 - Gas Pipeline Installation: Robbie McClaran.
Page 8 - Corporate Officers: Jeff Lee; Board of Directors: Robbie McClaran.
Page 11 - Robert Hess and Chu Lee: Robbie McClaran; NW Natural Headquarters: Corky Miller.
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, 2013
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 28, 2013, the registrant had 26,972,022 shares of its Common Stock outstanding, of which 26,636,200 shares
were held by non-affiliates. The aggregate market value of the 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 $1,131,505,776.
At February 21, 2014, 27,099,729 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 2014 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, 2013
TABLE OF CONTENTS
PART I
Glossary of Terms
Forward-Looking Statements
Item 1.
Business
Overview
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. Executive Compensation
Item 12. 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
8
10
10
11
11
11
11
12
19
19
19
19
20
21
22
47
49
87
87
87
88
89
89
90
90
91
92
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 an
atmospheric pressure of one and 60 degrees Fahrenheit.
One hundred thousand Btu’s equal one therm.
CALIFORNIA PUBLIC UTILITIES COMMISSION (CPUC): entity
that regulates our California gas storage business at our Gill
Ranch facility with respect to rates and terms of service,
among other matters.
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.
HEATING 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,
whether that capacity is used or not.
FEDERAL ENERGY REGULATORY COMMISSION (FERC):
entity that regulates interstate storage services offered by
our Mist gas storage facility as part of our gas storage
segment.
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.
GENERAL RATE CASE: a periodic filing with state or federal
regulators to establish billing rates for all classes of utility
customers.
INTERRUPTIBLE SERVICE: natural gas service offered to
customers (usually large commercial or industrial users)
under contracts or rate schedules that allow for interruptions
when necessary to meet the needs of firm service
customers.
LIQUEFIED NATURAL GAS (LNG): the cryogenic liquid form of
natural gas. To reach a liquid form at atmospheric pressure,
natural gas must be cooled to approximately negative 260
degrees Fahrenheit.
PUBLIC UTILITY COMMISSION OF OREGON (OPUC): entity
that regulates our Oregon utility business with respect to
rates and terms of service, among other matters. The
OPUC also regulates our Mist gas storage facility's
intrastate storage services.
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 use in determining
revenue requirements.
SALES SERVICE: service provided whereby a customer
purchases both natural gas commodity supply and
transportation from the utility.
SITE REMEDIATION AND RECOVERY MECHANISM (SRRM): an
Oregon rate mechanism for recovering prudently incurred
environmental site remediation costs through customer
billings, subject to an earnings test.
SYSTEM INTEGRITY PROGRAM (SIP): an Oregon rate
mechanism that provides cost recovery of pipeline and
system integrity programs, which are required under various
safety standards prescribed by both state and federal
regulators.
THERM: the basic unit of natural gas measurement, equal to
one hundred thousand 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.
WASHINGTON UTILITIES AND TRANSPORTATION
COMMISSION (WUTC): entity that regulates our Washington
utility business with respect to rates and terms of service,
among other matters.
WEATHER NORMALIZATION: an Oregon 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. The mechanism is applied to bills from December
through May of each heating season.
1
FORWARD-LOOKING STATEMENTS
This report contains forward-looking statements within the
meaning of the U.S. Private Securities Litigation Reform Act
of 1995. Forward-looking statements can be identified by
words such as anticipates, intends, plans, seeks, believes,
estimates, expects, and similar references to future periods.
Examples of forward-looking statements include, but are not
limited to statements regarding the following:
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
plans;
objectives;
goals;
strategies;
assumptions and estimates;
future events or performance;
trends;
timing and 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;
levels and pricing of gas storage contracts;
outcomes and effects of potential claims, 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;
effects of regulatory mechanisms; and
environmental, regulatory, litigation and insurance costs
and recoveries, and timing thereof.
•
•
•
•
•
Forward-looking statements are based on our current
expectations and assumptions regarding our business, the
economy and other future conditions. Because forward-
looking statements relate to the future, they are subject to
inherent uncertainties, risks and changes in circumstances
that are difficult to predict. Our actual results may differ
materially from those contemplated by the forward-looking
statements. We therefore caution you against relying on any
of these forward-looking statements. They are neither
statements of historical fact nor guarantees or assurances
of future performance. Important factors that could cause
actual results to differ materially from those in the forward-
looking statements are discussed at Item 1A., "Risk
Factors" of Part I and Item 7. and Item 7A., "Management’s
Discussion and Analysis of Financial Condition and Results
of Operations" and "Quantitative and Qualitative Disclosures
About Market Risk", respectively, of Part II of this report.
Any forward-looking statement made by us in this report
speaks only as of the date on which it is made. Factors or
events that could cause our actual results to differ may
emerge from time to time, and it is not possible for us to
predict all of them. We undertake no obligation to publicly
update any forward-looking statement, whether as a result
of new information, future developments or otherwise,
except as may be required by law.
2
NORTHWEST NATURAL GAS
COMPANY
PART I
ITEM 1. BUSINESS
OVERVIEW
Northwest Natural Gas Company (NW Natural or the
Company) was incorporated under the laws of Oregon in
1910. However, 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 business through NW Natural and its
subsidiaries. References in this discussion to "Notes" are
the Notes to the Consolidated Financial Statements in Item
8 of this report.
We have two core businesses: our regulated local gas
distribution business, referred to as the utility segment,
which serves residential, commercial, and industrial
customers in Oregon and southwest Washington; and our
gas storage businesses, referred to as the gas storage
segment, which provides storage services for utilities, gas
marketers, electric generators, and large industrial users
from storage facilities located in Oregon and California. In
addition, we have investments and other non-utility activities
that we aggregate and report as other.
The utility business is our largest segment, while our gas
storage businesses account for a majority of our remaining
net income. The following table reflects the percentage
allocation between segments and other as of December 31,
2013:
Non-Utility(1)
Utility
Gas
Storage(2)
Other
Total
Assets
89.0%
10.4%
0.6%
100.0%
9.2%
0.1%
90.7%
100.0%
Net Income
(1) We refer to our gas storage segment and other as non-utility as
they are not included in our regulated gas distribution business;
however, certain aspects of the gas storage segment and other
may be regulated by the OPUC, WUTC, CPUC, or FERC.
(2) Gas Storage segment includes asset management services for
both the utility and non-utility portion of our Mist gas storage facility.
LOCAL GAS DISTRIBUTION "UTILITY"
The utility is principally engaged in the regulated distribution
of natural gas in Oregon and southwest Washington to
approximately 695,000 customers with around 90% of our
customers located in Oregon and 10% located in
Washington. In total, we provide natural gas service to over
100 cities in 18 counties with an estimated population of 3.4
million in our service territory.
The OPUC and WUTC have allocated us an exclusive
service territory, which includes a major portion of western
Oregon, including the Portland metropolitan area, most of
the Willamette Valley, the Coastal area from Astoria to Coos
Bay, and portions of Washington along the Columbia River.
3
Portland serves as one of the largest international ports on
the West Coast and is a key distribution center due to its
comprehensive transportation system that comprises ocean
and river shipping, transcontinental railways and highways,
and an international airport. The area is a major retail and
manufacturing center and home to high-technology
industries.
Customers
We serve residential, commercial and industrial customers
with no individual customer or industry accounting for over
10% of our utility revenues. On an annual basis, residential
and commercial customers typically account for around 60%
of our utility’s total volumes delivered and 90% of our utility’s
margin. Industrial customers largely account for the
remaining volumes and utility margin. A small amount of
utility margin is also derived from other items. The following
table presents summary customer information as of
December 31, 2013:
Residential
Commercial
Industrial
Other(1)
Number of
Customers
% of
Volumes
% of Utility
Margin
628,634
65,321
918
N/A
36%
22%
42%
N/A
64%
27%
8%
1%
Total
694,873
(1) Other is derived from miscellaneous services, gains or losses
from our incentive gas cost sharing mechanism and other service
fees.
100%
100%
Generally residential and commercial customers purchase
both their natural gas commodity (gas sales) and natural
gas delivery services (transportation services) from the
utility. Industrial customers also purchase transportation
services from the utility, but may buy the gas commodity
either from the utility or directly from a third-party gas
marketer or supplier. Our gas commodity cost is primarily a
pass-through cost to customers; therefore, our profit
margins are not materially affected by an industrial
customer's decision to purchase gas from us or from third
parties. Industrial and large commercial customers may also
select between firm and interruptible service levels, with firm
services generally providing higher profit margins compared
to interruptible services.
To help manage gas supplies, our industrial tariffs are
designed to provide some certainty regarding industrial
customers' volumes by requiring an annual election of
services, special charges for changes between elections,
and in some cases, meeting a minimum or maximum
volume requirement before changing options.
Customer growth rates for natural gas utilities in the Pacific
Northwest are generally among the highest in the nation
due to lower market saturation as natural gas became
widely available as a residential heating source after other
fuel options. We estimate that natural gas is in less than
60% of residential single-family dwellings in our service
territory. Therefore, growth in the region comes from both
new housing construction and existing homes converting to
natural gas. Prior to the most recent recession, our
customer growth rate averaged around 3% or higher. From
2009 to 2012, growth dipped below 1%, but in 2013, the
12-month growth rate increased to 1.3%. With natural gas'
continued price advantage, operating convenience, and
environmental benefits, we believe there is potential for
continued growth in all customer categories as the economy
recovers. See Note 4 for information on the utility's assets
and results of operations.
Competitive Conditions
In our service areas, we have no direct competition from
other natural gas distributors, but we compete with other
forms of energy supply in each customer class. This
competition among energy suppliers is based on price,
efficiency, reliability, performance, market conditions,
technology, federal and state energy policy, and
environmental impacts.
For residential and small to mid-size commercial customers,
we compete primarily with electricity, fuel oil, propane and
renewable energy providers.
In the industrial and large commercial markets, we compete
with all forms of energy, including competition from
wholesale natural gas marketers. In addition, large industrial
customers could bypass our local gas distribution system by
installing their own direct pipeline connection to the
interstate pipeline system. We have designed custom
transportation service agreements with several of our
largest industrial customers to provide transportation service
rates that are competitive with the customer’s costs of
installing their own pipeline. These agreements generally
prohibit bypass. Due to the cost pressures that confront a
number of our largest customers that compete 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 could experience deterioration of
margin if customers bypass or switch over to custom
contracts that provide lower profit margins.
Seasonality of Business
Our utility business is seasonal in nature due to higher gas
usage by residential and commercial customers during the
cold winter heating months.
Regulation and Rates
The utility is subject to regulation by the OPUC, WUTC, and
FERC. These regulatory agencies authorize rates and allow
recovery mechanisms to provide our utility the opportunity to
recover prudently incurred capital and operating costs from
customers, while also earning a reasonable return on
investment for investors. In addition, the OPUC and WUTC
also regulate the system of accounts and issuance of
securities by our utility.
4
We file general rate cases and rate tariff requests
periodically with the commissions to establish approved
rates, an authorized ROE, an overall rate of return on rate
base (ROR), an authorized utility capital structure, and other
revenue/cost deferral and recovery mechanisms.
In addition, under our Mist interstate storage certificate with
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. In December 2013, we filed a
rate petition and received approval in 2014 for new
maximum cost-based rates effective January 1, 2014.
The utility's most recent general rate case in Oregon was
effective November 1, 2012, and the latest Washington rate
case was effective January 1, 2009. 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%
Key Regulatory Mechanisms:
PGA
Incentive Sharing
Weather Normalization Tariff
Decoupling
SIP
Pension Balancing
Environmental Cost Deferral
SRRM
X
X
X
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 that allow us to defer certain costs for future
recovery through the PGA or future general rate cases, such as our
environmental cost deferral order.
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 primarily 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.
For a complete discussion of regulatory matters, open
dockets, current regulatory activities, and additional details
on each rate mechanism, see Part II, Item 7, "Results of
Operations—Regulatory Matters" and "Gas Storage" below.
Gas Supply
The utility strives to secure sufficient, reliable supplies of
natural gas to meet the needs of customers at the lowest
reasonable cost through a comprehensive strategy that is
focused on the following items:
• Diverse Supply - providing diversity of supply sources;
• Diverse Contracts - maintaining a variety of contract
durations and types; and
• Cost Management - employing gas cost management
strategies.
Diversity of Supply Sources
We purchase our gas supplies primarily from the Alberta
and British Columbia areas of Canada and multiple receipt
points in the U.S. Rocky Mountains to protect against
regional supply disruptions and to optimize price
differentials. Currently, about 63% 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. We continue to evaluate the long-term
supply mix based on projections of gas production and
pricing in the U.S. Rocky Mountain region 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 region will continue to track with broader U.S.
market pricing. 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 pipelines to increase transportation capacity
out of the U.S. Rocky Mountain region.
We supplement our firm gas supply purchases with gas
withdrawals from gas storage facilities, including
underground reservoirs, and LNG storage facilities. These
storage facilities are generally injected with natural gas
during off-peak months during the spring and summer and
are withdrawn for use during peak demand months in the
winter.
The following table presents the storage facilities available
for our utility supply:
Maximum
Daily
Deliverability
(therms in
millions)
Capacity
(Bcf)
Gas Storage Facilities:
Owned Facility:
Mist, Oregon(1)
Contracted Facilities:
Jackson Prairie, Washington(2)
Alberta, Canada(3)
LNG Facilities:
Owned Facilities:
Newport, Oregon
Portland, Oregon
Contracted Facility:
Plymouth, Washington(4)
Total
2.7
0.5
0.5
0.6
1.2
0.6
6.1
10.0
1.1
2.8
0.9
0.6
0.5
15.9
t1) The Mist gas storage facility has a total maximum daily
deliverability of 5.2 million therms and a total working gas capacity
of about 16 Bcf, of which 2.7 million therms of daily deliverability
and 10 Bcf of storage capacity are reserved for core utility
customers.
(2) The storage facility is located near Chehalis, Washington and is
contracted from Northwest Pipeline, a subsidiary of The Williams
Companies.
(3) This resource does not add to our total peak day capacity, but
does help to manage price risks as it displaces equivalent volumes
of spot purchases.
(4) On certain days in December 2013, pipeline transportation
service from the Plymouth facility was curtailed. As a result, we no
longer assume that the resource will contribute to total peak day
capacity beginning with the 2014-2015 heating season. We are
currently evaluating this resource and alternative options, but will
continue to utilize the facility to manage price risks in the coming
year.
The Mist facility is used for both utility and non-utility
purposes. Under our regulatory agreement with the OPUC,
non-utility gas storage at Mist can be developed in advance
of core utility customer needs, but is subject to recall by the
utility when needed to serve utility customers as their
demand increases.
In addition, we have the ability to recall pipeline capacity
and supply resources from certain customers if needed.
Diverse Contract Durations and Types
We have a diverse portfolio of short-, medium-, and long-
term firm gas supply contracts and a variety of contract
types including firm and interruptible supplies plus
supplemental supplies from gas storage facilities.
Our portfolio of firm gas supply contracts typically includes
the following gas purchase contracts: year-round and
winter-only baseload supplies; seasonal supply with an
option to call on additional daily supplies during the winter
heating season; and daily or monthly spot purchases.
5
During 2013, we purchased a total of 762 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
28%
24
48
100%
We renew or replace gas supply contracts as they expire.
Aside from the gas supplies provided by an independent
energy marketing company as part of asset management
services, our largest individual supplier provided just over
10% of our gas supply requirements in 2013.
Gas Cost Management Strategy
The cost of gas sold to utility customers primarily consists of
the following items, which are included in annual PGA rates:
purchase price paid to suppliers; charges paid to pipeline
companies to store and transport gas to our distribution
system; our gas reserves contract; and gains or losses
related to gas commodity derivative contracts.
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
(1) convert floating index prices in physical gas supply
contracts to fixed prices (referred to as commodity price
swaps) or (2) 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) See Part II, Item 7A, "Quantitative
and Qualitative Disclosures About Market Risk—Credit
Risk—Credit Exposure to Financial Derivative
Counterparties";
buying physical gas supplies at a set price and injecting
it into storage for price stability and to minimize pipeline
capacity demand costs;
investing in gas reserves for longer term price stability
with Encana Oil & Gas (USA) Inc. (Encana). See Note
11; and
using an asset management service provider to
produce incremental revenues that are used to reduce
our utility’s net cost of gas.
•
•
•
We contract with an independent energy marketing
company to capture opportunities regarding our unused
storage and pipeline 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 customer's cost of gas and an opportunity to generate
incremental revenues for NW Natural's shareholders from a
regulatory incentive-sharing mechanism, which are included
in our gas storage segment.
Transportation of Gas Supplies
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 basins; and (2) the east, which brings
supplies from Alberta as well as the U.S. Rocky Mountain
supply basins.
In 2003, a federal order requiring Northwest Pipeline to
replace its 26-inch mainline from the Canadian border to our
service territory underscored the 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 into our service territory. 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, "2014
Outlook".
We incur monthly demand charges related to our firm
pipeline transportation contracts. Our largest pipeline
agreements are with Northwest Pipeline for firm
transportation capacity, which provides access to supplies in
British Columbia and the U.S. Rocky Mountains by
connecting us with the Northwest Pipeline and GTN
systems. These contracts are multi-year contracts with
expirations ranging from 2014 to 2044. We actively work
with Northwest Pipeline and others to renew contracts in
advance of expiration and ensure gas transportation
capacity is sufficient to meet our needs.
Rates for interstate pipeline transportation services are
established by FERC within the U.S. and by Canadian
authorities for services on Canadian pipelines.
Gas Distribution
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; and
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 to
minimize risks associated with regulatory prudence
reviews and cost recovery.
These goals are discussed more fully in the following
sections.
6
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 that integrates the
Company’s programs for bare steel replacement,
transmission pipeline integrity management, and distribution
pipeline integrity management into a single program. See
Part II, Item 7, "Results of Operations—Regulatory Matters
—System Integrity Program".
Natural gas distribution businesses are likely to be subject
to even greater federal and state regulation in the future due
to recent pipeline incidents involving other companies. Most
recently, additional regulations from the U.S. Department of
Transportation’s Pipeline and Hazardous Materials Safety
Administration (PHMSA) were drafted in 2013 with final
regulations expected in 2015 and an effective date in
2016. We will continue to work diligently with industry
associations as well as federal and state regulators to
ensure the safety of our system and 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 system ultimately
rests on whether we provide reliable service 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 25 years in our service territory.
Our projected maximum design day firm utility customer
sendout totals approximately 9.3 million therms. Of this
total, we are currently capable of meeting over 50% 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 February 6, 2014, we experienced our current record
customer sendout of 9.0 million therms, which included 7.4
million firm therms. This record day was approximately 9
degrees Fahrenheit warmer than the design day
temperature.
We believe that our gas 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.
The following table shows the sources of supply that are
projected to be used to satisfy the design day sendout for
the 2013-2014 winter heating season:
Therms in millions
Sources of utility supply:
Firm supply purchases
Mist underground storage (utility only)
Company-owned LNG storage
Off-system firm storage contract
Other off-system storage contract(1)
Recall agreements
Total
Therms
Percent
3.3
2.7
1.8
0.5
0.6
0.4
9.3
37%
29
19
5
6
4
100%
(1) On certain days in December 2013, pipeline transportation
service from the Plymouth storage facility was curtailed. We were
able to use this service in February 2014 primarily through other
transportation agreements. We are currently evaluating this
resource and alternative options for the 2014-2015 heating season.
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 resource requirements, 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.
In general, the IRP is filed biannually with both the OPUC
and the WUTC. An 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 plan to file our 2014 IRP in both Oregon and
Washington in May 2014.
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.
7
Cost Recovery
Mechanisms for gas cost recovery are designed to be fair
and reasonable, with an appropriate balance between the
interests of 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 resetting
customer rates annually through the PGA and aligning
customer and shareholder interests through the use of
sharing, weather normalization, and conservation
mechanisms in Oregon. See Part II, Item 7, "Results of
Operations—Regulatory Matters—Rate Mechanisms" and
"Results of Operations—Business Segments—Local Gas
Distribution Utility Operations—Cost of Gas."
GAS STORAGE
The gas storage segment includes the following:
•
the non-utility portion of the Mist gas storage facility
near Mist, Oregon;
our 75% share of the Gill Ranch gas storage facility
near Fresno, California; and
asset management services provided by an
independent energy marketing company.
•
•
In general, the supply of natural gas remains relatively
stable over the course of a year, while the demand for
natural gas typically fluctuates seasonally. Storage facilities
allow customers to purchase and inject natural gas supplies
during periods of low demand and withdraw these supplies
for use or resale during periods of higher demand. These
facilities allow us to capitalize on the imbalance of supply
and demand and price volatility for natural gas.
In recent years, as a result of the abundant supply of natural
gas in North America, we have seen lower, more stable
natural gas prices, which has created a challenging gas
storage environment. In late 2013 and early 2014, we saw
gas price volatility due to the colder than normal winter
throughout North America. In the short-term, this gas price
volatility increased the demand for, and value of, holding
gas storage. However, future gas storage demand and
pricing have been negatively affected by projections of
spring and summer natural gas prices that are equal to
projected gas prices for the winter of 2014-15, making the
purchase of spring and summer gas for injection into
storage less desirable. As a result of these current trends,
we anticipate contracting for the upcoming storage year at
lower market prices than in previous periods, especially at
our California facility, where some multi-year contracts are
expiring. In the longer term, increased demand for natural
gas and/or decreased drilling activity could change the
current supply/demand imbalance and result in higher gas
prices or increased market volatility, which could position
this segment for growth.
See Note 4 for more information on gas storage assets and
results of operations and "Financial Condition—Liquidity
and Capital Resources".
Gas Storage Facilities
The following table provides information concerning the
Company’s non-utility gas storage facilities:
Maximum
Storage
Capacity
(Bcf)
Deliverability
(Bcf/day)(3)
Injection
(Bcf/day)(3)
Mist Storage(1)
6
0.2
0.1
0.5
Gill Ranch Storage(2)
0.2
15
(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
deliverability rates.
Mist Storage Facility
The Mist storage facility began operations in 1989 and
currently consists of seven depleted natural gas reservoirs,
22 injection and withdrawal wells, a compressor station,
dehydration and control equipment, gathering lines and
other related facilities.
SERVICES. Mist provides multi-cycle gas storage services to
customers in the interstate and intrastate markets from its
facility located in Columbia County, Oregon, near the town
of Mist. The Mist field was converted to storage operations
for our utility customers in 1989. 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 intrastate firm storage services in Oregon
under an OPUC-approved rate schedule as an optional
service to eligible non-residential utility customers.
CUSTOMERS. For 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.
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 Washington 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.
8
SEASONALITY. Mist gas storage revenues generally 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, which are primarily in the
form of fixed monthly reservation charges and are not
affected by customer usage. However, there is seasonal
variation with Mist storage capacity related to utility
customers' lower demand during the spring and summer
months. This surplus storage capacity and related
transportation capacity can be optimized under regulatory
sharing agreements with the OPUC and WUTC. See "Asset
Management" below.
REGULATION. Our Mist facility is subject to regulation by the
OPUC and WUTC. In addition, FERC has approved
maximum cost-based rates under our Mist interstate storage
certificate. We are required to file either a petition for rate
approval or a cost and revenue study with FERC 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".
EXPANSION OPPORTUNITIES. The Pacific Northwest storage
markets have been impacted by lower gas prices and lack
of price volatility, although less than other areas of the
country. The need for new, flexible gas-fired generation has
been identified in the Pacific Northwest region to integrate
intermittent wind resources into the power system, thereby
increasing the associated need for gas storage. To address
this need, we are in the early planning stages of a potential
expansion of our Mist storage facility. If completed, this
expansion would be anchored by an agreement to provide
gas storage services to Portland General Electric (PGE) to
support their gas-fired generation facilities at Port
Westward, Oregon. The Mist expansion project is subject to
PGE's approval of projected costs and various other
approvals, regulatory requirements, and other conditions.
Gill Ranch 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 and currently consists of three depleted natural gas
reservoirs, 12 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.
California has been impacted by challenging market
conditions for gas storage, with contract prices in the region
at historic lows and a greater number of competitors in the
area compared to the Pacific Northwest region. As a result,
we anticipate contracting at lower market prices than we
have in the previous years. We are committed to using a
variety of contracting tools to maximize the value from the
Gill Ranch facility. In the longer term, the recovery of the
California economy and potentially an increased demand for
9
flexible generation could increase demand for natural gas
storage and increase price volatility.
SERVICES. Gill Ranch provides intrastate, multi-cycle
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. The Gill Ranch facility is not currently authorized
to provide interstate gas storage services.
CUSTOMERS. Customer contracts for firm storage capacity
at Gill Ranch are as long as 28 years in duration; however,
the majority of the contracted capacity is shorter term in
nature due to current market conditions. In the near-term,
we expect Gill Ranch to contract for terms mostly ranging
from one to five years. For the 2013-14 gas storage year,
Gill Ranch has several storage customers, with the largest
single contract accounting for approximately 13% of our
storage capacity. We are currently in the process of
contracting available capacity for the upcoming 2014-15 gas
storage year and expect shorter contract lengths and lower
prices reflecting current market trends.
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. Therefore, we
expect less sensitivity to any single customer or group of
customers at Gill Ranch. Current Gill Ranch customers
provide energy related services, including natural gas
production, marketing, and electric generation.
COMPETITIVE CONDITIONS. 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 could also be expansions and proposed new
construction of storage capacity in northern California that
may create increased competition.
SEASONALITY. Although we expect much of the storage
revenue at Gill Ranch to be in the form of fixed monthly
demand charges, cash flows can fluctuate due to timing of
asset management revenues. In addition, a significant
portion of operating costs at Gill Ranch are subject to
seasonality based on periods when storage customers elect
to inject or withdraw.
REGULATION. Gill Ranch has a tariff on file with the CPUC
authorizing it to charge market-based rates for the storage
services offered. See Part II, Item 7, "Results of
Operations–Regulatory Matters".
EXPANSION OPPORTUNITIES. 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
additional 25 Bcf of storage capacity, bringing the total
storage capacity to approximately 45 Bcf, of which our
current rights would give us up to an additional 7.5 Bcf or
ownership of a total of approximately 22.5 Bcf.
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 seek recovery of environmental costs through insurance
and customer rates, and we believe recovery of these costs
is probable. We currently have an open proceeding with the
OPUC to resolve implementation issues for the SRRM,
which allows for regulatory environmental cost recovery. 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 insurance recoveries for environmental costs are
insufficient and future rate recovery of such costs are not
probable, the costs will be charged to expense in the period
such determination is made. See Note 17 and Item 3 "Legal
Proceedings" for information regarding the recent
settlement with remaining defendant insurance companies.
See also "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
on an annual basis. The EPA also issued additional
greenhouse gas reporting regulations requiring the annual
reporting of fugitive emissions from our operations.
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 segment, except for amounts
allocated to our utility pursuant to regulatory sharing
agreements involving the use of utility assets. Utility 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 immaterial non-utility investments and other
business activities which are aggregated and reported as
other. Other primarily consists of:
•
an equity method investment in a joint venture to build
and operate a gas transmission pipeline in Oregon.
Palomar Gas Holdings, LLC (PGH) is owned 50% by
NWN Energy, a wholly-owned subsidiary of NW
Natural, and 50% by TransCanada American
Investments Ltd., an indirect wholly-owned subsidiary
of TransCanada Corporation. See Part II, Item 7, "2014
Outlook";
a minority interest in Kelso-Beaver Pipeline 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 other. See Note 4 for
summary information for these assets and results of
operations.
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 costs are difficult to determine with precision
because of the various factors that can affect their ultimate
disposition.
10
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 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 gases associated with our
operations, which could result in an increase in the prices
we charge our customers or a decline in the demand for
natural gas. On the other hand, because natural gas is a
fossil fuel with relatively low carbon content, it is also
possible that future carbon constraints could create
additional demand for natural gas for electric 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 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, 2013, the utility workforce consisted of 612
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. In 2013, each party served notice of intent to
negotiate the terms of an agreement prior to the May 31,
2014 expiration date. We are currently engaged in
negotiations to meet this schedule.
At December 31, 2013, our subsidiaries had a combined
workforce of 19 non-union employees. Our subsidiaries
receive certain services from centralized operations at the
utility, and 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, gate
stations, storage facilities and related assets, to expand the
reach or capacity of those assets, or improve the efficiency
of our operations. 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, and
distribution system improvements. In 2014, utility capital
expenditures are estimated to be between $115 and $135
million, and non-utility capital investments are estimated to
be less than $10 million. Additional non-utility spend for gas
storage and other investments during and after 2014 will
depend largely on future decisions about potential
expansion opportunities in gas storage and pipeline
projects. For the five-year period ending in 2018, capital
expenditures for the utility are estimated to be between
$600 and $700 million, while the amount for gas storage
and other investments after 2014 will depend largely on the
factors discussed previously.
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 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.
2402.
11
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 affects 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 ROE, 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 businesses 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 for which the deferral 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 an authorized rate
of return for our utility through the ratemaking process, 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
12
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 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.
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 initiated litigation 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 amounts we
recover from insurance are inadequate or we are unable to
recover these deferred costs in utility customer rates, 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
13
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 stages for a regional cross-Cascades pipeline
in Oregon, and a potential expansion of our gas storage
facility at Mist. We may also engage in other business
development projects such as investment in additional long-
term gas reserves or CNG refueling stations. 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
development projects at acceptable interest rates or within a
scheduled time frame 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, divest important assets, 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
14
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, which
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.
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
15
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. We expect there to be increased costs
associated with compliance these 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 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 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
16
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.
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.
CUSTOMER GROWTH RISK. Our utility margin, earnings and
cash flow may be negatively affected if we are unable to
sustain customer growth rates in our local gas distribution
segment.
Our utility margins and earnings growth have largely
depended upon the sustained growth of our residential and
commercial customer base due, in part, to the new
construction housing market, conversions of customers to
natural gas from other fuel sources and growing commercial
use of natural gas. 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 and commercial markets, our gas
distribution business competes primarily with suppliers of
electricity, fuel oil, propane, and renewable energy
providers. In the industrial market, we compete with
suppliers of all forms of energy. 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,
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.
SINGLE TRANSPORTATION PIPELINE RISK. We rely on a
single pipeline company for the transportation of gas to our
service territory, a disruption of which could adversely
impact our ability to meet our customers’ gas requirements.
Our distribution system is directly connected to a single
interstate pipeline, 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
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.
17
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
strengthen our systems or obtain specific insurance
coverage against potential losses.
Risks Related Primarily to Our Gas Storage
Businesses
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
historic lows. 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.
Prices below the costs to operate the storage facility could
result in a decision to shut in all or a portion of the facility. A
sustained decline in these prices or a shut-in of all or a
18
portion of the facility 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 businesses
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.
ITEM 1B. UNRESOLVED STAFF COMMENTS
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 pipeline system includes service pipelines,
meters and regulators, and gas regulating and metering
stations. Pipeline mains are located in municipal streets or
alleys pursuant to franchise or occupation ordinances, in
county roads or state highways pursuant to agreements or
permits granted pursuant to statute, or on lands of others
pursuant to easements obtained from the owners of such
lands. We also hold 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
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 remaining bare steel
mains and services in the system by the end of 2015.
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
associated 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 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 alleged that
the defendant insurance companies issued third party
liability insurance policies to NW Natural and that the
defendants had 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 sought damages in excess of $50 million in
losses it had incurred through the date of the complaint, as
well as declaratory relief for additional damages it expected
to incur in the future. Settlements with certain of the
defendant insurance companies resulted in payments
received by NW Natural through December 31, 2013 of
approximately $48 million.
In January and February 2014, the remaining defendant
insurance companies agreed to settle all of NW Natural’s
claims for insurance recovery for past and future
environmental remediation expenses. In 2014 the Company
expects to receive additional payments aggregating
approximately $102 million under these settlement
agreements signed in 2013 and 2014. Such payments are
to be made in the first and second quarters of 2014. As a
result of such settlements, the Company anticipates
dismissal of the litigation in the second quarter of 2014. See
Note 17.
ITEM 4. MINE SAFETY DISCLOSURES
Not applicable.
19
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 closing trades for our common stock during the past two years were as follows:
Quarter Ended
March 31
June 30
September 30
December 31
2013
2012
High
Low
High
Low
$
46.55
$
43.40
$
49.49
$
45.89
45.15
44.35
41.17
39.96
40.75
48.56
50.16
50.80
44.40
43.90
46.04
41.01
The closing quotations for our common stock on December 31, 2013 and 2012 were $42.82 and $44.20, respectively.
As of February 21, 2014, there were 6,178 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
2013
2012
$
$
0.455
$
0.455
0.455
0.460
1.825
$
0.445
0.445
0.445
0.455
1.790
The declaration and amount of future dividends depend upon our earnings, cash flows, financial condition and other factors. 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.
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, 2013:
Period
Balance forward
10/01/13-10/31/13
11/01/13-11/30/13
12/01/13-12/31/13
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
— $
3,406
231
3,637
$
—
42.31
43.16
42.37
—
—
—
—
—
—
2,124,528
$
16,732,648
(1) During the quarter ended December 31, 2013, 3,637 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, 2013, no shares of our common stock were accepted
as payment for stock option exercises pursuant to our 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, 2014 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, 2013, 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.
20
ITEM 6. SELECTED FINANCIAL DATA
In thousands, except share data
Operating revenues(1)
Net income(1)
2013
2012
2011
2010
2009
$
758,518
$
730,607
$
828,055
$
792,115
$
988,055
60,538
58,779
63,044
72,013
74,632
For the year ended December 31,
Earnings per share of common stock:
Basic(1)
Diluted(1)
Dividends paid per share of common stock
$
2.24
$
2.19
$
2.36
$
2.71
$
2.24
1.83
2.18
1.79
2.36
1.75
2.70
1.68
2.82
2.81
1.60
Total assets, end of period(1)
Total equity(1)
Long-term debt
$
2,970,911
$
2,813,120
$
2,742,718
$
2,614,172
$
2,397,890
751,872
681,700
729,627
691,700
712,158
641,700
691,625
591,700
659,283
601,700
(1) Prior period balances have been adjusted for a prior period error identified during the first quarter of 2013. See Note 16 for additional detail.
21
EXECUTIVE SUMMARY
During 2013 we continued to advance our long-term
strategic directives. Highlights for the year include:
•
increased customer count with close to 9,000 net
customer additions for an annual customer growth rate
of 1.3%;
developed new online tools for customers to compare
energy cost and service options;
ranked number one in J.D. Power customer service
survey among large gas utilities in the West;
pursued gas storage development opportunities at our
Mist gas storage facility;
completed construction of a new operations service
center, which also serves as a back-up business
continuity center, and industry leading training facility;
completed construction of a new water treatment
station at our Gasco site; and
received regulatory approval for an increased spending
limit for our annual system integrity cap-ex tracker,
which supports our safety investments.
We manage our business and strategic initiatives with a
long-term view on providing natural gas service safely and
conveniently to our customers, working with regulators on
key policy initiatives, and remaining focused on growing our
business. See "2014 Outlook" below for more information.
Key financial highlights include:
In millions, except per
share data
Consolidated net income
Consolidated EPS
Utility margin
2013
2012
2011
$
60.5
$
58.8
$
2.24
353.9
2.18
344.5
63.0
2.36
343.0
Results for 2013:
•
net income and EPS increased primarily due to higher
utility margin in 2013 and a one-time tax charge taken
in 2012;
gas storage net income increased primarily due to
higher asset management revenues and lower
operating costs; and
utility margin increased primarily due to customer
growth and higher rate-base return on our gas reserve
and other investments.
See "Consolidated Earnings and Dividends" below for
additional detail.
•
•
•
•
•
•
•
•
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 results for the years ended December 31,
2013, 2012, and 2011. 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),
• NNG Financial Corporation (NNG Financial),
• Northwest Energy Corporation (Energy Corp), and
• NW Natural Gas Reserves, LLC (NWN Gas Reserves).
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
segment and other as non-utility. Our utility segment
includes our NW Natural local gas distribution
business, NWN Gas Reserves, which is a wholly-owned
subsidiary of Energy Corp, and the utility portion of our
Mist underground storage facility in Oregon (Mist). 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 Mist, and asset management services.
Other includes NWN Energy's 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 equity investment in Kelso-
Beaver Pipeline (KB Pipeline). For a further discussion of
our business segments and other, 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 (EPS) 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.
22
2014 OUTLOOK
We are focused on the long-term strategic goals for our business: delivering safe and reliable gas to our customers and growing
our gas distribution and gas storage businesses. We believe our 2014 outlook leverages our resources and our history of
innovative solutions to continue meeting the needs of customers, regulators, and shareholders. We consider the following
components critical in achieving these long term goals:
Deliver Gas
Ensure Safety and Reliability
Advance Regulatory Dockets and Policy
Collaborate on Regulatory Energy Policies
Grow Our Businesses
Grow Customer Base
Pursue Key Initiatives
Develop New Services
SAFETY AND RELIABILITY. Delivering natural gas safely and
reliably to our customers and providing employees with a
safe work environment are our top priorities. During 2014,
we will continue ensuring our pipeline system and facilities
are well maintained with ongoing facility improvements and
additional investments in our system integrity program. We
plan to continue removing the bare steel pipe in our system
with complete removal targeted by the end of 2015. We are
preparing for new regulations from the U.S. Department of
Transportation’s Pipeline and Hazardous Materials Safety
Administration (PHMSA) that are expected to be issued in
2015 with a projected effective date of 2016.
Reliability of our system and delivering to our customers on
design days is a key priority. In 2014, we plan to file our
integrated resource plan with the OPUC and WUTC. This
plan will help to define the required infrastructure
improvements and expansions necessary to provide safe
and reliable gas service to our customers.
REGULATION. Proper regulatory policies and support from
our regulators helps ensure the utility can continue to
effectively deliver gas to customers and earn a reasonable
return for shareholders. During 2014, we plan to resolve
open dockets from our 2012 Oregon general rate case,
which include: a review of the interstate storage sharing
arrangement; the implementation of our new SRRM; and
the development of appropriate rate treatment for prepaid
pension assets in rate base. In addition to these dockets,
we plan to work closely with regulators to create an
incentive mechanism for gas utilities to reduce greenhouse
gas emissions.
ENERGY POLICIES. The Company is strengthened by
innovatively addressing the needs of our customers,
employees, and the communities we serve in a challenging
economic and regulatory environment. In 2014, we will
continue to work with state legislators to help build a strong
energy plan for Oregon. In addition, we remain committed to
working with environmental agencies to make significant
progress towards remediation of our legacy environmental
sites.
GROW CUSTOMER BASE. In the utility, we continue to
leverage our resources to provide natural gas services to
our residential, commercial, and industrial customers. We
are beginning to see signs of improvement in the housing
market and commercial development in our region and are
committed to growing our customer base. We plan to
investigate ways of potentially expanding the reach of our
current distribution system, including development of new
self-service online capabilities for builders, contractors, and
homeowners. In our gas storage business, we will focus on
maximizing the value of our storage capacity and optimizing
revenue opportunities as they arise, while recognizing the
unique challenges that currently low, seasonally stable
natural gas prices bring to the storage market.
We believe that investing in operating efficiencies and
marketing opportunities for our core businesses best
positions us for growth now and into the future.
KEY INITIATIVES. Increasing gas usage in our region is likely
to require additional infrastructure locally as well as through
new connections to gas supplies. Our utility operations and
gas storage operations at Mist currently depend on a single
bi-directional interstate transmission pipeline to transport
gas supplies to customers. We continue to work with
regulators and utilities in the Pacific Northwest to advance a
new integrated, regional cross-Cascades pipeline to create
regional diversity and increased reliability for our system.
The need for new connections to gas supply increases as
additional, potential large electric load generation and
industrial projects are sited within the region.
The need for new flexible gas-fired electric generation has
been identified in the Pacific Northwest region to integrate
intermittent wind resources into the power system. Natural
gas complements wind and solar renewable energy options
as a reliable, on-call, electric generation resource. We
believe natural gas storage for wind following electric
generation plants is needed, and we are working on
opportunities to expand our Mist storage facility to support
an announced gas fired plant being built by Portland
General Electric (PGE) at Port Westward, Oregon to follow
wind. The Mist expansion project is subject to several
conditions, including, but not limited to, PGE's approval of
projected costs.
NEW UTILITY SERVICES. We are currently working to provide
the infrastructure necessary to support compressed natural
gas (CNG) fleets, and are monitoring the new legislation
expected during 2014 that may support natural gas projects
such as conversions to natural gas, heavy-duty vehicle
conversions to CNG, and industrial projects.
23
Issues, Challenges and Performance Measures
ECONOMY. The local, national, and global economies
showed signs of improvement during 2013. We saw
increased utility customer growth and business demand for
natural gas. Our utility’s customer growth rate was 1.3% in
2013, compared to growth of 0.9% in 2012 and 0.8% in
2011. The local Oregon economy is beginning to show signs
of recovery as unemployment rates in the region dropped
from approximately 8% in 2012 to under 7% at the end of
2013. We believe our utility is well positioned for continued
customer additions and increasing industrial demand as the
economy continues to strengthen 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. Additional growth may also come
with increased industrial load from new projects in the
region and proposed legislation that favors lower carbon
emissions and lower cost energy alternatives, such as
natural gas. Our gas storage business is also impacted by
the employment trends throughout the West coast, including
California, which was among the hardest hit during the
recession, but is experiencing lower unemployment levels in
2013 and improvements in housing prices.
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 the abundance of
shale development 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. This projection is dependent upon 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 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.
We typically hedge gas prices on 75% of our utility's annual
sales requirement based on normal weather, including both
physical and financial hedges. We entered the 2013-14 gas
year (November 1, 2013 - October 31, 2014) hedged at
75% of our forecasted sales volumes, including 31% in
financial swap and option contracts and 44% in physical gas
supplies. For further discussion see "Regulatory Matters—
Rate Mechanisms—Purchased Gas Adjustment" below.
In addition to the amount hedged for the current gas
contract year, we are also hedged at approximately 33% for
the 2014-15 gas year as of December 31, 2013 and
between 7% and 21% 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, and
estimated gas reserve production. 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 storage contracts
with customers at favorable prices directly impacts our
financial results. Increases in demand for natural gas, or
decreases in supplies can put upward pressure on gas
prices and gas price volatility. Similarly, decreases in
demand and increases in supplies can cause downward
pressure on gas prices and gas price volatility. Current
storage prices remain low due to current low stable gas
prices; as a result, in the short-term we are focused on
lowering operating costs and finding opportunities in the
market to increase revenues through 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 approval of proposed remediation
solutions 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 orders. In our general rate case, the OPUC
approved our recovery of environmental costs from
investigation and site remediation subject to certain
conditions as noted in "Results of Operations—Regulatory
Matters—Rate Mechanisms" below.
We also recover some of our environmental costs from
insurance policies 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 and
demonstrate that costs were prudently incurred, and
understand the impact of the annual earnings test in
Oregon. Environmental cost recovery and carrying charges
on amounts charged to Washington customers will be
determined in a future proceeding.
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 has driven 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.
24
As required under EPA greenhouse gas regulations, we
annually report our system throughput and unintended
greenhouse gas releases. While our carbon dioxide
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. We measure our performance
and monitor progress on relevant metrics including, but not
limited to:
•
•
• ROE; and
•
earnings per share growth;
utility margin;
various operational metrics.
CONSOLIDATED EARNINGS AND DIVIDENDS
Consolidated Earnings
Consolidated highlights include:
In millions, except EPS
data
Net income
EPS
ROE
2013
2012
2011
$
60.5
2.24
$
58.8
2.18
$
63.0
2.36
8.2%
8.2%
9.0%
•
•
2012 COMPARED TO 2011. The most significant factors
contributing to the $4.3 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 businesses.
2013 COMPARED TO 2012. The primary factors contributing
to the $1.8 million increase in consolidated net income
were:
•
a $9.4 million increase in utility margin primarily due to
customer growth and the rate-base return on our gas
reserve and other investments; and
a $2.7 million after-tax charge taken in 2012 from an
Oregon general rate case disallowance.
•
Partially offsetting the above factors were:
•
a $7.1 million increase in operations and maintenance
expense primarily due to increased utility payroll and
system maintenance and safety program costs; and
a $2.9 million increase in depreciation and amortization
expenses primarily due to higher levels of investment in
property, plant, and equipment at the utility.
•
Dividends
Dividend highlights include:
Per common share
Dividends paid
2013
2012
2011
$
1.83
$
1.79
$
1.75
The Board of Directors declared a quarterly dividend on our
common stock of 46.0 cents per share, payable on February
14, 2014, reflecting an indicated annual dividend rate of
$1.84 per share.
25
RESULTS OF OPERATIONS
Regulatory Matters
Regulation and Rates
UTILITY. Our utility business is subject to regulation by the
OPUC, WUTC, and FERC with respect to, among other
matters, rates and terms of service. The OPUC and WUTC
also regulate the system of accounts and issuance of
securities by our utility. In 2013, 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 general rate cases
and other proceedings in Oregon and Washington, but are
also affected by the local economies in Oregon and
Washington, the pace of customer growth in the residential,
commercial, and industrial markets, and 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 "Most Recent
General Rate Cases" below.
GAS STORAGE. Our gas storage businesses are subject to
regulation by the OPUC, CPUC, and FERC with respect to,
among other matters, rates and terms of service. The
OPUC and CPUC also regulate the issuance of securities
and system of accounts. The OPUC and FERC regulate
intrastate and interstate storage services, respectively,
under a maximum cost of service model which allows for
gas 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 2013, approximately 56% of our
storage revenues were derived from FERC and Oregon
regulated operations and approximately 44% from California
operations.
Most Recent General Rate Cases
OREGON. Effective November 1, 2012, the OPUC
authorized rates to customers based on an ROE of 9.5%,
an overall rate of return of 7.78%, and a capital structure of
50% common equity and 50% long-term debt.
WASHINGTON. In 2008, 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.
FERC. 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. In December 2013
we filed a rate petition, which was approved in 2014 and
allows for the maximum cost-based rates for our interstate
gas storage services. These rates are effective January 1,
2014, with the rate changes having no significant impact on
our revenues.
2013 Regulatory Activities
WORKING GAS INVENTORY SETTLEMENT. On September 30,
2013, the OPUC approved an all-party settlement
agreement that allows the Company to include $39.5 million
of inventory in rate base and recover $4.5 million in carrying
costs. Previously, the Company had been accruing earnings
of $4.0 million related to working gas carrying costs for 2013
based on the amount of working gas inventory proposed in
our 2012 general rate case. The carrying costs were
included in PGA rates beginning November 1, 2013.
GASCO WATER TREATMENT STATION. On October 28, 2013,
the OPUC approved placing $19.0 million of capital costs
associated with constructing a water treatment station at our
Gasco environmental site into rates beginning November 1,
2013. These amounts are subject to refund, with interest, in
the event the Commission determines, through a separate
docket, that any of these costs were incurred imprudently.
On February 13, 2014, NW Natural filed an all-party
stipulation in the proceeding with the OPUC, which if
approved, would deem Gasco construction costs prudent
and would also approve applying $2.5 million of insurance
proceeds plus interest to reduce the Gasco costs included
in rates beginning November 1, 2014.
SITE REMEDIATION AND RECOVERY MECHANISM (SRRM). In
the 2012 Oregon general rate case, this new mechanism
was approved to recover the Company's deferred
environmental costs. The Commission ordered a separate
docket to determine the prudence of deferred costs, the
allocation of insurance proceeds, and an earnings test that
would be applied to past and future deferred costs. In July
2013, all parties filed a settlement agreement with the
OPUC to address how to apply the new mechanism. In
November, the Commission rejected the settlement and
ordered further proceedings. We have established a
schedule for 2014 and are working toward resolving this
matter.
INTERSTATE STORAGE SHARING. A docket has been
opened to review the current revenue sharing arrangement
that allocates a portion of the net revenues generated from
non-utility Mist storage services and third-party asset
management services to utility customers. We anticipate
resolution of this docket in 2014.
PREPAID PENSION ASSETS. The Company requested in its
last rate case that prepaid pension assets be included in
rate base and allowed a return on the investment. A
separate docket was ordered by the OPUC to review the
rate treatment of pensions on a general, non-utility-specific
basis. This pension docket is currently open and we
anticipate resolution in 2014. The OPUC has authorized NW
Natural to continue collecting pension expense based on
the amounts set in our 2003 Oregon general rate case and
to defer into a regulatory balancing account the difference
between actual expense and collected expense for future
rate recovery. We anticipate resolution of this docket in
2014.
CNG TARIFF APPROVED. In January 2014, we received
approval from the OPUC to offer business customers a
service to install, own, and maintain gas compression
equipment that enables them to fuel their vehicle fleets with
CNG. NW Natural filed the tariff in June 2013 after receiving
26
requests from businesses interested in switching or
increasing the number of their fleet vehicles fueled by CNG.
Costs associated with providing this service will be directly
paid by business customers using the service. The OPUC
will review the tariff in two years to assess the market for
CNG at that time.
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, the production of gas reserves, interstate
pipeline demand costs, a permanent rate adjustment for our
SIP program, temporary rate adjustments, which amortize
balances of deferred regulatory accounts, and the removal
of temporary rate adjustments effective for the previous
year.
In October 2013, the OPUC and WUTC authorized PGA
rate changes effective November 1, 2013. The effect of
these rate changes was an increase in the average monthly
bills of both Oregon and Washington residential customers
by 1.5%. This was the first rate increase in five years for
both states, reflecting annual adjustments for changes in
wholesale costs of natural gas as well as some additional
changes to Oregon rate base.
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.
EARNINGS TEST REVIEW. 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 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 2011-2012, 2012-2013, and 2013-2014 PGA years. The
ROE threshold is subject to adjustment annually based on
movements in long-term interest rates. For calendar years
2011 and 2012, the ROE threshold after adjustment for
long-term interest rates was 10.92% for both years. We
refunded $0.7 million to customers based on the 2011 utility
earnings test, and there were no refunds required based on
the 2012 utility earnings test. For calendar year 2013, the
ROE threshold was 10.58% with no refund expected to be
required based on our results of operations. The 2013 test
is expected to be filed in May of 2014.
27
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 revenues, costs, and
production volumes expected, and any variances between
forecasted and actual results are subject to our PGA
incentive sharing in Oregon.
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. This 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 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
from December through 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.
Residential and commercial customers in Oregon are
allowed to opt out of the weather normalization mechanism,
and as of December 31, 2013, 8% had opted out. We do not
have a weather normalization mechanism approved for
residential and commercial Washington customers, which
account for about 10% of total customers. 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 (SIP). Since 2002, various
laws requiring minimum standards for integrity management
programs and SIPs for natural gas transmission and
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 approved specific accounting treatment and cost
recovery for our transmission pipeline integrity management
program, our SIP, and for related pipeline safety rules
adopted by the U.S. Department of Transportation’s
PHMSA. In addition, the OPUC has provided a two-year
extension beginning in November 2012 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 base
recovery after the first $4 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. During 2013, the
Commission approved a temporary increase to the annual
cap, authorizing an additional $13.7 million of expenditures
above the cap over the next two years to be tracked into
rates. With the increased cap, we plan to substantially
complete our bare steel replacement by the end of 2015,
and as a result this stipulation precludes us from tracking
any additional bare steel replacement costs into rates after
2015. We do not have any special accounting or rate
treatment for our SIP costs incurred in the state of
Washington.
ENVIRONMENTAL COST DEFERRAL. The OPUC has
authorized the deferral of environmental costs associated
with certain named sites and to accrue carrying costs 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 OPUC has authorized us to defer
environmental costs and accrued carrying costs through
January 2014. We filed a request with the OPUC in January
2014 to continue our deferral of costs through January
2015. See Note 15 and 17 for further discussion of our
28
regulatory and insurance recovery of environmental costs
and "2013 Regulatory Activities" above for information
regarding SRRM.
The WUTC also authorized the deferral of environmental
costs, if any, that are appropriately allocated to Washington
customers. This order was effective January 26, 2011 with
cost recovery and a carrying charge to be determined in a
future proceeding.
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. Pension expense deferrals were $9.1 million
and $7.9 million in 2013 and 2012, respectively. 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 STORAGE SHARING. On an
annual basis, we credit amounts to Oregon and Washington
customers as part of our regulatory incentive sharing
mechanism related to revenues from gas storage and asset
management of pipeline capacity and gas storage at Mist.
Generally amounts are credited to Oregon customers in
June, while credits are given to customers in Washington
through reductions in rates in the annual PGA filing in
November. See "Business Segments—Gas Storage" below.
The following table presents the credits to customers:
In millions
Oregon utility
customer credit
Washington utility
customer credit
2013
2012
2011
$
8.8
$
9.2
$
12.5
0.5
0.8
0.9
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. 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
2013
2012
2011
Utility net income
$
54.9
$
54.0
$
EPS - utility segment
2.03
2.01
59.7
2.23
Gas sold and delivered
(in therms)
Utility margin(1)
1,146
1,112
1,152
$
353.9
$
344.5
$
343.0
(1) See Utility Margin Table below for a reconciliation and additional
detail.
•
2013 COMPARED TO 2012. The primary factors contributing
to the $0.9 million or $0.02 per share increase in net income
were as follows:
•
a $9.4 million net increase in utility margin primarily due
to:
a $10.8 million increase related to customer growth
and the rate-base return on our gas reserve and
other investments, such as our pipeline integrity
tracker; and
a $3.9 million increase related to the timing
impacts of changes in fixed monthly charges and
decoupling baselines in the 2012 Oregon general
rate case. As a result of changes to the decoupling
baseline for average use per customer included in
the 2012 rate case, the decoupling mechanism's
results this year will not be comparable to last year,
although the overall impact on revenues will
generally be the same on an annualized basis.
These increases in margin were partially offset by:
a $3.9 million decrease in gains from gas cost
incentive sharing due to actual gas prices that
were roughly equivalent to estimated PGA prices
for the current year as compared to actual gas
prices that were lower than estimated PGA prices
for the prior year; and
a $1.4 million decrease primarily related to the
lower Oregon Authorized ROE of 9.5% from the
2012 general rate case.
a $1.5 million increase in other income and expense,
net primarily due to interest on higher average
regulatory account balances; and
a $2.7 million one-time tax charge taken in 2012 from
an Oregon general rate case disallowance. See
"Application of Critical Accounting Policies and
Estimates—Regulatory Accounting" below.
These factors were partially offset by:
a $7.4 increase in operations and maintenance
expense primarily due to increased utility payroll and
system maintenance and safety program costs;
a $2.9 million increase in depreciation and amortization
expense primarily due to a higher level of investment in
utility property, plant, and equipment; and
a $2.4 million increase in interest expense primarily due
to increases in long-term debt outstanding.
•
•
•
•
•
Total utility volumes sold and delivered in 2013 increased
3.1% over last year primarily due to the impact of colder
weather on residential and commercial use.
2012 COMPARED TO 2011. The primary factors contributing
to the $5.6 million or $0.22 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
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.
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 ROE.
•
•
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.
29
UTILITY MARGIN TABLE. The following table summarizes the composition of utility gas volumes, revenues, and cost of sales:
In thousands, except degree day and customer data
2013
2012
2011
Favorable/(Unfavorable)
2013 vs.
2012
2012 vs.
2011
Utility volumes (therms):
Residential and commercial sales
Industrial sales and transportation
671,906
474,525
637,885
473,884
681,621
470,733
34,021
(43,736)
641
3,151
Total utility volumes sold and delivered
1,146,431
1,111,769
1,152,354
34,662
(40,585)
Utility operating revenues:
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 (loss) 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
Actual degree days
Percent colder (warmer) than average weather(3)
$ 673,250
$ 642,337
$
744,355
$ 30,913
$ (102,018)
68,880
70,020
—
4,054
19,002
727,182
373,298
—
5,935
18,430
699,862
355,335
81,313
(7,162)
3,713
20,741
801,478
458,508
(1,140)
(11,293)
—
(1,881)
7,162
2,222
572
(2,311)
27,320
17,963
(101,616)
(103,173)
$ 353,884
$ 344,527
$
342,970
$
9,357
$
1,557
$ 321,608
$ 306,382
$
315,688
$ 15,226
$
(9,306)
28,335
4,308
(41)
(326)
—
28,586
4,452
3,811
1,296
—
28,635
4,875
2,107
(1,173)
(7,162)
(251)
(144)
(3,852)
(1,622)
—
(49)
(423)
1,704
2,469
7,162
$ 353,884
$ 344,527
$
342,970
$
9,357
$
1,557
628,634
65,321
918
621,399
63,619
923
694,873
685,941
4,379
4,152
615,670
62,948
925
679,543
4,652
3%
(3)%
9%
7,235
1,702
(5)
5,729
671
(2)
8,932
6,398
(1) See "Regulatory Adjustment for Income Taxes Paid" below for additional information.
(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 2013, average weather
represents the 25-year average degree days as set in our 2012 Oregon general rate case. For 2012, average weather represents degree
days based on the 25-year average set in our 2003 Oregon general rate for the months of January through October, plus the 25-year
average set in the 2012 Oregon general rate case for the months of November and December. For 2011, average weather represents the
25-year average degree days as set in the 2003 Oregon general rate case.
30
a $3.9 million increase related to the timing
impacts of changes in fixed monthly charges and
decoupling baselines in the 2012 Oregon general
rate case.
Partially offsetting these increases was a $1.4
million decrease primarily related to the lower
Oregon Authorized ROE of 9.5% from the 2012
general rate case.
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;
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 ROE; and
a $3.4 million margin increase from our gas
reserves investment.
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.
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. The impact of weather on margin is
significantly reduced through our weather normalization
mechanism in Oregon. Approximately 80% of our total
customers are covered under this mechanism. The
remaining customers either opt out of the mechanism or are
located in Washington, which does not have a similar
mechanism in place. 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:
2013
2012
2011
418.6
253.3
671.9
395.5
242.4
637.9
424.9
256.7
681.6
Residential sales
$
447.4
$
428.5
$
497.2
Commercial sales
225.9
213.8
247.2
Total operating
revenues
Utility margin:
Residential:
Sales
Weather normalization
Decoupling
Total residential utility
margin
Commercial:
Sales
Weather normalization
Decoupling
Total commercial utility
margin
$
673.3
$
642.3
$
744.4
$
234.1
$
211.6
$
222.5
(9.0)
2.6
(0.1)
8.6
(10.2)
16.7
227.7
220.1
229.0
92.1
(4.0)
5.8
93.9
84.0
0.2
2.1
86.3
87.0
(2.9)
2.6
86.7
Total utility margin
$
321.6
$
306.4
$
315.7
2013 COMPARED TO 2012. The primary factors contributing
to changes in the residential and commercial markets were
as follows:
•
sales volumes increased 34.0 million therms, or 5%,
primarily reflecting 5% colder weather and customer
growth;
operating revenues increased $30.9 million, or 5%,
due to a 5% increase in sales volumes and $36.2
million of credits from gas cost savings which were
applied to customer billings in 2012, partially offset by
an 9% decrease in average gas prices, which flowed
through the Company's PGA rates; and
utility margin increased $15.2 million, or 5%, primarily
reflecting the following:
•
•
a $10.8 million increase related to customer growth
and the rate-base return on our gas reserve and
other investments; and
31
Industrial sales and transportation highlights include:
Other revenue highlights include:
In millions
2013
2012
2011
In millions
2013
2012
2011
Volumes (therms):
Other operating revenues
$
4.1
$
5.9
$
3.7
Industrial - firm sales
34.3
34.9
37.6
Industrial - firm
transportation
Industrial - interruptible
sales
Industrial - interruptible
transportation
Total volumes
Utility margin:
Industrial - sales and
transportation
144.5
131.2
133.0
59.5
59.6
59.1
236.2
474.5
248.2
473.9
241.0
470.7
$
28.3
$
28.6
$
28.6
2013 COMPARED TO 2012. The primary factors contributing
to changes in the industrial sales and transportation markets
were as follows:
•
sales volumes remained relatively flat for 2013
compared to 2012; and
utility margin decreased 1%, primarily due to lower
demand from customers in the pulp and paper
segment. These decreases were partially offset by
contributions from new customers and added load from
existing customers.
•
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
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.
•
Regulatory Adjustment for Income Taxes Paid
Oregon Senate Bill (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. Due to
the repeal, the Company recorded a $7.4 million write-off
including interest in 2011. 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.
32
2013 COMPARED TO 2012. The primary factors contributing
to changes in other revenues were as follows:
•
other revenues decreased $1.9 million primarily due to
a positive 2012 regulatory adjustment which did not
reoccur in 2013.
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.
Cost of Gas
Cost of gas as reported by the utility includes gas
purchases, gas withdrawn 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 have 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 hedge contracts (derivative
instruments), primarily fixed-price commodity swaps,
consistent with our financial derivatives policies to help
manage gas price stability. Gains and losses from these
financial hedge contracts are generally included in our PGA
and normally do not impact net income because the hedged
prices are reflected in our annual PGA rates, subject to a
regulatory prudence review. However, hedge contracts
entered into after the annual PGA rates are set for Oregon
customers 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.
Cost of gas highlights include:
Dollars and therms in
millions
2013
2012
2011
Cost of gas
$
373.3
$
355.3
$
458.5
Total volumes sold and
delivered (therms)
Average cost of gas
(cents per therm)
Gain from gas cost
incentive sharing
1,146
1,112
1,152
$
0.49
$
0.54
$
0.59
—
3.8
2.1
2013 COMPARED TO 2012. The primary factors contributing
to changes in cost of gas were as follows:
•
cost of gas increased $18.0 million, or 5%, 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
decreased $19.7 million, or 5%, primarily due to a 3%
increase in volumes offset by an 9% decrease in
average cost of gas collected through rates, reflecting
lower market prices for natural gas.
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
decreased $65.5 million, or 14%, primarily reflecting
lower usage due to 11% warmer weather and PGA rate
decreases in 2012 and 2011; and
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.
•
The effect on net income from our gas cost incentive
sharing mechanism was a pre-tax loss in margin of less
than $0.1 million in 2013 compared to a pre-tax gain in
margin of $3.8 million in 2012 and $2.1 million in 2011. 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 businesses segment. Pre-tax
income from gas storage at Mist and asset management
services using our utility's storage or transportation capacity
33
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 Gill Ranch. See Note 4.
Gas storage segment highlights include:
In millions, except EPS
data
2013
2012
2011
Gas storage net income
$
5.6
$
4.5
$
4.1
EPS - gas storage
segment
Average gas storage
contracted capacity (Bcf)
0.21
21
0.17
21
0.15
16
2013 COMPARED TO 2012. Our gas storage segment net
income increased $1.0 million primarily due to higher
revenues from asset management services and lower
operating costs.
2012 COMPARED TO 2011. Our gas storage segment 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.
For the 2013-2014 gas storage year we are fully contracted
at Gill Ranch and at Mist. We are in the process of
contracting for the upcoming 2014-2015 gas storage year,
which begins in April 2014. The market outlook for gas
storage in 2014 remains challenging. In recent months, the
country has seen significant storage withdrawals and gas
price volatility due to the extreme cold weather nationally,
but current storage values have been negatively impacted
by the increase in spring and summer prices as they are
similar to winter prices, thus reducing the desirability of
purchasing gas. As a result we anticipate contracting for the
upcoming storage year at lower market prices than in
previous periods, especially at our California facility where
some multi-year contracts are expiring. See, "Financial
Condition—Liquidity and Capital Resources" for more
information.
Other
Other primarily consists of NNG Financial's equity
investment in KB Pipeline, an equity investment in PGH,
which in turn has invested in a cross-Cascades pipeline
project, and other miscellaneous non-utility investments and
business activities. See Note 4 and Note 12 for further
details on other activities and our investment in PGH.
Other highlights include:
In millions, except EPS
data
2013
2012
2011
Other net income (loss)
$
— $
0.2
$
EPS - other
—
—
(0.7)
(0.02)
2013 COMPARED TO 2012. Other remained relatively flat over
2013 compared to 2012, as anticipated.
2012 COMPARED TO 2011. Other 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.
Consolidated Operations
Operations and Maintenance
Operations and maintenance highlights include:
In millions
2013
2012
2011
Operations and maintenance
$ 136.6
$ 129.5
$ 125.4
2013 COMPARED TO 2012. Operations and maintenance
expense increased $7.1 million or 6% in 2013 compared to
2012. The following summarizes the major factors that
contributed to this increase:
•
a $5.9 million increase in utility payroll expense
primarily related to additional customer service
positions for new programs and higher incentive
compensation; and
a $2.7 million increase in utility expenses related to
system maintenance and safety program costs.
•
Partially offsetting the above factors were:
•
a $0.9 million decrease in utility bad debt expense. See
further discussion below.
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.
•
The utility's bad debt expense remains well below 0.5% of
operating revenues and has decreased compared to 2012.
This decrease is primarily due to lower levels of delinquent
account balances during the period and a continuation of
lower delinquency rates resulting in an overall decrease to
our allowance for uncollectible accounts. Our bad debt
expense results are at historically low levels for the
Company.
Our accounting expense for pension costs increased in
2013 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,
2013 and 2012, we deferred pension expenses totaling $9.1
million and $7.9 million, respectively. See Note 8. As a
result, increased pension costs had a minimal effect on
operations and maintenance expense in 2013 and 2012,
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 principally consist of property and payroll
taxes and regulatory fees.
General tax highlights include:
In millions
General taxes
2013
2012
2011
$
30.0
$
30.6
$
29.3
2013 COMPARED TO 2012. General taxes remained relatively
flat for 2013 compared to 2012, as anticipated.
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 during 2012, as well as a $0.4 increase in payroll
tax expense at the utility.
Depreciation and Amortization
Depreciation and amortization highlights include:
In millions
2013
2012
2011
Depreciation and amortization
$
75.9
$
73.0
$
70.0
2013 COMPARED TO 2012. Depreciation and amortization
expense for 2013 increased by $2.9 million compared to
2012 due to an increase in utility depreciation expense on
investments in utility plant for system improvements and
training facilities.
34
Income Tax Expense
Income tax expense highlights include:
In millions
2013
2012
2011
Income tax expense
$ 41.7
$ 43.4
$ 42.8
Effective tax rate
40.8%
42.5%
40.5%
2013 COMPARED TO 2012. The decrease in income tax
expense of $1.7 million or 4% was primarily due to a $2.7
million one-time tax charge taken in 2012 from an Oregon
general rate case disallowance.
2012 COMPARED TO 2011. The increase in income tax
expense of $0.6 million or 1% was primarily due to a one-
time $2.7 million tax charge related to the 2012 Oregon
general rate case. This increase in taxes was partially offset
by lower pre-tax consolidated earnings.
EFFECTIVE TAX RATES. The effective tax rate in 2013 was
lower due to the tax charge taken in 2012 but consistent
with expectations and historical rates. The higher effective
tax rate in 2012 was primarily due to the $2.7 million tax
charge related to the Oregon general rate case. For more
information on our income taxes, including a reconciliation
between the statutory federal and state income tax rates
and the effective tax rate, see Note 2 and Note 9.
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 provide
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,
2013
2012
44.7%
45.3%
40.5
14.8
42.9
11.8
100.0%
100.0%
2012 COMPARED TO 2011. Depreciation and amortization
expense for 2012 increased by $3.0 million compared to
2011 primarily due to a $2.7 million increase in investments
in utility plant for system improvements and training
facilities.
Other Income and Expense, Net
Other income and expense, net highlights include:
In millions
2013
2012
2011
Gains from company-
owned life insurance
$
Interest income
Gain on sale of
investments
Income (loss) from equity
investments
Net interest on deferred
regulatory accounts(1)
Other non-operating
Total other income and
expense, net
2.5
0.1
—
(0.1)
4.5
(2.3)
$
$
2.3
0.2
(0.2)
—
3.0
(2.1)
2.2
0.1
(0.1)
(1.6)
4.6
(2.1)
$
4.7
$
3.2
$
3.1
(1) Prior period balances have been adjusted for a prior period error
identified during the first quarter of 2013. See Note 16 for additional
detail.
2013 COMPARED TO 2012. Other income and expense, net
increased $1.5 million in 2013 primarily due to interest on
higher average regulatory account balances.
2012 COMPARED TO 2011. Other income and expense, net
remained relatively flat for 2012 compared to 2011.
Interest Expense, Net
Interest expense, net highlights include:
In millions
2013
2012
2011
Interest expense, net
$
45.2
$
43.2
$
42.1
2013 COMPARED TO 2012. Interest expense, net of amounts
capitalized, increased $2.0 million in 2013 primarily due to
an increase of $2.3 million at the utility from the issuance of
long-term debt. The utility issued $50 million of debt with a
coupon rate of 3.542% in August 2013 and $50 million of
debt with a coupon rate of 4.00% in October 2012. This
increase was partially offset by a $0.7 million reduction in
2013 interest expense at the utility from the retirement of
$40 million of long-term debt with a coupon rate of 7.13% in
2012. See Note 7 for further detail.
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.
Interest expense also reflects a lower average interest rate
used in calculating the allowance for funds used during
construction (AFUDC). AFUDC rates, consists of short-term
and long-term capital costs as appropriate, were 0.3% in
both 2013 and 2012, and 0.5% in 2011.
35
Liquidity and Capital Resources
At December 31, 2013, we had $9.5 million of cash and
cash equivalents compared to $8.9 million at December 31,
2012. We also had $4.0 million in restricted cash at Gill
Ranch as of December 31, 2013 and 2012, 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. Our use of retained earnings is not
subject to those same restrictions.
For the utility segment, the short-term borrowing
requirements typically peak during colder months when the
utility borrows money to cover the lag between when it
purchases natural gas and when customers pay for the gas.
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 expenditures, refinance
maturing debt of the utility and provide for general corporate
purposes of the utility.
Market conditions have improved over 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 adverse market conditions or other
reasons, we expect that our near term liquidity needs can
be met using internal cash flows 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, 2013, we have
Board authorization to issue up to $325 million of additional
first mortgage bonds. We currently have OPUC approval to
issue up to $25 million of additional long-term debt for
approved purposes. We plan to file an application with the
OPUC in early 2014 to increase our OPUC long-term debt
authorization to $325 million.
In the event that our senior unsecured long-term debt
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. However, based
upon current financial swap and option contracts
outstanding, we do not have any collateral demand
exposure as the Company had unrealized gains of $5.4
million at December 31, 2013.
The "Dodd-Frank Wall Street Reform and Consumer
Protection Act" (Dodd-Frank Act or DFA) establishes a
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 an
exempt end-user and as such we are 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, current tax benefits from bonus
depreciation and other tax advantaged investments,
environmental expenditures and insurance recoveries, and
strategic growth initiatives.
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
Protection Act rules, including the new rules issued under
the Moving Ahead for Progress in the 21st Century Act
(MAP-21). See "Application of Critical Accounting Policies—
Accounting for Pensions and Postretirement Benefits"
below.
Regarding federal income tax liabilities, extensions were
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 reduced our tax liability
for those tax years and is expected to provide cash flow
benefits in subsequent years.
Concerning environmental expenditures, we expect to
continue using cash resources to fund our environmental
liabilities, but we also anticipate recovering amounts through
our insurance settlements and utility rates. The amount and
timing of these expenditures is uncertain with additional
insurance recoveries expected in 2014. See Note 15, Note
17, and "Results of Operations—Regulatory Matters—
Environmental Costs".
The Company did not issue any one-time refunds or credits
to customers from gas cost savings in 2013. In 2012, due to
significantly lower gas prices from November 2011 to March
2012, the Company was able to provide $35 million of
credits to its Oregon utility customers' bills and $4 million in
credits to its Washington customers. See "Results of
Operations—Regulatory Matters—Regulatory Mechanisms
—Purchased Gas Adjustment and —Customer Credits for
Gas Cost Incentive Sharing" above. In addition, the
Company may also provide its Oregon utility customers with
interstate storage credits from the regulatory incentive
36
sharing mechanism related to gas storage and asset
management services. See "Results of Operations—
Regulatory Matters—Regulatory Mechanisms—Customer
Credits for Gas Storage Sharing" above.
Short-term liquidity for our gas storage segment is
supported by cash balances, internal cash flow from
operations, external financing, and, to a certain extent,
equity investments from its parent company. Gill Ranch has
limited operational history, with operations commencing in
October 2010. The abundant supply of natural gas, low
volatility of natural gas prices, and available gas storage
capacity in California have resulted in lower storage market
prices than we have seen in previous years. As a result, we
are anticipating lower estimated future earnings and cash
flows for Gill Ranch. The amount and timing of these cash
flows from year to year are uncertain as the majority of Gill
Ranch's storage contracts are short-term. While we expect
short-term storage prices to be challenging, we do not
anticipate material changes in our sources of short-term
liquidity and anticipate our operating cash flows will be
sufficient.
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, 2013. 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.
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 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, certain prepayment penalties, restrictions on
dividends out of Gill Ranch unless certain earnings ratios
are met, and restrictions on the incurrence of additional
debt. At December 31, 2013, we were in compliance with all
covenants and restrictions under the debt agreements.
Based on several factors, we believe our Company's
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 declarations and amount of future dividends will
depend upon our earnings, cash flows, financial condition
and other factors. The amount and timing of dividends
payable on our common stock is at the sole discretion of our
Board of Directors.
Off-Balance Sheet Arrangements
Except for certain lease and purchase commitments, we
have no material off-balance sheet financing arrangements.
See "Contractual Obligations" below.
37
Contractual Obligations
The following table shows our contractual obligations at December 31, 2013 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,
2014
2015
2016
2017
2018
Thereafter
Total
$
188.2
$
— $
— $
— $
— $
— $
60.0
41.8
21.9
0.5
5.6
60.7
98.7
49.2
0.5
15.2
40.0
40.3
22.5
0.2
5.5
—
77.4
41.8
0.1
—
65.0
37.3
23.3
0.1
5.5
—
66.1
—
—
—
40.0
32.1
24.1
—
5.5
—
52.1
—
—
—
22.0
29.2
25.0
—
2.9
—
42.3
—
—
—
514.7
271.3
148.7
—
34.9
—
217.0
—
13.6
—
188.2
741.7
452.0
265.5
0.8
59.9
60.7
553.6
91.0
14.2
15.2
Total
$
542.3
$
227.8
$
197.3
$
153.8
$
121.4
$
1,200.2
$
2,442.8
(1) Postretirement benefit payments primarily consists of two items: (1) estimated qualified defined benefit pension plan payments, which are
funded by plan assets and future cash contributions, and (2) required payments to the Western States multiemployer pension plan due to
the Company withdrawing from the plan in December 2013. 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, 2013. 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 under our agreements. 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 12
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, 2013, 612 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 five-
year labor agreement called the Joint Accord. The 2009
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 2009 Joint Accord extends to May 31, 2014.
In 2013, each party served notice of intent to negotiate the
terms of an agreement prior to the May 31, 2014 expiration
date. We are currently engaged in negotiations to meet this
schedule.
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, 2013 and 2012, our utility had commercial
paper outstanding of $188.2 million and $190.3 million,
respectively. The effective interest rate on the utility’s
commercial paper outstanding at December 31, 2013 and
2012 was 0.3%.
38
Credit Agreements
In December 2012, we entered into a new multi-year credit
agreement for unsecured revolving loans totaling $300
million and an available extension of commitments for two
additional one-year periods, subject to lender approval. In
December 2013, we extended our commitment for an
additional year with an updated maturity date of December
20, 2018. All lenders under the new agreement are major
financial institutions with committed balances and
investment grade credit ratings as of December 31, 2013 as
follows:
In millions
Lender rating, by category
Loan Commitment
AA/Aa
A/A
BBB/Baa
Total
$
$
189
111
—
300
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, the Company does not believe this risk to be
eminent due to the lenders' strong investment grade credit
ratings.
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, 2013 or
2012. The 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,
2013 and 2012, with consolidated indebtedness to total
capitalization ratios of 55.3% and 54.7%, 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 credit ratings are a factor in our liquidity, affecting our
access to the capital markets including the commercial
paper market. Our credit ratings also have an impact on the
cost of funds and the need to post collateral under
derivative contracts. In February 2014, Moody's revised our
ratings outlook from negative to stable. 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
Stable
The above credit ratings are dependent upon a number of
factors, both qualitative and quantitative, and are subject to
change at any time. The disclosure of these credit ratings is
not a recommendation to buy, sell or hold NW Natural
securities. Each rating should be evaluated independently of
any other rating.
Retirements of Long-Term Debt
The following FMBs were retired:
In millions
Company First Mortgage Bonds
6.665% Series B due 2011
7.13% Series B due 2012
Years Ended December 31,
2013
2012
2011
$
$
— $
— $
—
— $
40
40
$
10
—
10
39
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
2013
2012
2011
Cash provided by operating
activities
$ 176.4
$ 168.8
$ 233.5
2013 COMPARED TO 2012. The significant factors
contributing to the $7.6 million increase in operating cash
flows were as follows:
• an increase of $15.8 million in other, net primarily due to
inflows from changes in net regulatory balances offset by
a decrease in pension liabilities;
• an increase of $12.4 million from net changes in gas cost
balances, which primarily reflects $39 million in credits
refunded to customers in 2012;
• an increase of $11.8 million due to lower cash
contributions to qualified defined benefit pension plans as
a result of new IRS funding rules, commonly referred to
as MAP-21;
• an increase of $8.0 million from changes in accounts
payable balances; and
• an increase of $4.7 million due to changes in the
amortization of gas reserves balance.
Partially offsetting these increases was:
• a decrease of $48.3 million from changes in the accounts
receivable balance, primarily due to customer growth and
29% colder weather in December 2013.
During the year ended December 31, 2013, we contributed
$11.7 million to our utility's qualified defined benefit pension
plans, which was significantly higher than the $5.7 million in
non-cash expense recognized on the income statement. In
2012, we contributed $23.5 million and had $5.4 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 the new federal funding requirements under MAP-21.
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 (2010 Act) and American Taxpayer
Relief Act of 2012 (2012 Act). The 2010 Act allowed 100%
bonus depreciation on qualified property placed in service
between September 9, 2010 and December 31, 2011, and
also extended the 50% bonus depreciation deduction to
qualifying property placed in service during 2012. The 2012
Act extended 50% bonus depreciation through 2013 for
modified accelerated cost recovery system (MACRS)
property with a recovery period of 20 years or less. These
and other tax benefits resulted in a net operating 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 the net operating loss (NOL) carried forward from
2010. We generated NOL carryforwards during 2012 and
2013. As of December 31, 2013, we had an estimated
federal income tax receivable balance of $3.2 million and an
estimated NOL carryforward balance of $113.0 million. In
2011, Oregon conformed with federal bonus depreciation,
contributing to a state NOL carryforward of $113.7 million.
We anticipate being able to use the full amount of 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.
Final tangible property regulations applicable to all
taxpayers were issued by the Treasury Department on
September 13, 2013. These regulations are generally
effective for taxable years beginning on or after January 1,
2014. In addition, procedural guidance related to the
regulations was recently issued under which taxpayers may
make accounting method changes to comply with the
regulations. We have evaluated the regulations and do not
anticipate any material impact. However, unit-of-property
guidance applicable to natural gas distribution networks has
not yet been issued and is expected in 2014. We will
evaluate the impact of this guidance once it is finalized.
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
colder weather at the end of 2011, which were collected
early in 2012.
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.
40
Investing Activities
Investing activity highlights include:
In millions
2013
2012
2011
Total cash used in investing
activities
$ 182.1
$ 184.7
$ 153.1
Capital expenditures
138.9
132.0
100.5
Proceeds from sale of
assets
Utility gas reserves
(8.6)
54.1
—
54.1
—
50.6
2013 COMPARED TO 2012. The $2.5 million decrease in cash
used in investing activities was due to proceeds received
from the sale of assets. This decrease was partially offset
by higher capital expenditures, reflecting increased
investments for new customer acquisitions, completion of
our Gasco Source Control water treatment station, and
additional expenditures for system integrity and bare steel
pipe removal.
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.
Over the five-year period 2014 through 2018, 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 around $90 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
2014, utility capital expenditures are estimated to be
between $115 and $135 million, and non-utility capital
investments are estimated to be less than $10 million.
Additional non-utility spend for gas storage and other
investments during and after 2014 will depend largely on
future decisions about potential expansion opportunities in
gas storage and pipeline projects. Gas storage segment
capital expenditures in 2014 are expected to be paid from
working capital, and additional equity contributions from NW
Natural as needed.
Financing Activities
Financing activity highlights include:
In millions
2013
2012
2011
Total cash provided by (used
in) financing activities
$
6.3
$
18.9
$
(78.0)
Change in short-term debt
Change in long-term debt
(2.1)
50.0
48.7
10.0
(115.8)
80.0
2013 COMPARED TO 2012. The $12.6 million decrease in
cash provided by financing activities was primarily due to
changes in our short-term debt balances, which decreased
$2.1 million in 2013 compared to an increase of $48.7
million in 2012. This decrease was partially offset by
changes in our long-term debt balances, which increased
due to $40 million of long-term debt retired in 2012. 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.
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 have a stock repurchase program approved through
May 2014 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 2013, 2012 or 2011 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 an 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 $21.5 million in 2013, an increase of $2.4
million from 2012. The fair market value of pension assets in
this plan increased to $267.1 million at December 31, 2013
from $249.6 million at December 31, 2012. The increase
was due to a return on plan assets of $22.9 million plus
$11.7 million in employer contributions, partially offset by
benefit payments of $17.1 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
benefit pension plans were underfunded by $95.3 million at
December 31, 2013. We plan to make contributions during
2014 of $15 million.
41
We also contributed 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 $0.5 million to
the Union Plan in 2013 and $0.4 million in 2012. Effective
December 22, 2013, we withdrew from the plan and have
been assessed a withdrawal liability of approximately $8.3
million, which requires NW Natural to contribute $0.6 million
each year to the plan for the next 20 years. See Note 8 for
further pension disclosures.
Ratios of Earnings to Fixed Charges
For the years ended December 31, 2013, 2012, and 2011,
our ratios of earnings to fixed charges, computed using the
Securities and Exchange Commission (SEC) method,
were 3.16, 3.26, and 3.38, 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. The prior period amounts have
been corrected for the prior period error identified in the first
quarter of 2013. See Note 16 for detail on the prior period
correction and Exhibit 12 for the detailed ratio calculation.
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, 2013, we had a regulatory asset of
$148.4 million for deferred environmental costs, which
includes $98.1 million for additional costs expected to be
paid in the future and $20.3 million of accrued interest.
Additionally, in 2014, a settlement was reached in our
environmental insurance recovery litigation with remaining
insurers. If it is determined that insurance recoveries for
environmental costs are insufficient and future rate recovery
of such costs are not probable, the costs will be charged to
expense in the period such determination is made. For
further discussion of contingent liabilities see Note 15, for an
update regarding insurance settlements see Note 17, and
see also "Results of Operations—Regulatory Matters—Rate
Mechanisms—Environmental Costs".
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.
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 accounting;
• 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) requires 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
regulatory assets from, or are required to refund regulatory
liabilities 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.
43
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 our regulatory assets and liabilities at
December 31, 2013 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, 2013 and 2012 was $60.4 million and $125.8
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. Accrued unbilled
revenue at December 31, 2013 and 2012 was $61.5 million
and $57.0 million, respectively. The increase in accrued
unbilled revenue at year-end 2013 was primarily due to
higher volumes in December 2013, reflecting colder weather
late in the month, and higher customer billing rates.
The following table presents changes in key metrics if the
estimated percentage of unbilled volume at December 31
was adjusted up or down by 1%:
In millions
Unbilled revenue increase (decrease)
Utility margin increase (decrease) (1)
Net income increase (decrease)
(1) Includes impact of regulatory mechanisms including decoupling
mechanism.
—
2013
Up 1%
Down 1%
$
0.6
$
(0.6)
—
—
—
SENATE BILL 408 AND 967. From 2007 through 2010, utility
revenues included the recognition of a regulatory
adjustment for income taxes paid (SB 408). Under Oregon
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.
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
44
hedging (see Note 2, "Derivatives” and "Industry
Regulation") which is either in current income or in
accumulated other comprehensive income (AOCI) under
common stock equity on the balance sheet. Our derivative
contracts outstanding at December 31, 2013 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.
The following table summarizes the amount of gains and
losses realized from commodity price, and currency hedge
transactions for the last three years:
In millions
Net utility loss on:
Commodity
Swaps
Options
Total net loss realized
2013
2012
2011
$
$
(11.0) $
(69.5) $
(53.8)
—
(0.7)
(2.7)
(11.0) $
(70.2) $
(56.5)
Realized losses from commodity hedges shown above were
recorded as increases to cost of gas and were included in
our annual PGA rates.
Pensions and Postretirement Benefits
We maintain a qualified non-contributory defined benefit
pension plan, 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 are not available to employees at any of
our subsidiary companies. 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 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 or AOCL,
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. As such, we received approval from the
OPUC 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 or
AOCL 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. At December 31,
2013, the cumulative amount deferred for future pension
cost recovery was $25.7 million. The regulatory balancing
account includes the recognition of accrued interest on the
account balance at the utility's actual cost of long-term debt.
A number of factors, as discussed above, are considered in
developing pension and postretirement benefit assumptions.
For the December 31, 2013 measurement date, we
reviewed and updated:
•
our weighted-average discount rate assumptions for
pensions went from 3.85% in 2012 to 4.73% in 2013,
and our weighted-average discount rate assumptions
for other postretirement benefits went from 3.56% in
2012 to 4.45% in 2013. The new rate assumptions
were determined for each plan based on a matching of
benchmark interest rates to the estimated cash flows,
which reflect 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 remained unchanged at a
rate of 7.50%; and
other key assumptions, which were based on actual
plan experience and actuarial recommendations.
At December 31, 2013, our net pension liability (benefit
obligations less market value of plan assets) for the
qualified defined benefit plan decreased $59.1 million
compared to 2012. The decrease in our net pension liability
is primarily due to the $41.6 million decrease in our pension
benefit obligation and an increase of $17.5 million in plan
assets. The liability for non-qualified plans decreased $3.2
million, and the liability for other postretirement benefits
decreased $4.4 million in 2013.
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
analyze 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,
2013, the actual annualized returns on plan assets, net of
management fees, for the past one-year, five-years, and 10-
years were 9.8%, 9.6%, and 5.6%, respectively.
We believe our pension assumptions to be appropriate
based on plan design and an assessment of market
conditions. However, the following shows the sensitivity of
our retirement benefit costs and benefit obligations to future
changes in certain actuarial assumptions:
Change in
Assumption
(0.25)%
Impact on
2013
Retirement
Benefit
Costs
Impact on
Retirement
Benefit
Obligations
at Dec. 31,
2013
$
1.0
$
—
—
11.4
0.7
0.7
(0.25)
0.7
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 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. In 2014, we expect to
45
contribute approximately $15 million under the adjusted 24-
month segment rate using MAP-21 corridor.
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, 2013 and 2012, our net long-
term deferred tax liability totaled $486.8 million and $444.4
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, 2013, 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 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, 2013 and 2012, we had regulatory assets representing
differences between book and tax basis related to pre-1981
property of $56.2 million and $60.3 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, 2013, 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
46
and recognized a reduction in state tax expense of $0.2
million. The net effect of these two state tax changes was
negligible.
The Company is currently under IRS examination for tax
years 2009-2011 and we expect resolution in 2014. The
Company is also subject to examination for tax year 2012.
To date, the IRS has not proposed any material
adjustments.
Interest and penalties related to any future income tax
deficiencies would be recorded in income tax expense in
our consolidated statements of income.
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
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 depends
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 actual range of potential liabilities could be
significantly different than estimated 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 $98.1 million as of December 31, 2013.
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. In 2014, a settlement
was reached in our environmental insurance recovery
litigation with remaining insurers. In addition, we have a new
SRRM in Oregon with a proceeding currently open to
resolve implementation issues including the prudence of
deferred costs, the allocation of insurance proceeds, and an
earnings test that would be applied to past and future
deferred costs. As there is uncertainty surrounding this
mechanism and the open proceeding, we will continue to
carefully assess these environmental assets for
recoverability. If it is determined that insurance recoveries
for environmental costs are insufficient 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, Note 15, and
Note 17.
ITEM 7A. QUANTITATIVE AND QUALITATIVE
DISCLOSURES ABOUT MARKET RISK
We are exposed to various forms of market risk including
commodity supply risk, commodity price risk, interest rate
risk, foreign currency risk, credit risk and weather risk. The
following describes our exposure to these risks.
Commodity Supply Risk
We enter into spot, short-term, and long-term natural gas
supply contracts, along with associated pipeline
transportation contracts, to manage our commodity supply
risk. Historically, we have arranged for physical delivery of
an adequate supply of gas, including gas in our Mist storage
facility, to meet expected requirements of our core utility
customers. Our gas purchase contracts are primarily index-
based and subject to monthly re-pricing, a strategy that is
intended to 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 financial swap and option
contracts to convert certain natural gas supply contracts
from floating prices to fixed or capped prices. We also
manage risk 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. If all of the foreign currency forward contracts had
been settled on December 31, 2013, a loss of $0.3 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
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 adequate
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, 2013, our overall credit exposure relating to
commodity 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, 2013, actual
financial swap and option derivative credit risk exposure
totals $5.4 million, which reflects amounts that
counterparties owe to us.
47
The following table summarizes our overall financial swap
and option 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 Gain (Loss)
2013
2012
$
$
— $
4.5
0.9
—
5.4
$
—
(5.0)
—
—
(5.0)
In most cases, we also mitigate the credit risk of financial
derivatives by having master netting arrangements with our
counterparties which provide for making or receiving net
cash settlements. Generally, transactions of the same type
in the same currency that have a settlement on the same
day with a single counterparty are netted and a single
payment is delivered or received depending on which party
is due funds.
Additionally we have master contracts in place with each
of our derivative counterparties that include provisions for
posting or calling for collateral. Generally we can obtain
cash or marketable securities as collateral with one day’s
notice. We use various collateral management strategies to
reduce liquidity risk. The collateral provisions vary by
counterparty but are not expected to result in the significant
posting of collateral, if any. We have performed stress tests
on the portfolio and concluded that the liquidity risk from
collateral calls is not material. Our derivative credit exposure
is primarily with investment grade counterparties rated AA-/
Aa3 or higher. Contracts are diversified across
counterparties to reduce credit and liquidity risk.
CREDIT EXPOSURE TO INSURANCE COMPANIES FOR
ENVIRONMENTAL DAMAGE CLAIMS. We regularly monitor
the financial condition of insurance companies who provide
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 could be material; however, we have
recently settled with remaining insurers for these claims with
payment expected in 2014. See Note 17. 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, 2013,
approximately 8% 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.
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, 2013, 2012, and 2011
Consolidated Balance Sheets at December 31, 2013 and 2012
Consolidated Statements of Shareholders' Equity for the Years Ended December 31, 2013, 2012, and 2011
Consolidated Statements of Cash Flows for the Years Ended December 31, 2013, 2012, and 2011
Notes to Consolidated Financial Statements
Quarterly Financial Information (Unaudited)
Supplementary Data for the Years Ended December 31, 2013, 2012, and 2011:
Financial Statement Schedule
Schedule II - Valuation and Qualifying Accounts and Reserves
Supplemental Schedules Omitted
Page
50
51
52
53
55
56
57
86
86
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, 2013. 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 (1992).
Based on our assessment and those criteria, management has concluded that we maintained effective internal control over
financial reporting as of December 31, 2013.
The effectiveness of internal control over financial reporting as of December 31, 2013 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
February 28, 2014
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, 2013 and 2012, and the
results of their operations and their cash flows for each of the three years in the period ended December 31, 2013 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, 2013, based on criteria established in
Internal Control - Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway
Commission (COSO). The Company's management is responsible for these financial statements and financial statement
schedule, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal
control over financial reporting, included in the accompanying Management's Report on Internal Control over Financial
Reporting. Our responsibility is to express opinions on these financial statements, on the financial statement schedule, and on
the Company's internal control over financial reporting based on our integrated audits. We conducted our audits in accordance
with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan
and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement
and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial
statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements,
assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial
statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal
control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and
operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other
procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our
opinions.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the
reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally
accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that
(i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions
of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit
preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and
expenditures of the company are being made only in accordance with authorizations of management and directors of the
company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or
disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also,
projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate
because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ PricewaterhouseCoopers LLP
Portland, Oregon
February 28, 2014
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 ($1,304) for 2013,
$1,339 for 2012, and $1,161 for 2011
Amortization of non-qualified employee benefit plan liability, net of taxes of ($608)
for 2013, ($434) for 2012, and ($383) for 2011
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,
2013
2012
2011
$ 758,518
$ 730,607
$ 828,055
373,298
136,613
29,956
75,905
615,772
142,746
4,669
45,172
355,335
129,477
30,598
73,017
588,427
142,180
3,159
43,157
458,508
125,417
29,281
70,004
683,210
144,845
3,112
42,088
102,243
102,182
105,869
41,705
60,538
43,403
58,779
42,825
63,044
1,998
(2,156)
(1,779)
935
665
583
$
63,471
$
57,288
$
61,848
26,974
27,027
26,831
26,907
26,687
26,744
$
$
2.24
2.24
1.83
$
2.19
2.18
1.79
2.36
2.36
1.75
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
Deferred tax assets
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,
2013
2012
$
9,471
$
81,889
61,527
(1,656)
22,635
5,311
60,669
20,646
3,534
45,241
21,181
330,448
8,923
61,229
56,955
(2,518)
52,448
1,950
67,602
14,966
2,552
—
19,592
283,699
2,918,739
2,786,008
855,865
812,396
2,062,874
1,973,612
121,998
369,603
1,880
67,851
4,000
12,257
84,693
382,255
3,639
67,667
4,000
13,555
2,640,463
2,529,421
$
2,970,911
$
2,813,120
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 27,075
and 26,917 at December 31, 2013 and 2012, respectively
Retained earnings
Accumulated other comprehensive loss
Total equity
Total liabilities and equity
See Notes to Consolidated Financial Statements
As of December 31,
2013
2012
$
188,200
$
190,250
60,000
96,126
10,856
7,103
28,335
1,891
40,280
432,791
681,700
532,036
303,485
149,354
615
119,058
—
85,613
9,588
5,953
20,792
10,796
45,444
368,436
691,700
444,377
288,113
215,792
578
74,497
1,104,548
1,023,357
—
—
364,549
393,681
(6,358)
751,872
356,571
382,347
(9,291)
729,627
$
2,970,911
$
2,813,120
54
NORTHWEST NATURAL GAS COMPANY
CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY
In thousands
Balance at Dec. 31, 2010
Comprehensive income (loss)
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 (loss)
Dividends paid on common stock
Tax expense from employee stock option plan
Stock-based compensation
Issuance of common stock
Balance at Dec. 31, 2012
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, 2013
Common
Stock
Retained
Earnings
Accumulated
Other
Comprehensive
Income (Loss)
Total
Equity
$
342,978
$
355,251
$
(6,604) $
691,625
—
—
(26)
1,769
3,632
30
348,383
—
—
(149)
1,291
7,046
356,571
—
—
(242)
2,169
6,051
63,044
(46,690)
—
—
—
(30)
371,575
58,779
(48,007)
—
—
—
382,347
60,538
(49,204)
—
—
—
(1,196)
—
—
—
—
—
(7,800)
(1,491)
—
—
—
—
(9,291)
2,933
—
—
—
—
61,848
(46,690)
(26)
1,769
3,632
—
712,158
57,288
(48,007)
(149)
1,291
7,046
729,627
63,471
(49,204)
(242)
2,169
6,051
$
364,549
$
393,681
$
(6,358) $
751,872
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
Regulatory amortization of gas reserves
Deferred tax liabilities, net
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
Proceeds from sale of assets
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 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
See Notes to Consolidated Financial Statements
56
Year Ended December 31,
2013
2012
2011
$ 60,538
$ 58,779
$ 63,044
75,905
11,089
46,483
5,666
73,017
6,340
42,079
5,448
70,004
1,143
46,319
7,191
(11,700)
(23,500)
(22,045)
(16,679)
(12,503)
25,586
(2,580)
(2,350)
(863)
(26,094)
22,170
(6,246)
6,933
286
7,422
1,150
6,761
3,334
(602)
96
(5,245)
(17,644)
23,216
7,413
6,022
34,189
148
675
8,565
(270)
176,390
168,838
233,462
(138,924)
(132,029)
(100,534)
(54,077)
(54,085)
(50,597)
8,638
—
2,231
—
—
1,437
—
(3,076)
1,142
(182,132)
(184,677)
(153,065)
5,964
50,000
6,758
50,000
3,040
90,000
—
(40,000)
(10,000)
(2,050)
48,650
(115,835)
(49,204)
(48,007)
(46,690)
1,580
6,290
548
8,923
1,528
18,929
3,090
5,833
$
9,471
$
8,923
$
1,464
(78,021)
2,376
3,457
5,833
$ 44,022
$ 43,061
$ 41,413
870
2,979
1,756
NORTHWEST NATURAL GAS
COMPANY
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS
1. ORGANIZATION AND PRINCIPLES OF
CONSOLIDATION
The accompanying consolidated financial statements
represent the consolidated results 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. We have two core businesses: our
regulated local gas distribution business, referred to as the
utility segment, which serves residential, commercial, and
industrial customers in Oregon and southwest Washington;
and our gas storage businesses, referred to as the gas
storage segment, which provides storage services for
utilities, gas marketers, electric generators, and large
industrial users from storage facilities located in Oregon and
California. In addition, we have investments and other non-
utility activities that we aggregate and report as other.
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), NNG Financial Corporation (NNG Financial),
Northwest Energy Corporation (Energy Corp), and NW
Natural Gas Reserves, LLC (NWN Gas Reserves).
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, which includes NWN Energy’s investment in
Palomar Gas Holdings, LLC (PGH) and NNG Financial's
investment in Kelso-Beaver (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
businesses and other non-utility investments and business
activities.
During the first quarter of 2013, we identified an error in the
rate used to calculate interest on regulatory assets. We
assessed the materiality of this error on prior period
financial statements and concluded it was not material to
any prior annual or interim periods; however, the cumulative
impact would have been material to the annual and interim
periods for 2013, if corrected in 2013. As a result, in
accordance with accounting standards, we have revised our
prior period financial statements as shown in Note 16 to
correct this error.
57
Certain prior year balances in our consolidated financial
statements and notes have been reclassified to conform
with the current presentation. These reclassifications 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.
Industry Regulation
Our principal businesses are the distribution of natural gas,
which is regulated by the OPUC and WUTC, and natural gas
storage services, which are regulated by either the FERC or
the 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.
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 recorded. 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 costs incurred and deferred at December 31,
2013 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 in the period such determination is
made.
New Accounting Standards
Recently Adopted Standards
BALANCE SHEET OFFSETTING. In December 2011, the
Financial Accounting Standards Board (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 was effective for annual reporting periods
beginning on or after January 1, 2013. The adoption of this
standard did not have a material effect on our financial
statement disclosures. See Note 13.
RECLASSIFICATIONS FROM ACCUMULATED OTHER
COMPREHENSIVE INCOME. In February 2013, the FASB
issued authoritative guidance, which requires an entity to
present significant amounts reclassified from each
component of accumulated other comprehensive income
(AOCI). This standard is intended to improve the reporting of
these reclassifications by presenting the information
concerning amounts reclassified into net income from AOCI
in a single location. This information has historically has
been presented throughout the financial statements. This
guidance was effective for reporting periods beginning after
December 15, 2012. The adoption of this standard did not
have a material effect on our financial statement disclosures.
See Note 8.
At December 31, the amounts deferred as regulatory assets
and liabilities were as follows:
In thousands
Current:
Unrealized loss on derivatives(1)
Other(2)
Total current
Non-current:
Unrealized loss on derivatives(1)
Pension balancing(3)
Income tax asset
Pension and other postretirement
benefit liabilities(3)
Environmental costs(4)
Other(2)
Regulatory Assets
2013
2012
$
1,891
$ 10,796
20,744
41,652
$ 22,635
$ 52,448
$
615
$
578
25,713
51,814
14,727
55,879
125,855
182,688
148,389
121,144
17,217
7,239
Total non-current
$ 369,603
$ 382,255
In thousands
Current:
Gas costs
Unrealized gain on derivatives(1)
Other(2)
Total current
Non-current:
Gas costs
Unrealized gain on derivatives(1)
Accrued asset removal costs
Other(2)
Regulatory Liabilities
2013
2012
$
7,510
$
9,100
5,290
15,535
1,950
9,742
$ 28,335
$ 20,792
$
2,172
$
—
1,880
3,639
296,294
281,213
3,139
3,261
Total non-current
$ 303,485
$ 288,113
(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 PGA mechanism when realized at
settlement.
(2) 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.
(3) Certain utility pension costs 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. See
Note 8.
(4) Environmental costs relate to specific sites approved for
regulatory deferral by the OPUC and WUTC. In Oregon, we
earn a carrying charge on amounts paid, whereas amounts
accrued but not yet paid do not earn a carrying charge until
expended. In Washington, a carrying charge related to deferred
amounts will be determined in a future proceeding. For further
information on environmental matters, see Note 15.
58
Recently Issued Accounting Pronouncements
OBLIGATIONS RESULTING FROM JOINT AND SEVERAL
LIABILITY ARRANGEMENTS. In February 2013, the FASB
issued guidance regarding the recognition, measurement
and disclosure of obligations resulting from joint and several
liability arrangements for which the total amount of the
obligation is fixed at the reporting date. Under the new
guidance, an entity is required to measure fixed obligations
as the sum of the amount the reporting entity agreed to pay
on the basis of its arrangement among its co-obligors plus
any additional amount the reporting entity expects to pay on
behalf of its co-obligors. In addition, an entity must disclose
the nature and amount of the obligation as well as other
information about the obligations. The guidance is effective
for fiscal years, and interim periods within those years,
beginning after December 15, 2013. We are currently
assessing the impact, if any, of this guidance on our financial
position, results of operations, or disclosures.
PRESENTATION OF UNRECOGNIZED TAX BENEFIT. In July
2013, the FASB issued guidance that requires an
unrecognized tax benefit, or a portion of an unrecognized tax
benefit, be presented in the financial statements as a
reduction to a deferred tax asset for a net operating loss
carryforward, a similar tax loss, or a tax credit carryforward,
except under certain circumstances. The new guidance is
effective for fiscal years and interim periods within those
years, beginning after December 15, 2013. This guidance is
not expected to have an impact on our financial position,
results of operations, and disclosures.
Accounting Policies
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.
In accordance with long-standing regulatory treatment, our
depreciation rates consist 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.
59
The costs of utility plant retired or otherwise disposed of are
removed from utility plant and charged to accumulated
depreciation for recovery or refund through future rates.
Gains from the sale of regulated assets are generally
deferred and refunded to customers. For non-utility assets,
we record a gain or loss upon the disposal of the property
that is recorded in other income and expense, net in the
consolidated statements of comprehensive income.
Our provision for depreciation of utility property, plant and
equipment is recorded under the group method on a straight-
line basis with rates computed in accordance with
depreciation studies approved by regulatory authorities. The
weighted average depreciation rate for utility assets in
service was approximately 2.8% in 2013, 2012, and 2011,
reflecting the approximate weighted average economic life of
the property. This includes 2013 weighted average
depreciation rates for the following asset categories: 2.7%
for transmission and distribution plant, 2.2% for gas storage
facilities, 4.3% for general plant, and 4.1% for intangible and
other fixed assets.
AFUDC. 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 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 2013 and 2012, and 0.5% in 2011.
IMPAIRMENT OF LONG-LIVED ASSETS. We review the
carrying value of long-lived assets whenever events or
changes in circumstances indicate that the carrying amount
of the assets might not be recoverable. Factors that would
necessitate an impairment assessment of long-lived assets
include a significant adverse change in the extent or manner
in which the asset is used, a significant adverse change in
legal factors or business climate that could affect the value of
the asset, or a significant decline in the observable market
value or expected future cash flows of the asset, among
others.
If such factors indicate a potential impairment, we assess the
recoverability by determining if the carrying value of the
asset exceeds the sum of the projected future cash flows
over the remaining economic life of the asset. An asset is
determined to be impaired when the carrying value is not
recoverable through undiscounted future cash flows, and in
those cases, we would estimate the fair value of the asset
using appropriate valuation methodologies, which may
include an estimate of discounted cash flows. Any
impairment would be measured as the difference between
the asset’s carrying amount and its estimated fair value.
While we determined there were no material impairments of
long-lived assets during the year ended December 31, 2013,
if our gas storage facilities experience sustained decreases
in future cash flows due to a prolonged, slow recovery of the
gas storage market, future assessments could result in an
impairment.
Cash and Cash Equivalents
For purposes of reporting cash flows, cash and cash
equivalents include cash on hand plus highly liquid
investment accounts with original maturity dates of three
months or less. At December 31, 2013 and 2012,
outstanding checks of approximately $2.8 million and $2.3
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, 2013 and 2012 was $61.5 million and $57.0
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.
In 2011, SB 408 was repealed and replaced by Senate Bill
SB 967. SB 967 required utilities to eliminate amounts
accrued under SB 408, which resulted in a one-time pre-tax
charge of $7.4 million in 2011.
Non-utility revenues are derived primarily from the gas
storage segment. At our Mist underground storage facility,
revenues are recognized upon delivery of services to
customers. At our Gill Ranch facility, 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. In
addition, we also have asset management service revenue
primarily from an independent energy marketing company
that optimizes commodity and pipeline capacity release
transactions. Under this agreement, guaranteed asset
management revenue is recognized using a straight-line,
pro-rata methodology over the term of each contract.
Revenues earned above the guaranteed amount are
recognized as they are earned. See Note 4.
Revenue Taxes
Revenue-based taxes are primarily franchise taxes, which
are collected from customers and remitted to taxing
authorities. Revenue taxes are included in operating
revenues in the statement of comprehensive income.
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
60
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 recorded 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 creditworthiness 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, consist primarily
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 not
included in our inventory balances. It is recorded at original
cost and classified as a long-term plant asset.
Material and supplies inventories consist of both utility and
non-utility inventories and are stated at the lower of average
cost or net realizable value.
Our utility and gas storage inventories totaled $51.4 million
and $58.8 million at December 31, 2013 and 2012,
respectively. At December 31, 2013 and 2012, our materials
and supplies inventories totaled $9.3 million and $8.8 million,
respectively.
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 calculated using the estimated
gas reserves and the estimated 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
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.
Income Tax Expense
NW Natural and its wholly-owned subsidiaries file
consolidated federal, state, and local income tax returns.
Income taxes are currently 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 $56.2 million and $60.3 million at
December 31, 2013 and 2012, 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
financial statement 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.
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. Our financial derivatives generally qualify for
deferral under regulatory accounting. The Company’s index-
priced physical derivative contracts also qualify for regulatory
deferral accounting treatment.
Derivative contracts entered into for utility requirements after
the annual PGA rate has been set and that PGA year has
begun are subject to the PGA incentive sharing mechanism.
In Oregon we participate in a PGA sharing mechanism under
which we are required to select either an 80% 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, 2013, 2012 and 2011, we selected a 90%
deferral of gas cost differences. In Washington, 100% of the
differences between the PGA prices and actual gas costs 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 without 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 determined necessary
to support normal business activities. We do not enter into
derivative instruments for trading purposes.
Fair Value
In accordance with fair value accounting, we use the
following fair value hierarchy for determining inputs for our
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.
61
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. 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.
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. It is our policy to
accrue the full amount of such liability when information is
sufficient to reasonably estimate the amount of probable
3. EARNINGS PER SHARE
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.
Subsequent Events
See Note 17 for information regarding the Company's
environmental insurance settlements.
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:
2013
2012
2011
$
60,538
$
58,779
$
26,974
53
27,027
26,831
76
26,907
$
$
2.24
2.24
$
$
2.19
2.18
$
$
63,044
26,687
57
26,744
2.36
2.36
Antidilutive shares not included in net income per diluted common share calculation
26
1
2
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
segment and other as non-utility. Our utility segment also
includes NWN Gas Reserves, which is a wholly-owned
subsidiary of Energy Corp, and the utility portion of Mist.
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 Mist, and all third-party
asset management services. Other includes NNG Financial
and NWN Energy's equity investment in PGH, which is
pursuing development of a cross-Cascades 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
around 60% of our utility’s total volumes delivered and 90%
of our utility’s margin. Industrial customers largely account
for the remaining volumes and utility margin. A small
amount of utility margin is also derived from miscellaneous
services, gains or losses from an incentive gas cost sharing
mechanism and other service fees.
Industrial sectors 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
62
publishing; nurseries; government and educational
institutions; and electric generation. No individual customer
or industry group accounts for over 10% of our utility
revenues or utility margins.
Gas Storage
Our gas storage segment includes natural gas storage
services provided to customers primarily from two
underground natural gas storage facilities, our Gill Ranch
gas storage facility, and the non-utility portion of our Mist
gas storage facility. In addition to earning revenue from
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,
2013, 2012 and 2011, this business segment derived a
majority of its revenues from firm and interruptible gas
storage contracts and from asset management services.
Mist Gas Storage Facility
Earnings from non-utility assets at our Mist facility in
Oregon are primarily related to firm storage capacity
revenues. Earnings for the gas storage segment also
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. Although this is a jointly owned
property, each owner is independently responsible for
financing its share of the Gill Ranch natural gas storage
facility.
Other
We have immaterial non-utility investments and other
business activities which are aggregated and reported as
other. Other 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. Other 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 $1.2 million and $1.1 million at December
31, 2013 and 2012, respectively.
63
Segment Information Summary
The following table presents summary financial information concerning the reportable segments. Inter-segment transactions are
insignificant.
In thousands
2013
Utility
Gas Storage
Other
Total
Operating revenues
$
727,182
$
31,112
$
224
$
Depreciation and amortization
Income from operations
Net income
Capital expenditures
Total assets at December 31, 2013
2012
69,420
128,066
54,920
137,466
2,644,367
6,485
14,669
5,569
1,458
310,097
Depreciation and amortization
Income from operations
Net income
Capital expenditures
Total assets at December 31, 2012
2011
66,545
128,854
54,049
130,151
2,505,655
6,472
13,226
4,521
1,541
291,568
Operating revenues
$
699,862
$
30,520
$
225
$
16,447
2,970,911
—
11
49
—
—
100
209
337
758,518
75,905
142,746
60,538
138,924
730,607
73,017
142,180
58,779
132,029
15,897
2,813,120
Operating revenues
$
801,478
$
26,354
$
223
$
Depreciation and amortization
Income from operations
Net income (loss)
Capital expenditures
63,843
135,722
59,673
94,049
6,161
9,090
4,101
6,485
—
33
(730)
—
828,055
70,004
144,845
63,044
100,534
Utility Margin
Utility margin is a financial measure consisting of utility operating revenues less revenue taxes and the associated cost of gas.
Cost of gas purchased for utility customers is generally a pass-through cost in the amount of revenues billed to regulated utility
customers. By netting costs of gas from utility operating revenues, utility margin provides a key metric used by our chief
operating decision maker in assessing the performance of the utility segment. The following table presents additional segment
information concerning utility margin. The gas storage and other segments emphasize growth in operating revenues and net
income as opposed to margin because these segments do not incur commodity cost of sales like the utility and, therefore, use
operating revenues and net income to assess performance.
In thousands
Utility margin calculation:
Utility operating revenues
Less: Utility cost of gas
Utility margin
2013
2012
2011
$
$
727,182
$
699,862
$
373,298
355,335
353,884
$
344,527
$
801,478
458,508
342,970
64
5. COMMON STOCK
6. STOCK-BASED COMPENSATION
Common Stock
As of December 31, 2013 and 2012, we had 100 million
shares of common stock authorized. As of December 31,
2013, we had reserved 122,184 shares for issuance of
common stock under the Employee Stock Purchase Plan
(ESPP) and 96,991 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 492,150 options outstanding at December 31,
2013, 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 2014 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, 2013. 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:
In thousands
Balance, December 31, 2010
Sales to employees under ESPP
Stock-based compensation
Sales to shareholders under DRPP
Balance, December 31, 2011
Sales to employees under ESPP
Stock-based compensation
Sales to shareholders under DRPP
Balance, December 31, 2012
Sales to employees under ESPP
Stock-based compensation
Sales to shareholders under DRPP
Balance, December 31, 2013
Shares
26,668
15
24
49
26,756
18
47
96
26,917
16
42
100
27,075
65
Our stock-based compensation plans are designed to
promote stock ownership in NW Natural by employees and
officers. These 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 2012.
Long-Term Incentive Plan
The LTIP is intended to provide a flexible, competitive
compensation program for eligible officers and key
employees. Under the 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 850,000 shares were
authorized for issuance as of December 31, 2013. Shares
awarded under the LTIP may be purchased on the open
market or issued as new shares.
Of the 850,000 shares of common stock authorized for LTIP
awards at December 31, 2013, there were 241,169 shares
available for issuance under any type of award. This
assumes that market, performance, and service based
grants currently outstanding are awarded at the target level.
Additionally, 250,000 shares of common stock were
available for option grants at December 31, 2013. There
were no outstanding grants of restricted stock or stock
options under the LTIP at December 31, 2013 or 2012. 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 of 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 with three-year
performance periods. The following table summarizes
performance share expense information:
Expense in millions
Estimated award:
2011-2013 grant(2)
Actual award:
Shares (1)
Expense
During Award
Year(3)
Total
Expense
for Award
9,516
$
0.4
$
1.0
2010-2012 grant
9,924
0.5
1.2
0.4
2009-2011 grant
0.8
8,428
(1) In addition to common stock shares, a participant also receives 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.
(2) This represents the estimated number of shares to be awarded
as of December 31, 2013 as certain performance share measures
had been achieved. Amounts are subject to change with final
payout amounts authorized by the Board of Directors in February
2014.
(3)Amount represents the expense recognized in the third year of the
vesting period noted above.
The aggregate number of performance shares granted and outstanding at the target and maximum levels were as follows:
Dollars in thousands
Performance Period
Performance Share Awards Outstanding
Target
Maximum
2013
Expense
Cumulative Expense
December 31, 2013
2011-13
2012-14
2013-15
Total
37,950
35,340
37,300
110,590
75,900
$
390
$
70,680
74,600
221,180
$
603
486
1,479
960
1,238
486
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-based compensation and calculated
based on performance levels achieved and an estimated fair
value using the Monte-Carlo method. The weighted-average
grant date fair value of unvested shares at December 31,
2013 and 2012 was $43.39 and $51.42 per share,
respectively. The weighted-average grant date fair value of
shares vested during the year was $30.86 per share and for
shares granted during the year was $38.96 per share. As of
December 31, 2013, there was $1.6 million of unrecognized
compensation cost related to the unvested portion of
performance awards expected to be recognized through
2015.
Restricted Stock Units
In 2012, the Company began granting RSUs under the LTIP
instead of stock options under the Restated SOP. The
majority of RSUs include a performance-based threshold
and generally have 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. The fair value of the RSU is equal to the closing
market price of the Company's common stock on the grant
date.
Information regarding the RSU activity is summarized as
follows:
Number
of
RSUs
Weighted -
Average
Price Per
RSU
Nonvested, Dec. 31, 2011
— $
Granted
Vested
Forfeited
Nonvested, Dec. 31, 2012
Granted
Vested
Forfeited
Nonvested, Dec. 31, 2013
25,224
—
(360)
24,864
25,748
(5,455)
(590)
44,567
—
47.58
—
48.00
47.57
45.38
48.01
46.58
46.27
66
As of December 31, 2013, there was $1.5 million of
unrecognized compensation cost from grants of RSUs,
which is expected to be recognized over a period extending
through 2017.
Restated Stock Option Plan
The Restated SOP was terminated for new option grants in
2012; however, options that had been granted before the
plan 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. We did not
grant new stock options during 2012 or 2013.
At December 31, 2013, a total of 492,150 shares of
common stock remained reserved for issuance under the
Restated SOP. As the plan is closed, there are no additional
shares 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.
The fair value of each stock option is estimated on the grant
date using the Black-Scholes option pricing model with the
following weighted average assumptions and outcomes:
Risk-free interest rate
Expected life (in years)
Expected market price volatility factor
Expected dividend yield
Forfeiture rate
2011
2.0%
4.5
24.5%
3.8%
3.1%
Weighted average grant date fair value
$ 6.73
The expected life of our grants was calculated based on our
actual experience with previously exercised option
grants. The risk-free interest rate was based on the implied
yield currently available on U.S. Treasury zero-coupon
issues with a life equal to the expected life of the
options. Historical data was used to estimate the volatility
factor, measured on a daily basis, for a period equal to the
duration of the expected life of the option awards. The
dividend yield was based on management’s current
estimate for future dividend payouts at the time of grant. We
expense the total cost of stock option awards granted to
retirement eligible employees at the date of grant in
accordance with stock option accounting guidance and the
retirement vesting provisions of our option agreements.
Information regarding the Restated SOP activity is
summarized as follows:
7. DEBT
Weighted -
Average
Price Per
Share
Intrinsic
Value
(In millions)
Option
Shares
Balance outstanding,
Dec. 31, 2010
490,460
$
40.82
$
Granted
Exercised
Forfeited
Balance outstanding,
Dec. 31, 2011
Exercised
Forfeited
Balance outstanding,
Dec. 31, 2012
Exercised
Forfeited
Balance outstanding,
Dec. 31, 2013
Exercisable,
Dec. 31, 2013
122,700
(24,185)
(9,750)
579,225
(46,825)
(2,475)
529,925
(33,800)
(3,975)
45.74
33.88
44.38
42.09
40.62
43.78
42.22
32.16
43.72
492,150
42.89
409,036
42.41
2.8
n/a
0.3
n/a
3.4
0.4
n/a
1.3
0.3
n/a
0.6
0.6
During 2013, cash of $1.1 million was received for option
shares exercised and $0.2 million related tax benefit was
realized. During 2013, 2012, and 2011, the total fair value of
options that vested was $0.5 million, $0.6 million and $0.6
million, respectively. The weighted average remaining life of
options exercisable and outstanding at December 31, 2013,
was 4.8 years and 5.1 years, respectively. As of December
31, 2013, there was $0.2 million of unrecognized
compensation cost related to the unvested portion of
outstanding stock option awards expected to be recognized
during 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 $21,236 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
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
2013
2012
2011
Operations and maintenance
expense, for stock-based
compensation
$ 1,876 $ 1,668 $ 1,477
Income tax benefit
(765)
(707)
(597)
Net stock-based compensation
effect on net income
$ 1,111 $
961 $
880
Amounts capitalized for stock-based
compensation
$
331 $
294 $
261
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, 2013 and 2012, the amounts of
commercial paper debt outstanding were $188.2 million and
$190.3 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,
2013, our commercial paper had a maximum maturity of 136
days and an average maturity of 66 days. There were no
bank loans outstanding at December 31, 2013 or 2012.
On December 20, 2012, NW Natural entered into a five-year
$300 million credit agreement, pursuant to which we may
extend commitments for two additional one-year periods
subject to lender approval. In December 2013, we extended
our commitment for an additional year with an updated
maturity date of December 20, 2018. 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. There were no outstanding
balances under the agreement and no letters of credit
issued or outstanding at December 31, 2013 and 2012.
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,
2013 and 2012.
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.
67
First Mortgage Bonds
NW Natural issued $50 million of FMBs on August 19, 2013
with a coupon rate of 3.542% and a 10-year maturity. In
October 2012, the utility issued $50 million of FMBs with a
coupon rate of 4.00% and a maturity date of October 31,
2042.
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, 2013, 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, 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,
2013.
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
December 31,
2013
2012
Carrying amount
$
741,700
$
Estimated fair value
806,359
691,700
834,664
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, 2018 are as follows:
In thousands
Year
2014
2015
2016
2017
2018
$
60,000
40,000
65,000
40,000
22,000
The following table presents our debt outstanding as of
December 31:
In thousands
First Mortgage Bonds
2013
2012
8.26 % Series B due 2014
$
10,000
$
10,000
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
3.542% Series B due 2023
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
50,000
40,000
25,000
40,000
22,000
10,000
20,000
75,000
10,000
50,000
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
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
Subsidiary Senior Secured Debt
Gill Ranch debt due 2016
701,700
651,700
40,000
40,000
741,700
691,700
Less: Current maturities of long-term
debt
Total long-term debt
60,000
—
$ 681,700
$ 691,700
68
8. PENSION AND OTHER POSTRETIREMENT BENEFIT COSTS
We maintain qualified non-contributory defined benefit pension plans, 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 into one plan. 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, and a summary of the funded
status and amounts recognized in the consolidated balance sheets as of December 31:
In thousands
Reconciliation of change in benefit obligation:
Obligation at January 1
Service cost
Interest cost
Net actuarial (gain) 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
2013
2012
2013
2012
$
435,889
$
391,127
$
33,119
$
30,049
8,698
16,400
(51,043)
(18,855)
8,047
17,295
37,615
(18,195)
656
1,157
(4,283)
(1,895)
592
1,267
3,182
(1,971)
$
391,089
$
435,889
$
28,754
$
33,119
$
249,603
$
215,970
$
22,872
13,442
26,683
25,145
(18,855)
(18,195)
— $
—
1,895
(1,895)
267,062
$
249,603
$
— $
—
—
1,971
(1,971)
—
(124,027) $
(186,286) $
(28,754) $
(33,119)
$
$
Our qualified defined benefit pension plan has an aggregate benefit obligation of $362.4 million and $404.0 million at December
31, 2013 and 2012, respectively, and fair values of plan assets of $267.1 million and $249.6 million, respectively.
The following table presents amounts realized through regulatory assets or in other comprehensive income for the years ended
December 31:
Regulatory Assets
Other Comprehensive Income
Pension Benefits
Other Postretirement Benefits
Pension Benefits
In thousands
2013
2012
2011
2013
2012
2011
2013
2012
2011
Net actuarial (gain) loss
$ (51,892) $ 26,504
$ 66,404
$ (4,283) $
3,182
$
2,225
$ (3,302) $
3,511
$
2,948
Amortization of:
Transition obligation
Prior service cost
Actuarial loss
—
(230)
—
(230)
—
(230)
(16,744)
(14,482)
(10,731)
—
(197)
(733)
(411)
(197)
(435)
(411)
(197)
(289)
—
7
—
35
(1,550)
(1,150)
—
(122)
(854)
Total
$ (68,866) $ 11,792
$ 55,443
$ (5,213) $
2,139
$
1,328
$ (4,845) $
2,396
$
1,972
69
The following table presents amounts recognized in regulatory assets and accumulated other comprehensive loss (AOCL) at
December 31:
In thousands
Prior service cost
Net actuarial loss
Total
Regulatory Assets
AOCL
Pension Benefits
Other Postretirement Benefits
Pension Benefits
2013
2012
2013
2012
2013
2012
$
$
867
$
1,097
$
685
$
882
$
(5) $
(12)
119,638
188,278
4,665
9,681
10,475
120,505
$
189,375
$
5,350
$
10,563
$
10,470
$
15,327
15,315
The following table presents amounts recognized in AOCL and the changes in AOCL related to our non-qualified employee
benefit plans:
In thousands
Beginning balance
Amounts reclassified to AOCL
Amounts reclassified from AOCL:
Amortization of prior service costs
Amortization of actuarial losses
Total reclassifications before tax
Tax (benefit) expense
Total reclassifications for the period
Ending balance
In 2014, an estimated $9.8 million will be amortized from
regulatory assets to net periodic benefit costs, consisting of
$9.4 million of actuarial losses, and $0.4 million of prior
service costs. A total of $1.0 million will be amortized from
AOCL 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
Year Ended December 31,
2013
2012
(9,291) $
3,302
(7)
1,550
4,845
(1,912)
2,933
(6,358) $
(7,800)
(3,495)
(35)
1,134
(2,396)
905
(1,491)
(9,291)
$
$
convertible securities, absolute and real return strategies,
real estate, and investments in NW Natural securities. 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.
The following is our pension plan asset target allocation at
December 31, 2013:
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 bonds
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 $28.7 million and $31.9 million at
December 31, 2013 and 2012, respectively. These plans
are not subject to regulatory deferral, and the changes in
70
actuarial gains and losses, prior service costs and transition
assets or obligations are recognized in AOCL, 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 and other assets.
Our other postretirement benefit plans 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 are recognized as a regulatory
asset. Net periodic benefit costs consist of service costs,
interest costs, and the amortization of actuarial gains and
losses.
Net periodic benefit costs consist of service costs, interest
costs, and 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.
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 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
2013
2012
2011
2013
2012
2011
$
8,698
$
8,047
$
7,122
$
656
$
592
$
16,400
(18,721)
—
223
18,294
24,894
(6,712)
(9,115)
17,295
18,134
1,157
1,267
(19,082)
(17,867)
—
195
15,631
22,086
(5,820)
(7,876)
—
352
11,584
19,325
(4,905)
(6,008)
—
—
197
734
2,744
(856)
—
—
411
197
435
2,902
(882)
—
614
1,404
—
411
197
289
2,915
(878)
—
Net amount charged to expense
$
9,067
$
8,390
$
8,412
$
1,888
$
2,020
$
2,037
(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
2013
2012
2011
2013
2012
2011
Assumptions for net periodic benefit cost:
Weighted-average discount rate
3.84%
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
Assumptions for year-end funded status:
Weighted-average discount rate
4.73%
3.85%
4.51%
4.45%
3.56%
4.33%
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%
7.50%
8.00%
n/a
n/a
n/a
n/a
n/a
n/a
The assumed annual increase in health care cost trend
rates used in measuring other postretirement benefits as of
December 31, 2013 was 9.0% for pre-65 and 7.9% for
post-65 populations. These trend rates apply to both
medical and prescription drugs. Medical costs and
prescription drugs are assumed to decrease gradually each
year to a rate of 5.0% by 2021.
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
$
73
$
(64)
739
(660)
71
The impact of a change in retirement benefit costs on
operating results would be less than the amounts shown
above because a portion would be capitalized to utility plant,
and a certain amount would be recorded to the regulatory
balancing account with the remaining amount recognized in
current earnings.
The following table provides information regarding employer
contributions and benefit payments for the qualified pension
plan, non-qualified pension plans and other postretirement
benefit plans for the years ended December 31, and
estimated future contributions and payments:
In thousands
Pension Benefits
Other Benefits
$
25,559
$
Employer Contributions:
2012
2013
2014 (estimated)
Benefit Payments:
2011
2012
2013
Estimated Future Benefit Payments:
2014
2015
2016
2017
2018
13,907
15,607
18,269
18,195
18,855
19,450
20,033
20,671
21,424
22,337
1,971
1,895
1,892
1,870
1,971
1,895
1,892
1,927
2,001
2,053
2,112
2019-2023
129,177
10,823
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) legislation
changed 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 plan is
currently underfunded by $95.3 million at December 31,
2013. Including the impacts of MAP-21, we expect to make
contributions during 2014 of approximately $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
72
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
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 $0.5 million in 2013
and $0.4 million in 2012, and 2011, which is approximately
4% to 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 could
withdraw from the Western States Plan at any time.
Effective December 22, 2013, we withdrew from the plan,
which was a noncash transaction. Vested participants will
receive all benefits accrued through the date of withdrawal.
As the plan was underfunded at the time of withdrawal, we
have been assessed a withdrawal liability of $8.3 million,
which requires NW Natural to pay $0.6 million each year to
the plan for the next 20 years. We have deferred the
withdrawal liability to a regulatory account on the balance
sheet.
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 2013 and 2012, and $2.4
million in 2011. 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
readily determinable fair value, including a published net
asset value (NAV). The level 2 assets consist of mutual
funds where NAV is not 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 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 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 MARKETS EQUITY. These are level 1 assets
representing a mutual fund with readily determinable fair
value, including published NAV's. 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 published, but the
investment can be readily disposed of at NAV. 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 readily determinable fair value, including a
published 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 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 readily determinable fair
value, including a published 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 readily determinable fair value,
including a published 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
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.
REAL RETURN STRATEGY. These are level 1 assets
representing a mutual fund with a readily determinable fair
value, including a published NAV. This asset class includes
an investment in a broad range of assets primarily including
fixed income, high-yield bonds, and emerging market debt.
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 NAV 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.
73
The following table presents the fair value of plan assets, including outstanding receivables and liabilities, of the retirement trust
fund:
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
High yield bonds
Emerging market debt
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, 2013
Level 1
Level 2
Level 3
Total
$
39,124
$
30,465
16,782
7,405
—
33,152
—
9,987
16,559
—
13,031
—
$
79
55
17,202
—
367
32,763
12,890
—
—
35,339
—
1,418
— $
—
—
—
—
—
—
—
—
—
—
—
39,203
30,520
33,984
7,405
367
65,915
12,890
9,987
16,559
35,339
13,031
1,418
$
166,505
$
100,113
$
— $
266,618
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,
2013
2012
$
468
$
1,154
$
1,622
$
388
4,459
4,847
$
$
1,178
267,062
$
$
935
249,603
74
9. INCOME TAX
The following table provides a reconciliation between
income taxes calculated at the statutory federal tax rate and
the provision for income taxes reflected in the consolidated
statements of comprehensive income for the three years
ended December 31:
Dollars in thousands
2013
2012
2011
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
$ 35,785
$ 35,764
$ 37,056
4,674
4,773
4,945
(271)
(350)
(442)
2,357
1,718
1,647
(864)
(800)
(786)
—
24
2,700
(402)
—
405
Total provision for income
taxes
$ 41,705
$ 43,403
$ 42,825
Effective tax rate
40.8%
42.5%
40.5%
The decrease in the effective income tax rate for 2013
compared to 2012 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 tax
amounts resulting from the 2009 Oregon income tax rate
change.
The provision (benefit) for current and deferred income
taxes consists of the following at December 31:
In thousands
Current
Federal
State
Deferred
Federal
State
2013
2012
2011
$
(62) $
1,693
$
(11)
(73)
99
1,792
130
(929)
(799)
35,109
6,669
41,778
31,187
10,424
41,611
35,021
8,603
43,624
Total provision for
income taxes
$ 41,705
$ 43,403
$ 42,825
Total income taxes paid
$
870
$
2,979
$
1,756
The following table summarizes the total provision (benefit)
for income taxes for the utility and non-utility business
segments for the three years ended December 31:
In thousands
Utility:
Current
Deferred
Deferred investment
and energy tax credits
Non-utility business
segments:
Current
Deferred
2013
2012
2011
$
(73) $
1,909
$
(4,646)
38,073
39,163
49,595
(271)
(350)
(422)
37,729
40,722
44,527
—
3,976
3,976
(117)
2,798
2,681
3,846
(5,548)
(1,702)
Total provision for income
taxes
$ 41,705
$ 43,403
$ 42,825
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 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
2013
2012
$ 362,160
$ 322,527
56,183
71,971
47,516
60,253
49,197
43,824
$ 537,830
$ 475,801
$
— $
(7,724)
4,112
—
1,939
45,351
51,402
6,024
(1,235)
1,986
32,997
32,048
Deferred income tax liabilities, net
486,428
443,753
Deferred investment tax credits
367
624
Deferred income taxes and investment
tax credits
$ 486,795
$ 444,377
We have determined that we are more likely than not to
realize all recorded deferred tax assets as of December 31,
2013.
On December 17, 2010, President Obama signed into law
the Tax Relief, Unemployment Insurance Reauthorization,
and Job Creation Act of 2010, 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, which extended 50%
bonus depreciation under §168(k) through 2013 for modified
accelerated cost recovery system (MACRS) property with a
recovery period of 20 years or less.
75
The Company estimates that it has net operating loss (NOL)
carryforwards of $113.0 million for federal taxes and $113.7
million for Oregon taxes at December 31, 2013. 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 our
consolidated balance sheet. As of December 31, 2013, we
had no reserves for uncertain tax positions.
As of December 31, 2013, the Company was under
examination by the Internal Revenue Service for tax years
2009 through 2011, with resolution expected in 2014. The
Company is also subject to examination for tax year 2012.
In 2012 the Company settled the Oregon Department of
Revenue 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.
Interest and penalties related to any future income tax
deficiencies are recorded within income tax expense in the
consolidated statements of comprehensive 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:
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 our agreements with Encana Oil & Gas
(USA) Inc. (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 6% of our gas supplies for the
year ended December 31, 2013. The following table outlines
our net gas reserves investment at December 31:
In thousands
2013
2012
Gas reserves, current
$
20,646
$
14,966
Gas reserves, non-current
Less: Accumulated amortization
Total gas reserves
Less: Deferred taxes on gas reserves
140,573
18,575
142,644
42,117
92,179
7,486
99,659
28,329
Net investment in gas reserves
$ 100,527
$
71,330
Variable Interest Entity (VIE) Analysis
We concluded that the arrangement with Encana qualifies
as a variable interest (VI) as our interest represents a minor
portion of total extraction activities. Our investment is
included on our balance sheet under gas reserves with our
maximum loss exposure limited to our current investment
balance.
In thousands
2013
2012
Utility plant in service
$2,585,901
$2,435,886
12. INVESTMENTS
Utility construction work in progress
28,855
46,831
Less: Accumulated depreciation
827,380
789,201
Utility plant, net
Non-utility plant in service
Non-utility construction work in
progress
Less: Accumulated depreciation
1,787,376
1,693,516
297,330
296,781
6,653
28,485
6,510
23,195
Non-utility plant, net
275,498
280,096
Total property, plant, and equipment
$2,062,874
$1,973,612
The weighted average depreciation rate was 2.8% for utility
assets and 2.2% for non-utility assets in 2013, 2012, and
2011.
Accumulated depreciation does not include the accumulated
provision for asset removal costs of $296.3 million and
$281.2 million at December 31, 2013 and 2012,
respectively. These accrued asset removal costs are
reflected on the balance sheets as regulatory liabilities. See
Note 2.
76
Investments include financial investments in life insurance
policies, which are accounted for at cash surrender value,
net of policy loans, and equity investments in certain
partnerships and limited liability companies, which are
accounted for under the equity method. The following table
summarizes our other investments at December 31:
In thousands
2013
2012
Investments in life insurance policies
$ 51,791
$ 51,439
Investments in gas pipeline joint ventures
14,048
14,216
Other
2,012
2,012
Total other investments
$ 67,851
$ 67,667
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 at cash surrender value, net of
policy loans.
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, a wholly-
owned subsidiary of NW Natural, and 50% by TransCanada
American Investments Ltd., an indirect wholly-owned
subsidiary of TransCanada Corporation.
VIE Analysis
PGH is a development stage VIE. As of December 31,
2013, 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 or impairments to the project since 2011. Our
remaining equity investment was not impaired at December
31, 2013 as the fair value of expected cash flows from
planned development exceeded our remaining equity
investment of $13.4 million at December 31, 2013.
However, if we learn that the project is 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.
77
13. DERIVATIVE INSTRUMENTS
We enter into financial derivative contracts to meet our
utility’s natural gas sales requirements. These contracts
include swaps, options, and combinations of option
contracts. We primarily use these derivative financial
instruments to manage commodity price variability. A small
portion of our derivative hedging strategy involves foreign
currency exchange contracts. Our financial derivatives used
to meet our utility's natural gas requirements qualify for
regulatory accounting deferral.
We enter into these financial derivatives, up to prescribed
limits, to hedge price variability related to our physical gas
supply contracts as well as to hedge spot purchases of
natural gas. The foreign currency forward contracts are
used to hedge the fluctuation in foreign currency exchange
rates for pipeline demand charges paid in Canadian dollars.
In the normal course of business, we also enter into
indexed-price physical forward natural gas commodity
purchase contracts and options to meet the requirements of
utility customers. These contracts qualify for regulatory
deferral accounting treatment. We also enter into exchange
contracts related to the optimization of our gas portfolio,
which are derivatives that do not qualify for hedge
accounting or regulatory deferral, but are subject to our
regulatory sharing agreement.
Notional Amounts
The following table presents the absolute notional amounts
related to open positions on our derivative instruments:
In thousands
Natural gas (in therms):
Financial
Physical
Foreign exchange
At December 31,
2013
2012
389,225
395,820
552,500
398,250
$ 15,002
$ 13,231
PGA
Derivatives entered into by the utility for the procurement or
hedging of natural gas for future gas years and 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 20% or
10% recognized in current income. For the current gas year
we have selected the 90% deferral option. In general, our
commodity hedging for the current gas year is completed
prior to the start of the upcoming gas year, and hedge prices
are included in the Company's weighted-average cost of
gas (WACOG) in the PGA filing. As of November 1, 2013,
we reached our target hedge percentage for the 2013-14
gas year, and these hedge prices were included in the PGA
filing and qualified for regulatory deferral.
Unrealized and Realized Gain/Loss
The following table reflects the income statement presentation for the unrealized gains and losses from our derivative
instruments. Outstanding derivative instruments related to regulated utility operations are deferred in accordance with regulatory
accounting standards.
In thousands
Benefit (expense) to cost of gas
Less:
Amounts deferred to regulatory accounts on balance sheet
Total gain in pre-tax earnings
$
$
December 31, 2013
December 31, 2012
Natural gas
commodity
Foreign
exchange
Natural gas
commodity
Foreign
exchange
4,985
$
(300) $
(5,850) $
(4,964)
21
$
300
— $
5,850
— $
65
(65)
—
The cost of foreign currency forward and natural gas derivative contracts are recognized immediately in the cost of gas; however,
costs above or below the amount embedded in the current year PGA are subject to a regulatory deferral tariff and therefore, are
recorded as a regulatory asset or liability.
We realized net losses of $11.0 million and $70.2 million for the years ended December 31, 2013 and 2012, respectively, from
the settlement of natural gas financial derivative contracts. These realized losses were recorded as increases to the cost of gas.
Credit Risk Management of Financial Derivatives
Instruments
No collateral was posted with or by our counterparties as of
December 31, 2013 or 2012. 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 2013 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 financial swap and option
contracts outstanding, which reflect unrealized gains of $5.4
million at December 31, 2013, we do not have any collateral
demand exposure.
Our financial derivative instruments are subject to master
netting arrangements; however, they are presented on a
gross basis on the face of our statement of financial
position. The Company and its counterparties have the
ability to set-off their obligations to each other under
specified circumstances. Such circumstances may include
when there is a defaulting party or in the event of a credit
change due to a merger that affects either party or any other
termination event.
If netted by counterparty, our derivative position would result
in an asset of $7.2 million and a liability of $2.5 million as of
December 31, 2013. As of December 31, 2012, our
derivative position would result in an asset of $5.6 million
and a liability of $11.4 million.
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
78
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
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 financial derivatives
at December 31, 2013 currently does not extend beyond
March 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.
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, 2013:
In thousands
2014
2015
2016
2017
2018
Thereafter
Total
Less: Amount
representing
interest
Total at present
value
Gas
Purchase
Agreements
Pipeline
Capacity
Purchase
Agreements
Pipeline
Capacity
Release
Agreements
$
60,692
$
94,923
$
3,739
—
—
—
—
—
60,692
77,433
66,146
52,084
42,263
216,995
549,844
—
—
—
—
—
3,739
20
113,437
—
$
60,672
$
436,407
$
3,739
Our total payments for fixed charges under capacity
purchase agreements were $98.2 million in 2013, $94.3
million in 2012, and $94.2 million in 2011. Included in the
amounts were reductions for capacity release sales of $4.5
million for 2013, $4.2 million for 2012, and $3.1 million for
2011. 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.
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, 2013. As of December 31, 2013
and 2012, the net fair value was an asset of $4.7 million and
a liability of $5.8 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, 2013 and 2012. See Note 2.
14. COMMITMENTS AND CONTINGENCIES
Leases
We lease land, buildings, and equipment under agreements
that expire in various years, including a 99-year land lease
that extends through 2108. Rental expense under operating
leases was $5.1 million, $4.8 million and $5.4 million for the
years ended December 31, 2013, 2012 and 2011,
respectively. The following table reflects the future minimum
lease payments due under non-cancelable leases at
December 31, 2013. These commitments relate principally
to the lease of our office headquarters, underground gas
storage facilities, and computer equipment.
In thousands
Operating
leases
Capital
leases
2014
2015
2016
2017
2018
Thereafter
Total
$
5,611
$
462
$
5,530
5,510
5,506
2,858
34,836
196
82
12
—
—
Minimum
lease
payments
6,073
5,726
5,592
5,518
2,858
34,836
$
59,851
$
752
$
60,603
79
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.
In the 2012 Oregon general rate case, the new SRRM
mechanism was approved to recover the Company's
deferred environmental costs. The Commission ordered a
separate docket to determine the prudence of deferred
costs, the allocation of insurance proceeds, and an earnings
test that would be applied to past and future deferred costs.
In July 2013, all parties filed a settlement agreement with
the OPUC to address how to apply the new mechanism. In
November, the Commission rejected the settlement and
ordered further proceedings. We have established a
schedule with parties for 2014 and are working toward
resolution of this matter.
In Washington, 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 Part I, Item 3
"Legal Proceedings"). In the complaint, NW Natural sought
damages in excess of $50 million in losses it incurred
through the date of the complaint, as well as declaratory
relief for additional losses it expects to incur in the future. As
of February 6, 2014, we had settled with all defendant
insurance companies in this litigation. As a result of this
settlement, the Company expects to receive additional
payments aggregating approximately $102 million in 2014
related to the settlements. Such payments are to be made in
the first and second quarters of 2014. Through December
31, 2013, we have received approximately $48 million. See
Note 17 for additional information.
Environmental Sites
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:
In 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
2013
2012
2013
2012
$
1,278
$
2,207
$
37,954
$
36,087
1,766
11,010
763
85
1,274
—
1,767
18,722
3,478
39,508
637
140
993
—
406
248
122
179
3,160
5,028
379
396
—
185
$
16,176
$
24,466
$
81,895
$
45,235
80
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:
In thousands
Cash paid(1)
2013
2012
$
98,817
$
71,124
Total regulatory asset deferral(2)
148,389
121,144
(1) Includes $20.1 million reclassified to utility plant in 2013
associated with the water treatment station of which a portion was
paid in 2012.
(2) Includes cash paid, remaining liability, and interest, net of
insurance reimbursement and amounts reclassified to utility plant
for the water treatment station.
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 the Environmental Protection
Agency (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 the EPA will select for the entire 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 the 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 $39.2 million to $350 million. We have recorded
a liability of $39.2 million for the sediment clean-up, which
reflects the low end of the EE/CA range, as well as costs 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
the EPA. NW Natural also incurs costs related to natural
resource damages from these sites. The Company and
81
other parties have signed a cooperative agreement with the
Portland Harbor Natural Resource Trustee council to
participate in a phased natural resource damage
assessment to estimate liabilities to support an early
restoration-based settlement of natural resource damage
claims. Natural resource damage claims may arise only
after a remedy for clean-up has been settled. We have
accrued a liability for these claims which is at the low end of
the range of the potential liability and the high end of the
range cannot be reasonably estimated. 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 1958 (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 the
remediation of the uplands portion of the site which is at the
low end of the range of potential liability and the high end of
the range cannot be reasonably estimated at this time.
In September 2013, we completed construction and placed
into service a groundwater source control system, including
a water treatment station, at the Gasco site. We are working
with ODEQ on monitoring the effectiveness of the system
and at this time it is unclear what, if any, additional actions
ODEQ may require subsequent to the initial testing of the
system or as part of the final remedy for the uplands portion
of the Gasco site. We have estimated the cost associated
with the ongoing operation of the system and have
recognized a liability which is at the low end of the range of
potential cost. We cannot estimate the high end of the range
due to the uncertainty associated with the duration of
running the water treatment station, which will be highly
dependent upon the remedy determined for both the upland
portion as well as the final remedy for our Gasco sediment
exposure.
On October 28, 2013, the OPUC approved placing $19.0
million of capital costs associated with constructing a water
treatment station at our Gasco environmental site into rates
beginning November 1, 2013. These amounts are subject to
refund, with interest, in the event the Commission
determines, through a separate docket, that any of these
costs were incurred imprudently. On February 13, 2014, NW
Natural filed an all-party stipulation in the proceeding with
the OPUC, which if approved would deem Gasco
construction costs prudent and would also approve applying
$2.5 million of insurance proceeds plus interest to reduce
the Gasco costs included in rates beginning November 1,
2014.
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; the high end of the
range could not be reasonably estimated as of December
31, 2013.
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 with confirmed releases of hazardous
substances, 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. See also Part I, Item 3,
“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.
82
16. REVISION OF PRIOR PERIOD FINANCIAL STATEMENTS
During the first quarter of 2013, we identified an error in the rate used to calculate interest on certain regulatory assets.
Accounting standards allow for the capitalization of all or part of an incurred cost that would otherwise be charged to expense if
the regulator provides orders that create probable recovery of past costs through future revenues. Historically we had accrued
interest as specified by regulatory order on certain regulatory balances at our authorized rate of return (ROR). This ROR
includes both a debt and equity component, which we are allowed to recover from customers in the form of a carrying cost on
regulatory deferred account balances. As the equity component of our ROR is not an incurred cost that would otherwise be
charged to expense, this portion of the carrying cost should not have been capitalized for financial reporting purposes.
We assessed the materiality of this error on prior period financial statements and concluded it was not material to any prior
annual or interim periods; however, the cumulative impact would have been material to the annual and interim periods for 2013,
if corrected in 2013. As a result, in accordance with accounting standards, we revised our prior period financial statements as
described below to correct this error. The revision had no effect on reported cash flows.
The adjustment impacted years 2003 through 2012 with a cumulative pre-tax decrease over that period of $5.6 million to
regulatory assets and other income and expense. The revision decreased net income by $1.1 million and $0.9 million for the
years ended December 31, 2012 and 2011, respectively. The cumulative decrease to January 1, 2011 retained earnings was
$1.4 million as a result of the revision.
The following table presents the income statement impacts of this revision for the years ended December 31:
In thousands, except per share data
Other income and expense, net
Income before income taxes
Income tax expense
Net Income
Comprehensive income
Basic EPS
Diluted EPS
Reported
Balance
2012
Adjust-
ment
Adjusted
Balance
Reported
Balance
2011
Adjust-
ment
Adjusted
Balance
$
4,936
$
(1,777) $
3,159
$
4,523
$
(1,411) $
3,112
103,959
(1,777)
102,182
107,280
(1,411)
105,869
44,104
59,855
58,364
2.23
2.22
(701)
(1,076)
(1,076)
(0.04)
(0.04)
43,403
58,779
57,288
2.19
2.18
43,382
63,898
62,702
2.39
2.39
(557)
(854)
(854)
(0.03)
(0.03)
42,825
63,044
61,848
2.36
2.36
The following table presents the balance sheet impacts of this revision as of December 31:
In thousands
Non-current assets:
Regulatory assets
Total non-current assets
Total assets
Liabilities and equity:
2012
2011
Reported
Balance
Adjustment
Adjusted
Balance
Reported
Balance
Adjustment
Adjusted
Balance
$
387,888
$
(5,633) $
2,535,054
2,818,753
(5,633)
(5,633)
382,255
2,529,421
2,813,120
$
371,392
2,397,885
$
2,746,574
(3,856) $
(3,856)
(3,856)
367,536
2,394,029
2,742,718
Deferred credits and other non-current liabilities:
Deferred tax liabilities
$
446,604
$
(2,227) $
444,377
$
413,209
$
(1,526) $
411,683
Total deferred credits and other non-current
liabilities
1,025,584
(2,227)
1,023,357
975,922
(1,526)
974,396
Equity:
Retained earnings
Total equity
Total liabilities and equity
385,753
733,033
2,818,753
(3,406)
(3,406)
(5,633)
382,347
729,627
2,813,120
373,905
714,488
2,746,574
(2,330)
(2,330)
(3,856)
371,575
712,158
2,742,718
83
The following tables present the income statement and balance sheet corrections for the following quarters:
First Quarter
Second Quarter
Third Quarter
Fourth Quarter
2012
In thousands, except per share data
Reported
Balance
Adjusted
Balance
Reported
Balance
Adjusted
Balance
Reported
Balance
Adjusted
Balance
Reported
Balance
Adjusted
Balance
Other income and expense, net
$
1,005
$
472
$
921
$
620
$
1,710
$
1,180
$
1,300
$
887
Income (loss) before income taxes
Income tax expense (benefit)
Net income (loss)
Comprehensive income (loss)
Basic EPS
Diluted EPS
Non-current assets:
Regulatory assets
68,480
27,873
40,607
40,773
1.52
1.51
67,947
27,663
40,284
40,450
1.50
1.50
2,296
887
1,409
1,575
0.05
0.05
1,995
768
1,227
1,393
0.05
0.05
(13,594)
(14,124)
(3,036)
(3,245)
(10,558)
(10,879)
(10,391)
(10,712)
(0.39)
(0.39)
(0.41)
(0.41)
46,777
18,380
28,397
26,407
1.06
1.05
46,364
18,217
28,147
26,157
1.05
1.04
$ 368,521
$ 364,132
$ 366,981
$ 362,290
$ 367,692
$ 362,472
$ 387,888
$ 382,255
Total non-current assets
2,416,372
2,411,983
2,448,359
2,443,668
2,492,467
2,487,247
2,535,054
2,529,421
Total assets
Liabilities and equity:
Deferred credits and other non-
current liabilities:
Deferred tax liabilities
Total deferred credits and other
non-current liabilities
Equity:
Retained earnings
Total equity
2,727,262
2,722,873
2,635,141
2,630,450
2,690,368
2,685,148
2,818,753
2,813,120
$ 438,486
$ 436,750
$ 440,073
$ 438,217
$ 430,885
$ 428,821
$ 446,604
$ 444,377
999,028
997,292
991,007
989,151
985,729
983,665
1,025,584
1,023,357
402,599
399,946
745,971
743,318
392,082
737,570
389,247
734,735
369,584
717,559
366,428
714,403
385,753
733,033
382,347
729,627
Total liabilities and equity
2,727,262
2,722,873
2,635,141
2,630,450
2,690,368
2,685,148
2,818,753
2,813,120
First Quarter
Second Quarter
Third Quarter
Fourth Quarter
2011
In thousands, except per share data
Reported
Balance
Adjusted
Balance
Reported
Balance
Adjusted
Balance
Reported
Balance
Adjusted
Balance
Reported
Balance
Adjusted
Balance
Other income and expense, net
$
1,214
$
1,291
$
1,122
$
779
$
1,781
$
1,426
$
406
$
(384)
Income (loss) before income taxes
Income tax expense (benefit)
Net income (loss)
Comprehensive income (loss)
Basic EPS
Diluted EPS
Non-current assets:
Regulatory assets
68,627
27,854
40,773
40,919
1.53
1.53
68,704
27,884
40,820
40,966
1.53
1.53
3,509
1,316
2,193
2,339
0.08
0.08
3,166
1,181
1,985
2,131
0.07
0.07
(14,012)
(14,367)
(5,700)
(8,312)
(8,166)
(0.31)
(0.31)
(5,840)
(8,527)
(8,381)
(0.32)
(0.32)
49,156
19,912
29,244
27,610
1.09
1.09
48,366
19,600
28,766
27,132
1.08
1.07
$ 345,452
$ 343,085
$ 326,081
$ 323,371
$ 328,757
$ 325,692
$ 371,392
$ 367,536
Total non-current assets
2,290,848
2,288,481
2,294,100
2,291,390
2,317,293
2,314,228
2,397,885
2,394,029
Total assets
2,571,553
2,569,186
2,521,994
2,519,284
2,567,840
2,564,775
2,746,574
2,742,718
Liabilities and equity:
Deferred credits and other non-
current liabilities:
Deferred tax liabilities
$ 396,357
$ 395,419
$ 398,825
$ 397,751
$ 394,217
$ 393,003
$ 413,209
$ 411,683
Total deferred credits and other
non-current liabilities
Equity:
Retained earnings
Total equity
873,714
872,776
874,842
873,768
866,927
865,713
975,922
974,396
385,899
384,470
376,489
374,853
356,574
354,723
373,905
371,575
723,228
721,799
714,628
712,992
696,605
694,754
714,488
712,158
Total liabilities and equity
2,571,553
2,569,186
2,521,994
2,519,284
2,567,840
2,564,775
2,746,574
2,742,718
84
17. SUBSEQUENT EVENT
In December 2010, NW Natural commenced litigation
against certain of its historical liability insurers. NW Natural
alleged that the defendant insurance companies issued third
party liability insurance policies to NW Natural and that the
defendants had 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 sought damages in excess of $50 million in
losses it had incurred through the date of the complaint, as
well as declaratory relief for additional damages it expected
to incur in the future. Settlements with certain of the
defendant insurance companies resulted in payments
received by NW Natural through December 31, 2013 of
approximately $48 million.
In January and February 2014, the remaining defendant
insurance companies agreed to settle all of NW Natural’s
claims. In 2014 the Company expects to receive additional
payments aggregating approximately $102 million under
settlement agreements signed in 2013 and 2014. Such
payments are to be made in the first and second quarters of
2014. As a result of such settlements, the Company
anticipates dismissal of the litigation in the second quarter of
2014.
The settlements are recognized in regulatory accounts with
the treatment determined through the SRRM. We expect the
open regulatory docket regarding SRRM to be resolved
during 2014.
85
NORTHWEST NATURAL GAS COMPANY
QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
Quarter ended
In thousands, except share data
March 31
June 30
September 30
December 31
2013
Operating revenues
Net income (loss)
Basic earnings (loss) per share(1)
Diluted earnings (loss) per share(1)
2012
Operating revenues
Net income (loss)(2)
Basic earnings (loss) per share(1)(2)
Diluted earnings (loss) per share(1)(2)
$
277,861
$
131,714
$
88,195
$
37,639
1.40
1.40
2,126
0.08
0.08
(8,233)
(0.31)
(0.31)
$
309,639
$
103,991
$
87,501
$
40,284
1.50
1.50
1,227
0.05
0.05
(10,879)
(0.41)
(0.41)
260,748
29,006
1.07
1.07
229,476
28,147
1.05
1.04
(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.
(2) Prior period balances have been adjusted for a prior period error identified during the first quarter of 2013. See Note 16 for reconciliation to
amounts previously reported.
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)
2013
Reserves deducted in balance sheet from
assets to which they apply:
Allowance for uncollectible accounts
2012
Reserves deducted in balance sheet from
assets to which they apply:
Allowance for uncollectible accounts
2011
Reserves deducted in balance sheet from
assets to which they apply:
Allowance for uncollectible accounts
$
$
$
Balance at
beginning of
period
Charged to
costs and
expenses
Charged to
other accounts
Net write-offs
Balance at end
of period
2,518
$
199
$
— $
1,061
$
1,656
2,895
$
1,130
$
— $
1,507
$
2,518
2,950
$
1,919
$
— $
1,974
$
2,895
86
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, 2013 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.
87
PART III
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Information concerning our Board of Directors, its Committees and the Audit Committee financial expert contained in NW
Natural’s definitive Proxy Statement for the May 22, 2014 Annual Meeting of Shareholders is hereby incorporated by reference.
The information concerning "Section 16(a) Beneficial Ownership Reporting Compliance" and "Corporate Governance" contained
in our definitive Proxy Statement for the May 22, 2014 Annual Meeting of Shareholders is hereby incorporated by reference.
Name
Gregg S. Kantor
David H. Anderson
Stephen P. Feltz
Margaret D. Kirkpatrick
Lea Anne Doolittle
J. Keith White
David R. Williams
Grant M. Yoshihara
C. Alex Miller
MardiLyn Saathoff
Brody J. Wilson
David A. Weber
Age at
Dec. 31,
2013
56
52
58
59
58
60
60
58
56
57
34
54
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 and Chief Operating Officer (2014- );
Executive Vice President Operations and Regulation (2013-2014);
Senior Vice President and Chief Financial Officer (2004-2013).
Senior Vice President and Chief Financial Officer (2013- ); Assistant
Secretary (2007- ); Treasurer and Controller (1999-2013).
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 (2008-2013);
General Manager of Rates and Regulatory Affairs (2002-2009).
Vice President Legal, Risk and Compliance (2013- ); Deputy General
Counsel (2010-2013); Chief Governance Officer and Corporate
Secretary (2008- ); Chief Compliance Officer and Assistant General
Counsel, Tektronix, Inc. (2005-2008).
Controller (2013- ); Acting Controller (2013); Accounting Director
(2012-2013); Senior Manager, PriceWaterhouseCoopers LLP
(2009-2012); Manager, PriceWaterhouseCoopers LLP (2007-2009).
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 22, 2014. 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.
88
ITEM 11. EXECUTIVE COMPENSATION
The information concerning "Executive Compensation", "Report of the Organization and Executive Compensation Committee",
and "Compensation Committee Interlocks and Insider Participation" contained in our definitive Proxy Statement for the May 22,
2014 Annual Meeting of Shareholders is hereby incorporated by reference. Information related to Executive Officers as of
December 31, 2013 is reflected in Part III, Item 10, above.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND
RELATED STOCKHOLDER MATTERS
The following table sets forth information regarding compensation plans under which equity securities of NW Natural are
authorized for issuance as of December 31, 2013 (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))
152,007
50,972
—
492,150
$
26,191
1,326
55,253
134,711
912,610
n/a
n/a
—
42.89
35.69
n/a
n/a
n/a
443,198
443,198
250,000
—
95,993
n/a
n/a
n/a
789,191
(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 Share Awards outstanding at
December 31, 2013, the number of shares shown in column (a) would increase by 152,007 shares and the number of shares shown in
column (c) would decrease by the same amount of shares.
The aggregate 443,198 shares are available for future issuance under the LTIP as Restricted Stock Units, Performance Share Awards, or
LTIP Stock Options. An additional 250,000 shares are available for LTIP Stock Option Issuance at December 31, 2013, but those additional
shares 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. Amounts credited to stock accounts are payable solely in shares of common stock and cash for
fractional shares, and amounts in the above table represent the aggregate number of shares credited to participant's stock accounts. 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, 10, or 15 years as elected by the participant in accordance with the terms of the DCP. Amounts credited to stock
accounts are payable solely in shares of common stock and cash for fractional shares, and amounts in the above table represent the
aggregate number of shares credited to participant's stock accounts. 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” and "Security
Ownership of Common Stock of Certain Beneficial Owners" contained in our definitive Proxy Statement for the May 22, 2014
Annual Meeting of Shareholders is incorporated herein by reference.
89
ITEM 13. CERTAIN RELATIONSHIPS AND
RELATED TRANSACTIONS, AND DIRECTOR
INDEPENDENCE
The information captioned "Transactions with Related
Persons" and "Corporate Governance" in the Company’s
definitive Proxy Statement for the May 22, 2014 Annual
Meeting of Shareholders is hereby incorporated by
reference.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND
SERVICES
The information captioned "2013 and 2012 Audit Firm Fees"
in the Company’s definitive Proxy Statement for the May 22,
2014 Annual Meeting of Shareholders is hereby
incorporated by reference.
90
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 93.
91
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: February 28, 2014
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
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/ Kenneth Thrasher
Kenneth Thrasher
Title
Date
Principal Executive Officer and Director
February 28, 2014
Principal Financial Officer
February 28, 2014
Principal Accounting Officer
February 28, 2014
)
)
)
)
)
)
)
)
)
)
)
February 28, 2014
)
)
)
)
)
)
)
)
)
)
)
Director
Director
Director
Director
Director
Director
Director
Director
92
NORTHWEST NATURAL GAS COMPANY
Exhibit Index to Annual Report on Form 10-K
For the Fiscal Year Ended December 31, 2013
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).
93
4k.
Form of Letter Agreement, between each of JPMorgan Chase Bank, N.A., Bank of America, N.A., Canadian Imperial
Bank of Commerce, Royal Bank of Canada, TD Bank, N.A., Union Bank, N.A., US Bank, N.A., and Wells Fargo Bank,
N.A., with JPMorgan Chase Bank, N.A. as Administrative Agent, extending the Credit Agreement between Northwest
Natural Gas Company and each financial institutions, effective as of December 20, 2013.
*10a
Carry and Earning Agreement (incorporated herein by reference to Exhibit 10.1 to Form 10-Q for the quarter ended
March 31, 2011, File No. 1-15973).
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).
94
*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).
*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
(incorporated herein by reference to Exhibit 10r to Form 10-K for 2013, File No. 1-15973)
*10s.
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).
*10t.
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).
*10u.
Form of Long-Term Incentive Award Agreement under the Long-Term Incentive Plan (2013-2015) (incorporated herein
by reference to Exhibit 10v. to Form 10K for 2012, File No. 1-15973).
10v.
Form of Long-Term Incentive Award Agreement under the Long-Term Incentive Plan (2014-2016).
*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).
*10aa. Form of Restricted Stock Unit Award Agreement under the Long-Term Incentive Plan (2013) (incorporated herein by
reference to Exhibit 10aa. to Form 10-K for 2012, File No. 1-15978).
*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. Form of Special Restricted Stock Unit Award Agreement under the Long-Term Incentive Plan between the Company
and an executive officer (incorporated herein by reference to Exhibit 10cc. to Form 10-Q for the period ending
September 30, 2013, File No. 1-15973)
*10dd. Annual Incentive Plan for NW Natural Gas Storage, LLC, as amended February 2, 2012 (incorporated herein by
reference to Exhibit 10cc. to Form 10-K for 2012, File No. 1-15973).
*10ee. Long Term Incentive Plan for NW Natural Gas Storage, LLC (incorporated herein by reference to Exhibit 10dd. to
Form 10-K for 2012, File No. 1-15973).
95
*10ff.
Form of Change in Control Severance Agreement between the Company and an executive officer (incorporated
herein by reference to Exhibit 10ee. to Form 10-K for 2012, File No. 1-15973).
101.
The following materials from Northwest Natural Gas Company Annual Report on Form 10-K for the fiscal year ended
December 31, 2013, 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
96
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(1)
Taxes on Income(1)
Fixed Charges, as above
Total Earnings, as defined
Ratios of Earnings to Fixed Charges
Year Ended December 31,
2013
2012
2011
2010
2009
$
$
40,825
2,709
1,877
1,910
47,321
$
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
60,538
41,705
47,321
$ 149,564
3.16
58,779
43,403
45,201
$ 147,383
3.26
63,044
42,825
44,433
$ 150,302
3.38
72,013
49,033
44,681
$ 165,727
3.71
74,632
46,349
42,622
$ 163,603
3.84
(1) Prior period balances have been adjusted for a prior period error identified during the first quarter of 2013. See Note 16 for additional detail
on this error.
97
CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
EXHIBIT 23
We hereby consent to the incorporation by reference in the Registration Statement on Form
333-120955, 333-134973, 333-139819, 333-180350 and 333-187005) and in the Registration Statement on Form S-3 (No.
333-192641) of Northwest Natural Gas Company of our report dated February 28, 2014 relating to the consolidated financial
statements, financial statement schedule and the effectiveness of internal control over financial reporting, which appears in this
Form
(Nos. 333-70218, 333-100885,
10-K.
S-8
/s/ PricewaterhouseCoopers LLP
Portland, Oregon
February 28, 2014
98
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: February 28, 2014
/s/ Gregg S. Kantor
Gregg S. Kantor
President and Chief Executive Officer
99
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: February 28, 2014
/s/ Stephen P. Feltz
Stephen P. Feltz
Senior Vice President and Chief Financial Officer
100
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, 2013 (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 28th day of
February 2014.
/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.
101
[THIS PAGE INTENTIONALLY LEFT BLANK]
[THIS PAGE INTENTIONALLY LEFT BLANK]
INVESTOR AND SHAREHOLDER INFORMATION
CORPORATE INFORMATION
Robert Hess
Director, Investor Relations
(800) 422-4012, Ext. 2388
rsh@nwnatural.com
Chu Lee
Manager, Shareholder Services
(800) 422-4012, Ext. 2402
c4l@nwnatural.com
Stock transfer agent and registrar
Community and Sustainability Report
For common stock:
Learn more about NW Natural’s community involvement and
American Stock Transfer & Trust Company
philanthropic contributions, environmental stewardship,
6201 15th Avenue
Brooklyn, NY 11219
(888) 777-0321
web: amstock.com
email: info@amstock.com
Trustee and bond paying agent
For all bond issues:
Deutsche Bank Trust Company Americas
60 Wall Street
New York, NY 10005
(800) 735-7777
employee safety efforts and other company initiatives.
View the Community & Sustainability Annual Report at
nwnatural.com/aboutnwnatural/community.
Low-Income Weatherization Program
NW Natural offers a program to our low-income customers
designed to reduce their natural gas use through the installation
of energy-efficient equipment and weatherization measures.
Find out more about this innovative Oregon program.
View the Low-Income Energy-Efficiency Program Annual Report
at nwnatural.com/aboutnwnatural/environmentalstewardship.
Energy-Efficiency Programs
NW Natural partners with Energy Trust of Oregon to offer
our Oregon and Washington customers energy-efficiency
programs and services. Learn more about the results of
these programs and the benefits to our customers.
View the Energy Trust of Oregon Annual Report at nwnatural.
com/aboutnwnatural/environmentalstewardship.
220 NW SECOND AVENUE
PORTLAND, OREGON 97209
NWNATURAL.COM
NYSE: NWN