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BUILDING
WITH FORESIGHT
2015 ANNUAL REPORT
CORPORATE PROFILE
NW Natural (NYSE: NWN)
is a 157-year-old natural
gas distribution company
headquartered in Portland,
Oregon.
NW Natural serves more than
714,000 utility customers in Oregon
and Southwest Washington and
provides natural gas storage to
customers on the West Coast.
In keeping with its steady
growth strategy, the company
has increased dividends
paid to shareholders
for 60 consecutive
years.
WASHINGTON
ASTORIA
MIST STORAGE
VANCOUVER
GASCO LNG
PORTLAND
THE DALLES
TRAINING
CENTER
LINCOLN CITY
NEWPORT LNG
SALEM
ALBANY
SERVICE TERRITORY
AND STORAGE FACILITIES
EUGENE
OREGON
COOS BAY
ASTORIA
MIST STORAGE
VANCOUVER
GASCO LNG
WASHINGTON
PORTLAND
THE DALLES
TRAINING
CENTER
LINCOLN CITY
SALEM
ALBANY
NEWPORT LNG
EUGENE
OREGON
COOS BAY
SAN FRANCISCO
KEY
NEVADA
NW NATURAL SERVICE TERRITORY
TRAINING CENTER
REGIONAL RESOURCE CENTER
LNG PLANT
UNDERGROUND STORAGE
HEADQUARTERS
GILL RANCH
STORAGE
FRESNO
CALIFORNIA
2015
2014
increase
(decrease )
FINANCIAL OVERVIEW
earnings
Financial facts ($000):
Operating revenues
Utility margin
Net income
Adjusted net income*
Financial ratios (%):
Return on average common equity
Adjusted return on average common equity*
Capital structure** at year-end:
Long-term debt
Common stock equity
**Excluding short-term debt and current long-term maturities.
common stock
Shareholder data (000):
723,791
371,392
53,703
62,778
754,037
366,088
58,692
58,692
6.9
8.1
42.5
57.5
7.7
7.7
44.8
55.2
Average shares outstanding – diluted
Year-end shares outstanding
27,417
27,427
27,223
27,284
Per share data ($):
Diluted earnings
Adjusted diluted earnings*
Dividends paid
Book value at year-end
Market value at year-end
utility operating highlights
1.96
2.29
1.86
28.47
50.61
2.16
2.16
1.85
28.12
49.90
Gas sales and transportation deliveries (000 therms) 1,028,612
3,458
Degree days
714,428
Customers at year-end
1,061
Employees at year-end
1,092,990
3,792
704,644
1,084
dividends paid on common stock (per share)
PAYMENT DATE
February 15
May 15
August 15
November 15
Total dividends paid
$ 0.4650
0.4650
0.4650
0.4675
$ 1.8625
$ 0.460
0.460
0.460
0.465
$ 1.845
(4) %
1
(9)
7
bps
(80)
40
bps
(230)
230
1%
1
(9)%
6
1
1
1
(6)%
(9)
1
(2)
diluted earnings per share
(in dollars)
dividends paid per share
(in dollars)
$2.60
$2.10
$1.60
$1.10
$0.60
$0.10
$1.90
$1.85
$1.80
$1.75
$1.70
$1.65
$1.60
$1.55
2011
2012
2013
2014
2015
2011
2012
2013
2014
2015
Diluted earnings per share were $1.96 or
$2.29 adjusted for the regulatory
disallowance in 2015.*
Annual dividends paid per share in 2015
increased for the 60th consecutive year.
The current indicated annual dividend is
$1.87 per share.
* Indicates non-GAAP measures based on the $15 million pre-tax or $9.1 million after-tax charge from the 2015
environmental order. After-tax amounts calculated using statutory tax rate of 39.5% and EPS uses 27.4 million
diluted shares.
LOS ANGELES
NEVADA
SAN FRANCISCO
GILL RANCH
STORAGE
FRESNO
CALIFORNIA
LOS ANGELES
Left: Gregg Kantor, CEO
Right: David Anderson, President and COO
LETTER TO SHAREHOLDERS
3
NW Natural has a long record of thinking ahead,
of careful planning and disciplined execution.
These attributes served us well in 2015.
This past year we completed the removal of our bare steel pipe –
making NW Natural’s distribution system one of the most modern
in the nation. A milestone made possible due to pipe replace-
ment cost trackers established three decades ago.
We successfully navigated the financial impacts of a record-warm
winter as a result of effective cost management and our weather
normalization mechanism (WARM) put in place in 2003.
We advanced a proposal to expand our storage assets in
Oregon, first identified in 1979, to serve gas-fired electric
generation that will back up recently built wind resources.
And we began collecting revenues in November through our
new environmental cost recovery mechanism. The Site Reme-
2015 HIGHLIGHTS
• Reported net income of $53.7 million or $1.96 per share.
Excluding the environmental charge, net income was
$62.8 million or $2.29 per share, an increase of
13 cents per share compared to 2014 results.*
• Continued to add new customers at an annual growth rate
of 1.4 percent, bringing our customer base to more than
714,000.
• Reduced residential customer rates by approximately 7 percent
in Oregon and 14 percent in Washington, as a result of the
lowest natural gas commodity prices in 15 years.
• Earned the highest customer satisfaction score among large
utilities in the West in the 2015 J.D. Power Gas Utility Resi-
dential Customer Satisfaction Study.
diation and Recovery Mechanism (SRRM) allows us to recover
• Invested $129 million in capital expenditures for customer
prudently incurred environmental cleanup costs allocated to
growth and system improvements.
Oregon, associated with legacy manufactured gas plants that
operated until 1957. While that docket required a $15 million
write-down in 2015 due to over-earning in years past, the
recovery mechanism aligns our company and customers
around a responsible cleanup of these legacy assets.
Acting with foresight is no accident. It is part of our culture and key
to a successful business in the Pacific Northwest. At NW Natural,
we are proud of our ability to anticipate the needs of our customers,
find innovative solutions, and successfully respond to challenges.
Evidence of this can be seen in our 2015 performance:
• Received key regulatory decisions from the Public Utility
Commission of Oregon that resulted in cost recovery for
prudently incurred environmental expenses and Jonah Field
investments.
• Increased common dividends paid for the 60th consecutive
year, one of the longest dividend increase records of any
company on the NYSE.
4
LETTER TO SHAREHOLDERS
System Safety and Preparedness
Removing the last few miles of all identified bare
steel pipe in our system last year was a major
accomplishment, but it was just one of many
initiatives we’re working on to ensure our
systems’ safety and reliability.
In 2015, we moved forward on a five-year, $25 million
infrastructure investment plan in Clark County, WA.
The system upgrades planned for Clark County
will include new high-pressure distribution lines and
extensions to better serve customers in our service
territory’s fastest-growing community.
We also began to make additional improvements to
our Newport LNG facility, built in 1977. Upgrades
planned for this natural gas storage facility on the
Oregon Coast include tank refurbishments, turbine
modernization, and control room enhancements at
an estimated cost of $25 million.
Customer and system safety remains at the core of
our operational priorities. In 2015, we once again
reached our emergency response goals of answering
90 percent of emergency calls within 10 seconds,
and responding on-site to damage and odor calls
within 30 minutes on average.
We also continued to prepare for a large-scale
emergency event, such as a severe earthquake.
Should our Portland headquarters be rendered
unsafe, we can now transfer gas control and
emergency dispatch operations to our new Business Continuity Center in
Sherwood, Oregon. The facility was built to the highest structural standards
for earthquake preparedness and has been outfitted to host employees crucial
to core business functions during the first phases of a natural disaster.
But today system safety doesn’t stop at state-of-the art pipelines and
facilities. Utilities must also anticipate and mitigate cybersecurity threats.
In 2015, our Information Technology team made significant strides to increase
our cyber resiliency, deploying new cybersecurity technology, employee
education and training on new policies and emergency response protocols
company-wide.
Regulatory Progress
Last year, we continued to manage several
important regulatory dockets at the Public
Utility Commission of Oregon (OPUC).
Early in 2015, we received the commission’s
decision on our environmental cost recovery
proceeding. In its order, the OPUC found that
$114 million of environmental remediation
expenses and carrying costs incurred through
March of 2014 were prudent, as were the
insurance settlements we executed totaling
approximately $150 million. However, the
OPUC disallowed recovery of $15 million of
environmental costs based on the application
of an earnings test for past years when the
company earned above its authorized rate
of return. As a result, we took an after-tax
charge of $9.1 million to net income in 2015.
SYSTEM
SAFETY
COMPLETED
THE REMOVAL OF
BARE STEEL AND
CAST IRON PIPES
CAPITAL EXPENDITURES
WITH DEPRECIATION & AMORTIZATION
(in millions)
2011
2012
2013
2014
2015
CAPITAL EXPENDITURES
DEPRECIATION & AMORTIZATION
$150
$125
$100
$75
$50
$25
$0
Total investment in capital expenditures during 2015 was $129 million, of
which nearly $100 million was related to system integrity, maintenance and
customer growth.
Andrea Kuehnel and Scott Burg were part of the team
that worked to remove the last known bare steel from
NW Natural’s system.
LETTER TO SHAREHOLDERS
5
In January 2016, the commission
reviewed our compliance filing under
their 2015 order and confirmed the
company’s recovery of environmental
costs allocated to Oregon rate payers
under the mechanism. However, they
disallowed interest earned on the
original $15 million disallowance, which
resulted in the company recognizing
a $2 million after-tax charge in 2016.
Although the charges were disappoint-
ing, this was a complex docket, and
we believe the mechanism provides a
good path forward for all stakeholders.
In September of last year, the OPUC
also adopted an all-party settlement
that determined how we would recover
costs associated with seven wells
we drilled under our amended gas
WE REDUCED
RESIDENTIAL
CUSTOMER RATES
APPROXIMATELY
7 PERCENT
IN OREGON AND
14 PERCENT
IN WASHINGTON
reserves agreement. This $10 million additional investment provides long-term
price protection for Oregon utility customers. We were pleased with this
collaborative settlement and the positive conclusion to the docket.
In 2016, we will be working with the commission and other utilities in Oregon
on a policy docket to explore commodity hedging, including what role gas
reserves could play in a balanced natural gas supply portfolio. It’s our view
that today’s low prices, coupled with the expected increase in demand for
natural gas to serve power generation, make long-term hedging opportunities
like gas reserves an important option to help ensure future price stability for
our customers.
Utility and Storage Operations
In November, we reduced residential customer
rates approximately 7 percent in Oregon and 14
percent in Washington. With that reduction, our
customers are paying less for their natural gas
now than they did 15 years ago. This price decline
helps our customers and improves the company’s
competitive position, as consumers in our service
area can save about 50 percent by switching from
an electric or oil furnace to natural gas.
UTILITY CUSTOMERS AT YEAR-END
720,000
700,000
680,000
660,000
640,000
620,000
600,000
580,000
560,000
2011
2012
2013
2014
2015
INDUSTRIAL
COMMERCIAL
RESIDENTIAL
We added 9,784 new customers in 2015, and now serve 714,428 customers.
6
LETTER TO SHAREHOLDERS
Our engineering team created a streamlined piping and metering design that reduces
developer costs. As a result, this 10-story “Block 75” project in Portland will now include
gas amenities in all 75 apartments, when it opens later in 2016.
We were pleased to pair these lower rates with
flexible energy resources Gill Ranch can deliver.
another year of outstanding service from our
As the impacts of those RPS requirements unfold,
employees. For the sixth time in nine years,
our priority is to pursue higher value service con-
NW Natural ranked first in the annual J.D. Power
tracts and tap into new market opportunities.
Residential Customer Satisfaction Study for natural
gas utilities in the West. This also marked the eighth
time in nine years of posting among the top two
highest satisfaction scores in the nation.
Also in 2015, operations at our underground
storage facility near Mist, Oregon performed well,
providing valuable services to our core utility cus-
tomers and profitably serving storage customers in
the Northwest. However, our California Gill Ranch
storage facility continued to operate in challenging
market conditions.
Excess natural gas storage capacity and limited
gas price volatility have kept storage values low in
California over the last several years. But new legis-
lation recently signed by the Governor is likely to
change the state’s energy landscape in substantial
ways. California’s new Renewable Portfolio Standard
(RPS) requires 50 percent of its power generation
be produced from renewables by 2030, which we
believe provides a strategic opportunity for the
NW NATURAL
RANKED FIRST
in the J.D. Power Residential
Customer Satisfaction Study
in the West
Competing for the Future
Our region is attracting young, college educated
households considered vital for both economic
development and longer-term growth. More
people were employed in 2015, with the average
monthly employment in the Portland and Van-
couver Metro area increasing by about 35,000
new jobs for an annual employment growth rate
of 3.2 percent. This is more than one percentage
point above the national average. In that same
time period, the unemployment rate fell 100 basis
points to 5.3 percent. Oregon’s average wage
today is the highest it has been in a generation.
PORTLAND
AREA
RENTERS
prefer natural gas
amenities
We are also seeing strong housing growth in the Portland area with a
25 percent increase in single-family building permits in the last 12 months.
NW Natural leveraged these economic improvements last year to sign up
nearly 9,800 new customers, an annual growth rate of 1.4 percent.
Nationally, single-family new construction has yet to rebound to pre-recession
levels – and the Northwest is no exception. But there has been an upturn in
the housing sector locally, particularly in multifamily apartments. Seeing this
trend emerge, we created a cross-functional team to evaluate every aspect
of the apartment rental market – a market typically underserved with natural
gas in the Northwest and across the U.S.
One of the first steps we took to assess our opportunity was to conduct
renter preference research. A recent study showed 80 percent of Portland
area renters paying average rent prices or above prefer gas amenities such
OREGON & WASHINGTON AVERAGE RESIDENTIAL RATES
(in dollars per therm)
LETTER TO SHAREHOLDERS
7
$1.60
$1.40
$1.20
$1.00
$0.80
$0.60
2001
2003
2005
2007
2009
2011
2013
2015
OREGON AND WASHINGTON AVERAGE RESIDENTIAL RATES
Today’s residential rates are lower than they were 15 years ago.
The portal team is now working on new enhancements
to leverage web analytics and cost data to identify
main extension opportunities.
as cooktops, water heating and fireplaces – demonstrating a clear gap between
amendment to our existing Mist Site Certificate to
what renters’ desire and what’s available.
Armed with this data, we created a comprehensive marketing program to
target apartment developers. While still early, we’ve been pleased with the level
of interest from project owners. We view rental apartments as an untapped
growth opportunity and a priority segment for us moving forward.
Competing for growth today requires making it easier and faster to connect to
gas. In 2015, the use of our industry-leading online portal grew, as consumers
searched for gas availability in their area with the click of a mouse or a tap on
the screen. In fact, almost 30 percent of our conversion sales used this web
tool and more than 1,500 online orders were submitted by builders and con-
tractors last year. Strong adoption of the portal’s
functionality helps us operate more efficiently.
But, as important, portal analytics allow us to
strategically target new areas for growth and
create customized marketing programs in 2016
and beyond.
Leading with Solutions
Policy makers in the Pacific Northwest are
committed to shutting down coal-fired electric
generation and substantially increasing the use
of renewables to meet our region’s power needs.
Natural gas and its supporting infrastructure
are critical to helping achieve this goal. One
way is by helping to back-up intermittent wind
resources at a local electric utility’s gas-fired
generating plants.
In 2015, we submitted an application to the
Oregon Energy Facility Siting Council for an
30
PERCENT
of conversions
used the portal
allow us to provide on-demand storage services
to these gas-fired generating plants. Last year, we
also held an open house with the local community,
obtained required permits and property rights, and
worked with local agencies on the details of the
project. In early 2016, the Department of Energy
published a proposed order as part of the permit-
ting process. If there are no challenges to that
order, we could receive approval from the Oregon
Energy Facility Siting Council for our permit later
this spring. Concurrently, we are in the process
of rebidding the engineering, procurement, and
construction portion of the project. Following the
approval of the permit and the rebidding process,
we expect to receive a notice to proceed from the
project sponsor later this year.
Another way NW Natural is striving to support
our region’s environmental goals is through a new
Combined Heat and Power (CHP) program. The
CHP program is the first proposal submitted by
the company under Senate Bill 844 – the Oregon
legislation designed to incent natural gas utilities to
invest in projects that reduce carbon emissions. As
submitted, the CHP program would provide finan-
cial incentives to customers in our service territory
that invest in and install CHP at their facilities. We
submitted the program in June 2015, and expect
a decision from the Commission in the spring of
2016. That decision will also help determine how
we proceed with other potential carbon reduction
programs under this legislation.
8
LETTER TO SHAREHOLDERS
LIVING OUR MISSION & VALUES
Leadership for the Future
Over many years, NW Natural has demonstrated
the careful planning essential to finding and retain-
ing the talent necessary to drive future success.
Detailed succession plans are an integral part of
the company’s business activities, and this past
year, the benefits of that work were visible.
In July of 2015, the board of directors elected
David H. Anderson as President, adding to his
responsibilities as Chief Operating Officer. Then
in December, we announced my retirement at the
end of 2016 and that David would begin serving
as Chief Executive Officer effective Aug. 1 this year.
To help with the transition, I will be staying on as an
advisor to the board until the end of December.
A smooth transition at the top is critical, but as
important is developing the talent for succession
in key positions across the organization. That has
been a long-held commitment at NW Natural, one
that in my opinion is the true mark of a company
with foresight.
In today’s complex and rapidly changing energy
landscape, foresight has never been more impor-
tant. In 2016, NW Natural will remain focused on
meeting today’s expectations while keeping an eye
on the horizon.
We will continue to safely provide our product with
great customer service; provide a solid financial
value to our customers and to you, our shareholders;
and look toward the future – ensuring we have the
expertise to drive growth and provide innovative
solutions that fuel our long-term success.
As I complete my last year at the company, I would
like you to know it has been a great privilege to
work with the talented men and women who make
up NW Natural and to lead this great company on
your behalf. And finally, as we continue into our
157th year, from all of us at NW Natural, we thank
you for your investment and support.
Gregg S. Kantor
CEO
OUR MISSION
We provide safe, reliable and affordable
energy in an environmentally responsible
way to better the lives of the public
we serve.
OUR CORE VALUES
Integrity
Safety
Service Ethic
Caring
Environmental Stewardship
Produced by NW Natural’s
Corporate Communications
photo credits
Bruce Forster - Cover: Tilikum Crossing;
Page 3: Gregg Kantor and David Anderson
Dale Headrick - Page 4: Andrea Kuehnel and Scott Burg;
Page 5: Newport storage facility; Page 6: D.G. Graham,
Block 75 project
Robbie McClaran - Page 9: Board of Directors
Corky Miller - Page 4: Bare steel removal, Page 6: Customer
Service Rep; Page 7: Kristen Brown and Walter Cahall;
Inside back cover: Nikki Sparley, Chu Lee and backpack event;
Page 8: Corporate Officers
printing
RR Donnelley
Front to back – left to right
lea anne doolittle
Senior Vice President and
Chief Administrative Officer
mardilyn saathoff
Senior Vice President
and General Counsel
gregg s. kantor
Chief Executive Officer
david r. williams
Vice President
Utility Services
david h. anderson
President and
Chief Operating Officer
kimberly heiting
Vice President
Communications and
Chief Marketing Officer
shawn m. filippi
Vice President and
Corporate Secretary
c. alex miller
Vice President Regulation
and Treasurer
tom imeson
Vice President
Public Affairs
gregory c. hazelton
Senior Vice President and
Chief Financial Officer
grant m. yoshihara
Vice President
Utility Operations
brody j. wilson
Controller and Chief
Accounting Officer
CORPORATE OFFICERS
9
BOARD OF DIRECTORS
timothy p. boyle
Chief Executive Officer
Columbia Sportswear
Company
martha l.
“stormy” byorum
Chief Executive Officer
Cori Investment
Advisors, LLC
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
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
malia wasson
Former Executive
Vice President of
Commercial Banking,
U.S. Bank
10 CORPORATE INFORMATION
Notice of Annual Meeting
The 2016 Annual Meeting will be held at 2 p.m., Thursday, May 26, 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 a legal proxy or other evidence to the meeting showing that you owned NW Natural
Common Stock as of the record date, April 7, 2016, 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.
to NW Natural Board of Directors,
Request for publications
Dividend reinvestment and
direct stock purchase plan
Participants may make an initial invest-
ment in company stock and common
shareholders of record may reinvest all
or part of their dividends in additional
shares under the company’s plan. Cash
purchases may also be made. Participants
in the plan bear the cost of brokerage fees
and commissions for shares purchased
on the open market to fulfill purchases
under the plan. A prospectus will be
sent upon request.
c/o Corporate Secretary.
Forward-looking statements
The statements made in this Annual
Report that are not purely historical,
including statements regarding strat-
egy, growth and marketing initiatives,
dividends, earnings, financial value, future
demand for gas, commodity costs and
competitiveness, revenues, customer
growth, gas supplies and reserves, hedge
efficacy, capital expenditures, pipeline
and storage infrastructure investments,
Scheduled dividend payment dates
system expansion, Mist storage expan-
Subject to Board approval, the following
dates are scheduled for dividend payment:
February 12, 2016
May 13, 2016
August 15, 2016
November 15, 2016
Certifications
The Chief Executive Officer certified
to the NYSE on June 25, 2015, that,
as of that date, he was not aware of
any violation by the company of NYSE’s
corporate governance listing standards,
and the company had filed with the
Securities and Exchange Commission
(SEC), as exhibits 31.1 and 31.2 to its
Annual Report on Form 10-K for the year
ended December 31, 2014, the certificates
of the Chief Executive Officer and the Chief
Financial Officer of the company certifying the
quality of the company’s public disclosure.
For the year ended December 31, 2015,
the certificates of the Chief Executive Officer
and Chief Financial Officer are attached
as exhibits 31.1 and 31.2 to the Form 10-K
included in this Annual Report.
Contact the NW Natural Board
Concerns may be directed to the
nonmanagement directors by writing
sion project, including but not limited
to cost and timelines, growth initiatives
including SB844 projects, emergency
preparedness, cyber resiliency and
preparedness, system reliability, storage
performance values, governmental policy
and legislation and the effects thereof,
regulatory cost recovery mechanisms,
including, but not limited to, the SRRM,
regulatory prudence reviews including,
but not limited to, commodity hedging,
regulatory proceedings and actions,
economic recovery factors, customer
savings, market trends and the com-
petitive environment, and coal-fired
and renewable energy resources, 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 uncertainties, 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.
The following publications may be
obtained without charge by contacting
the Corporate Secretary at NW Natural’s
address: Annual Report; Form 10-K; Form
10-Q; Corporate Governance Standards;
Director Independence Standards; Code
of Ethics; and Board Committee Charters.
These publications, as well as other filings
made with the SEC, are also available
on our website at nwnatural.com. Our
SEC filings are also available by request
through the SEC by mail at U.S. Securi-
ties and Exchange Commission, Office
of FOIA/PA Operations, 100 F Street,
N.E., Washington, 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
1-800-SEC-0330.
comparison of five-year
cumulative total return
(Based on $100 invested on 12/31/2010)
$250
$200
$150
$100
$50
$0
2010
2011
2012
2013
2014
2015
NWN
S&P UTILITIES INDEX
S&P 500 INDEX
Total shareholder return (annualized) over the five
years ending December 31, 2015 for NW Natural
was 5.9%, compared to Standard & Poor’s (S&P)
Utilities Index return of 11%, and the S&P 500
Index return of 12.5%.
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, 2015
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from ___________ to____________
Commission file number 1-15973
NORTHWEST NATURAL GAS COMPANY
(Exact name of registrant as specified in its charter)
Oregon
(State or other jurisdiction of
incorporation or organization)
93-0256722
(I.R.S. Employer
Identification No.)
220 N.W. Second Avenue, Portland, Oregon 97209
(Address of principal executive offices) (Zip Code)
Registrant’s telephone number, including area code: (503) 226-4211
Securities registered pursuant to Section 12(b) of the Act:
Title of each class Name of each exchange on which registered
Common Stock New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: None.
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
Yes [ X ] No [ ]
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.
Yes [ ] No [ X ]
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the
Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to
file such reports), and (2) has been subject to such filing requirements for the past 90 days.
Yes [ X ] No [ ]
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every
Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter)
during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).
Yes [ X ] No [ ]
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405) is not contained
herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated
by reference in Part III of this Form 10-K or any amendment to this Form 10-K.
[ X ]
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a
smaller reporting company. See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in
Rule 12b-2 of the Exchange Act. (Check one):
Large Accelerated Filer [ X ] Accelerated Filer [ ]
Non-accelerated Filer [ ] Smaller Reporting Company [ ]
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yes [ ] No [ X ]
As of June 30, 2015, the registrant had 27,355,642 shares of its Common Stock outstanding, of which 26,973,861 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 $1,137,757,457.
At February 19, 2016, 27,435,906 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 2016 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, 2015
TABLE OF CONTENTS
PART I
Glossary of Terms
Forward-Looking Statements
Item 1.
Business
Overview
Business Model
Local Gas Distribution
Gas Storage
Other
Environmental Issues
Employees
Additions to Infrastructure
Executive Officers of the Registrant
Available Information
Item 1A. Risk Factors
Item 1B. Unresolved Staff Comments
Properties
Legal Proceedings
Mine Safety Disclosures
Item 2.
Item 3.
Item 4.
PART II
Item 5.
Market for 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
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5
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5
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46
48
86
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87
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89
90
91
GLOSSARY OF TERMS AND ABBREVIATIONS
AFUDC
AOCI / AOCL
ASC
ASU
Average Weather
Bcf
Btu
CAP
CNG
CO2
Allowance for Funds Used During Construction
Accumulated Other Comprehensive Income (Loss)
Accounting Standards Codification
Accounting Standards Update as issued by the FASB
The 25-year average heating degree days based on temperatures established in our last
Oregon general rate case
Billion cubic feet, a volumetric measure of natural gas, where one Bcf is roughly equal to
10 million therms
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
Compliance Assurance Process with the Internal Revenue Service
Compressed Natural Gas
Carbon Dioxide
Core Utility Customers
Residential, commercial and industrial customers receiving firm service from the utility
Cost of Gas
CPUC
Decoupling
Demand Cost
Dth
EBITDA
EE/CA
Encana
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
California Public Utilities Commission, the entity that regulates our California gas storage
business at our Gill Ranch facility with respect to rates and terms of service, among other
matters
A billing rate mechanism, also referred to as our conservation tariff, which is designed to
break the link between utility earnings and the quantity of natural gas sold to customers;
the design is intended to allow the utility to encourage industrial and small commercial
customers to conserve energy while not adversely affecting its earnings due to
reductions in sales volumes
A component in core utility customer rates representing the cost of securing firm pipeline
capacity, whether the capacity is used or not
Dekatherm (also decatherm) is equal to 10 therms or one million British thermal units
(Btu)
Earnings before interest, taxes, depreciation and amortization, a non-GAAP financial
measure
Engineering Evaluation / Cost Analysis
Encana Oil & Gas (USA) Inc.
Energy Corp
Northwest Energy Corporation, a wholly-owned subsidiary of NW Natural
EPA
EPS
FASB
FERC
Firm Service
FMBs
GAAP
General Rate Case
GHG
Gill Ranch
Gill Ranch Facility
Environmental Protection Agency
Earnings per share
Financial Accounting Standards Board
Federal Energy Regulatory Commission; the entity regulating interstate storage services
offered by our Mist gas storage facility as part of our gas storage segment
Natural gas service offered to customers under contracts or rate schedules that will not
be disrupted to meet the needs of other customers
First Mortgage Bonds
Accounting principles generally accepted in the United States of America
A periodic filing with state or federal regulators to establish billing rates for utility
customers
Greenhouse gases
Gill Ranch Storage, LLC, a wholly-owned subsidiary of NWN Gas Storage
Underground natural gas storage facility near Fresno, California, with 75% owned by Gill
Ranch and 25% owned by PG&E
1
GTN
Heating Degree Days
Gas Transmission Northwest, which owns a transmission pipeline serving California and
the Pacific Northwest
Units of measure reflecting temperature-sensitive consumption of natural gas, calculated
by subtracting the average of a day’s high and low temperatures from 65 degrees
Fahrenheit
HATFA
Highway and Transportation Funding Act of 2014
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
IRP
IRS
KB
LIBOR
LNG
LWG
MAP-21
Moody's
NAV
Integrated Resource Plan
United States Internal Revenue Service
Kelso-Beaver Pipeline, of which 10% is owned by K-B Pipeline Company, a subsidiary of
NNG Financial
London Interbank Offered Rate
Liquefied Natural Gas, 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
Lower Willamette Group
A federal pension plan funding law called the Moving Ahead for Progress in the 21st
Century Act, July 2012
Moody's Investors Service, Inc. is a credit rating agency
Net Asset Value
NNG Financial
NNG Financial Corporation, a wholly-owned subsidiary of NW Natural
NOL
NRD
Net Operating Loss
Natural Resource Damages
NWN Energy
NW Natural Energy, LLC, a wholly-owned subsidiary of NW Natural
NWN Gas Reserves
NW Natural Gas Reserves, LLC, a wholly-owned subsidiary of Northwest Energy
Corporation
NWN Gas Storage
NW Natural Gas Storage, LLC, a wholly-owned subsidiary of NWN Energy
ODEQ
OPEIU
OPUC
PBGC
PG&E
PGA
PGE
PHMSA
PRP
RI/FS
ROD
ROE
ROR
S&P
Department of Environmental Quality
Office and Professional Employees International Union Local No. 11, AFL-CIO, which is
also referred to as the Union representing NW Natural's bargaining unit employees
Public Utility Commission of Oregon; the 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
Pension Benefit Guaranty Corporation
Pacific Gas & Electric Company; is a 25% owner of the Gill Ranch Facility
Purchased Gas Adjustment, 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
Portland General Electric
U.S. Department of Transportation's Pipeline and Hazardous Materials Safety
Administration
Potentially Responsible Parties
Remedial Investigation / Feasibility Study
Record of Decision
Return on Equity, 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 utility revenue requirements
Rate of Return
Standard & Poor's, a division of The McGraw-Hill Companies, Inc., is a credit rating
agency
Sales Service
Service provided whereby a customer purchases both natural gas commodity supply and
transportation from the utility
SEC
U.S. Securities and Exchange Commission
2
SIP
SRRM
TAIL
Therm
TWH
TWP
System Integrity Program, an Oregon billing rate mechanism that provides cost recovery
of pipeline system integrity programs, which are required under various safety standards
prescribed by both state and federal regulators
Site Remediation and Recovery Mechanism, an Oregon billing rate mechanism for
recovering prudently incurred environmental site remediation costs through customer
billings, subject to an earnings test
TransCanada American Investments, Ltd., a 50% owner of TWH
The basic unit of natural gas measurement, equal to one hundred thousand Btu’s
Trail West Holdings, LLC is 50% owned by NWN Energy
Trail West Pipeline, LLC, a subsidiary of TWH
TransCanada
TransCanada Pipelines Limited, owner of TAIL and GTN
Transportation Service
Service provided whereby a customer purchases natural gas 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, franchise tax and environmental recoveries
VIE
Variable Interest Entity
Weather Normalization
WUTC
An Oregon billing rate mechanism applied to residential and commercial customers to
adjust for temperature variances from average weather; rates decrease when the
weather is colder than average, and rates increase when the weather is warmer than
average; the mechanism is applied to customer bills from December through mid-May of
each heating season
Washington Utilities and Transportation Commission, the entity that regulates our
Washington utility business with respect to rates and terms of service, among other
matters
3
FORWARD-LOOKING STATEMENTS
plans, projections and predictions;
objectives;
goals;
strategies;
assumptions and estimates;
future events or performance;
trends;
risks;
timing and cyclicality;
earnings and dividends;
capital expenditures and allocation;
capital structure;
growth;
customer rates;
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, assumes, 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:
•
•
•
•
•
•
•
•
•
•
•
•
•
•
• workforce succession;
commodity costs;
•
gas reserves;
•
operational performance and costs;
•
energy policy and preferences;
•
efficacy of derivatives and hedges;
•
liquidity and financial positions;
•
•
project and program development, expansion, or
investment;
competition;
procurement and development of gas supplies;
estimated expenditures;
costs of compliance;
credit exposures;
potential efficiencies;
rate or regulatory outcomes, recovery or refunds;
impacts of laws, rules and regulations;
tax liabilities or refunds;
levels and pricing of gas storage contracts and gas
storage markets;
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;
effects of new or anticipated changes in critical accounting
policies;
approval and adequacy of regulatory deferrals;
effects and efficacy 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.
4
NORTHWEST NATURAL GAS
COMPANY
PART I
ITEM 1. BUSINESS
OVERVIEW
Northwest Natural Gas Company (NW Natural or the
Company) was incorporated under the laws of Oregon in
1910. Our Company and its predecessors have supplied
gas service to the public since 1859, and we have been
doing business as NW Natural since 1997. We maintain
operations in Oregon, Washington, and California and
conduct business through NW Natural and its subsidiaries.
References in this discussion to "Notes" are to 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
we aggregate and report as other. See Note 4 to the
Consolidated Financial Statements for further information on
total assets and results of operations for our segments for
the years ended December 31, 2013, 2014 and 2015.
The utility business is our largest segment, while our gas
storage businesses account for the majority of our
remaining net income. The following table reflects the
percentage allocation between segments and other as of
December 31, 2015:
Non-Utility(1)
Utility
Gas
Storage(2)
Other
Total
Assets
91.0%
8.5%
0.5%
100.0%
100.0%
0.3%
99.4%
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.
0.3%
(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 over
714,000 customers with approximately 89% of our
customers located in Oregon and 11% located in
Washington. In total, we provide natural gas service to over
100 cities in 18 counties with an estimated population of 3.5
million in our service territory.
5
We have been allocated an exclusive service territory by the
OPUC and WUTC, 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. 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 of ocean and river shipping, transcontinental
railways and highways, and an international airport. Major
businesses located in our service territory include retail,
manufacturing, and high-technology industries.
Natural gas provides a clean, low-carbon, and affordable
energy source, and supply in the United States is at an all-
time high. We are committed to environmental stewardship
and furthering the usage of natural gas to fuel heat, electric
generation, and transportation systems in our communities.
To this end, we filed our first proposal in 2015 with state
regulators under a Carbon Solutions Program incentivizing
industrial users to install combined heat and power systems
using natural gas. See Part II, Item 7, "Results of
Operations—Regulatory Matters". We also have an
approved CNG tariff in place to provide customers with high-
pressured gas service. Further, we have partnered with
local agencies on environmental programs, and are able to
allow residential and commercial customers to offset their
carbon emissions by supporting carbon-reduction projects
at dairies and other farms. Energy conservation is another
key component of our environmental focus and competitive
advantage, and we were among the first utilities in the
nation to break the link between utility earnings and the
quantity of natural gas sold to customers with our
decoupling mechanism or conservation tariff. The
decoupling mechanism is intended to allow the utility to
encourage industrial and small commercial customers to
conserve energy while not adversely affecting its earnings
due to reductions in sales volumes. We will continue to
further the role of natural gas in our region and country as it
is an affordable, energy efficient fuel source.
Customers
We serve residential, commercial and industrial customers
with no individual customer or industry accounting for more
than 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. The following
table presents summary customer information as of
December 31, 2015:
Residential
Commercial
Industrial
Other(1)
Total
Number of
Customers
% of
Volumes
% of Utility
Margin (1)
646,841
66,584
1,003
N/A
34%
21%
45%
N/A
63%
27%
8%
2%
714,428
100%
100%
(1) Utility margin is also affected by other items, including
miscellaneous services, gains or losses from our incentive gas
cost sharing mechanism, and other service fees.
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 service election,
special charges for changes between elections, and in
some cases, a minimum or maximum volume requirement
before changing options.
Customer growth rates for natural gas utilities in the Pacific
Northwest historically have been 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 natural gas is currently
in approximately 60% of residential single-family dwellings
in our service territory. Customer growth in our region
comes from the following main sources, in both new
construction and conversions: single-family housing, both
new construction and conversions; multifamily housing
construction; and commercial buildings, both new
construction and conversions. Single family new
construction has consistently been our strongest performing
source of growth. We have added increasing numbers of
customers in our service territory for the last four years as
the economy has recovered. Continued customer growth is
closely tied to the comparative pricing of natural gas to
electricity and fuel oil and the health of the Portland, Oregon
and Vancouver, Washington economies. We believe there is
potential for continued growth as natural gas is affordable,
reliable, a clean fuel choice, and a preferred energy source
in our service territory. 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 confronting a
number of our largest customers competing in global
markets, bypass continues to be a competitive
threat. Although we do not expect a significant number of
our large customers to bypass our system in the
foreseeable future, we could experience deterioration of
utility margin if customers bypass or switch over to custom
contracts with 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.
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. We filed a rate petition in 2013
and received approval in 2014 for new maximum cost-
based rates effective January 1, 2014.
6
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
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(1)
Pension Balancing
Environmental Cost Deferral
SRRM
X
X
X
X
X
X
X
X
X
X
(1) Regulatory authority for SIP expired October 31, 2014,
although the bare steel replacement portion of the mechanism
remained in place until the end of 2015.
In general, these rates and regulatory mechanisms do not
allow 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 gas reserves
investments and 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.
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".
Gas Supply
The utility strives to secure sufficient, reliable supplies of
natural gas to meet the needs of customers at the lowest
reasonable cost, while maintaining price stability and
managing gas purchase costs prudently. This is
accomplished through a comprehensive strategy focused on
the following items:
• Diverse Supply - providing diversity of supply sources;
• Diverse Contracts - maintaining a variety of contract
durations and types;
• Reliability - ensuring gas resource portfolios are
sufficient to satisfy customer requirements under
extreme cold weather conditions; and
• Cost Management and Recovery - employing prudent
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 take advantage of price
differentials. For 2015, 62% of our gas supply came from
Canada, with the balance primarily coming from the U.S.
Rocky Mountain region. We believe 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; however, we believe 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, the extraction of shale gas has
increased the availability of gas supplies throughout North
America for the foreseeable future.
We supplement our firm gas supply purchases with gas
withdrawals from gas storage facilities, including
underground reservoirs and LNG storage facilities. Storage
facilities are generally injected with natural gas during the
off-peak months in the spring and summer and the gas is
withdrawn for use during peak demand months in the winter.
The following table presents the storage facilities available
for our utility supply:
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
Total
Maximum
Daily
Deliverability
(therms in
millions)
Capacity
(Bcf)
3.1
0.5
0.7
0.6
1.2
6.1
10.6
1.1
4.4
0.9
0.6
17.6
(1) 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 3.1 million therms of daily
deliverability and 10.6 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
mitigates price risks as it displaces equivalent volumes of
heating season spot purchases.
The Mist facility is used for both utility and non-utility
purposes. Under our regulatory agreements with the OPUC
and WUTC, 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 May 2015, the utility recalled
0.3 million therms per day of deliverability and 0.7 Bcf of
associated storage capacity from the non-utility business to
serve core utility customer needs.
7
In addition, we have the ability to recall pipeline capacity
and supply resources from certain customers if needed to
meet high demand requirements.
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.
During 2015, we purchased a total of 669 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
Total
Percent of
Purchases
33%
30
37
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, no individual supplier provided over 10% of our
gas supply requirements in 2015.
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 seven day design peak
event based on the most severe cold weather experienced
during the last 30 years in our service territory.
Our projected maximum design day firm utility customer
sendout totals are approximately 9.5 million therms. Of this
total, we are currently capable of meeting about 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 come from gas
purchases under firm gas purchase contracts and recall
agreements.
To supplement near-term natural gas supplies, we planned
to segment transportation capacity during the 2014-2015
and 2015-2016 heating seasons for approximately 0.4
million therms per day if needed. Pipeline segmentation is a
natural gas transportation mechanism under which a
shipper can leverage its firm pipeline transportation capacity
by separating it into multiple segments with alternate
delivery routes. The reliability of service on these alternate
routes will vary depending on the constraints of the pipeline
system. For those segments with acceptable reliability,
segmentation provides a shipper with increased flexibility
and potential cost savings compared to traditional pipeline
service.
Specifically, we could segment pipeline capacity that flows
from Stanfield, Oregon with additional gas expected from
the Sumas, Washington trading hub. This segmented
capacity is considered reliable as the pipeline has not
experienced constraints from Sumas in recent years.
We believe 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 IRP process.
The following table shows the sources of supply projected to
be used to satisfy the design day sendout for the 2015-2016
winter heating season:
Therms in millions
Sources of utility supply:
Firm supply purchases
Mist underground storage (utility only)
Company-owned LNG storage
Off-system storage contract
Pipeline segmentation capacity
Recall agreements
Peak day citygate deliveries(1)
Therms
Percent
3.3
3.1
1.8
0.5
0.4
0.4
0.2
34%
32
19
5
4
4
2
Total
100%
(1) These citygate deliveries are contracted from December 2015
to February 2016 with this resource being evaluated for future
heating seasons after the current winter.
9.7
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 our IRP met the requirements of
the Washington Administrative Code. OPUC
acknowledgment of the IRP does not constitute ratemaking
approval of any specific resource acquisition strategy or
expenditure. However, the Commissioners generally
indicate they would give considerable weight in prudence
reviews to utility actions consistent with acknowledged
plans. The WUTC has indicated the IRP process is one
factor it will consider in a prudence review. We filed our
2014 IRP in both Oregon and Washington in August 2014
and received acknowledgment from the OPUC in February
2015, and notice from the WUTC in March 2015. We plan to
file an IRP with both Commissions in 2016.
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 transport gas to our distribution system; costs
paid to store gas; our gas reserves contracts; and gains or
losses related to gas commodity derivative contracts.
8
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: (1)
effectively 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
the gas into storage for price stability and to minimize
pipeline capacity demand costs; and
investing in gas reserves for longer term price stability.
See Note 11 for additional information about our gas
reserves.
•
•
We also contract with an independent energy marketing
company to capture opportunities regarding our 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 opportunities to generate
incremental revenues for our shareholders from a regulatory
incentive-sharing mechanism, which are included in our gas
storage segment.
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 of, 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."
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.
We incur monthly demand charges related to our firm
pipeline transportation contracts. Our largest pipeline
agreements are with Northwest Pipeline. These contracts
are multi-year contracts with expirations ranging from 2016
to 2044. We actively work with Northwest Pipeline and
others to renew contracts in advance of expiration to ensure
9
gas transportation capacity is sufficient to meet our utility
needs.
Rates for interstate pipeline transportation services are
established by FERC within the U.S. and by Canadian
authorities for services on Canadian pipelines.
As mentioned above, our service territory is dependent on a
single pipeline for its natural gas supply. Although supply
has not been disrupted in the recent past, pipeline
replacement projects and long-term projected natural gas
demand in our region underscore the need for pipeline
transportation diversity. In addition, there are several
potential industrial projects in the region, which could
increase the demand for natural gas and the need for
additional pipeline capacity and pipeline diversity.
Several interstate pipeline projects currently proposed could
meet the region's and our projected demand. The pipeline
location is dependent on the location of the committed
industrial project. We will evaluate and closely monitor the
currently prospected projects to determine the best option
for ratepayers. The Company also has an equity investment
in Trail West Holdings, LLC (TWH) that is developing plans
to build the Trail West pipeline. This pipeline 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, "2016
Outlook".
Gas Distribution
The primary goals of our gas distribution operations are
safety and reliability of our system, which entails building
and maintaining a safe pipeline distribution system.
Safety and the protection of our employees, our customers,
and the public at large are, and will remain, our top
priorities. We construct, operate and maintain our pipeline
distribution system and storage operations with the goal of
ensuring natural gas is delivered and stored safely, reliably,
and efficiently.
NW Natural has one of the most modern distribution
systems in the country with no identified cast iron pipe or
bare steel main. We removed the final three miles of known
bare steel from our system in 2015 and completed our cast
iron pipe removal in 2000. Since the 1980s, we have taken
a proactive approach to replacement programs and
partnered with our Commissions on progressive regulation
to further safety and reliability efforts for our distribution
system. In the past, we had a cost recovery program in
Oregon that encompassed the Company’s programs for
bare steel replacement, transmission pipeline integrity
management, and distribution pipeline integrity
management. Currently, we are working with the OPUC and
other Oregon natural gas utilities to evaluate guidelines for
potential future safety cost-recovery tracking programs. 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 pipeline incidents involving other companies. Additional
regulations from the U.S. Department of Transportation’s
Pipeline and Hazardous Materials Safety Administration
(PHMSA) are currently under development with final
regulations expected in 2016 and effective dates beginning
in 2017. 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 the costs associated with
compliance of federal, state, and local rules would be
recoverable in rates.
GAS STORAGE
Our gas storage segment includes the following:
•
the non-utility portion of the Mist gas storage facility
near Mist, Oregon;
our 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.
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
Designed
Storage
Capacity
(Bcf)
Deliverability
(Therms in
millions/day(3)
Injection
(Therms in
millions/day)(3)
Mist Storage(1)
5.4
2.1
Gill Ranch Storage(2)
15.0
(1) Approximately 5.4 Bcf of a total 16 Bcf at Mist is currently
4.9
0.8
2.4
available to our gas storage segment. The remaining 10.6 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. In May
2015, the utility recalled approximately 0.3 million therms per
day of deliverability and 0.7 Bcf of capacity for core utility
customer use.
(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 the
facility located in Columbia County, Oregon, near the town
of Mist. The Mist field was initially converted to storage
operations for our utility customers. Since 2001, gas storage
capacity at Mist has also 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 storage services, firm service
agreements with customers are entered into with terms
typically ranging from 2 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 distribution, electric generation, and
energy marketing. Three storage customers currently
account for all of our existing contracted non-utility gas
storage capacity at Mist, with the largest customer
accounting for about half of the total capacity. These three
customers have contracts expiring at various dates through
2019.
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.
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
10
rates for the interstate storage service. See Part II, Item 7,
"Results of Operations—Regulatory Matters".
EXPANSION OPPORTUNITIES. The need for new, flexible
gas-fired electricity 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 planning a potential expansion of our Mist storage
facility. If completed, this expansion would be supported by
a long-term contract with Portland General Electric (PGE) to
serve gas-fired electric power generation facilities at Port
Westward, Oregon, which is located approximately 15 miles
from Mist.
The project would include a new reservoir providing up to
2.5 Bcf of available storage, an additional compressor
station with design capacity of 1.2 million therms of gas
per day, innovative no-notice service with uninterrupted
turn capability, and a 13-mile pipeline to connect to PGE’s
gas plants at Port Westward. The current estimated cost of
the expansion is approximately $125 million with a
targeted in-service date in winter of 2018-19, depending
on the permitting process and construction schedule.
In early 2015, we received authorization from PGE to begin
permitting and land acquisition work, and a new rate
schedule was approved in October 2014 under which we
will provide no-notice gas storage service associated with
the expansion. This expansion project is subject to PGE's
final approval of project costs and a notice to proceed, as
well as the receipt of permits, certain land rights, and other
conditions.
Gill Ranch Storage Facility
Gill Ranch Storage, LLC (Gill Ranch), our subsidiary, has a
joint project agreement with Pacific Gas and Electric
Company (PG&E) to develop and own the Gill Ranch
underground natural gas storage facility near Fresno,
California. Currently, Gill Ranch is the sole operator of the
facility. The facility began operations in 2010 and 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
near historic lows and a greater number of competitors in
the area compared to the Pacific Northwest region. Prices
for the 2015-16 gas year showed improvement, however
prices remained low relative to the pricing in our original
long-term contracts which ended primarily in the 2013-14
gas storage year. In the future, we may see an improvement
in gas storage values and an increase in the demand for
natural gas driven by a number of factors, including
changes in electric generation triggered by California's
renewable portfolio standards, an increase in use of
alternative fuels to meet carbon reduction targets,
improvement of the California economy, growth of domestic
11
industrial manufacturing, potential exports of liquefied
natural gas from the west coast, and other favorable storage
market conditions in and around California. These factors, if
they occur, may contribute to higher summer/winter natural
gas price spreads, gas price volatility, and gas storage
values. We are continuing to explore opportunities to
increase revenues through enhanced services for storage
customers and capitalizing on opportunities that fit our
business-risk profile.
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. Our 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 27 years in duration; however,
the majority of the contracted capacity is shorter term in
nature due to market conditions. In the near-term, we
expect Gill Ranch to contract for terms ranging from one to
five years. For the 2015-16 gas storage year, Gill Ranch has
several storage customers, with the largest single contract
accounting for approximately 13% of our storage capacity.
In the near term, we continue to expect shorter contract
lengths reflecting current market prices and 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. The Gill Ranch storage facility currently competes
with a number of other storage providers, including local
integrated gas companies and other independent storage
providers (ISPs) in the northern California market. There are
currently four ISPs authorized by the CPUC to provide
storage services in California, with the Gill Ranch storage
facility comprising approximately 12% of the storage
capacity held by ISPs. A recent proposed acquisition, which
is pending CPUC approval, will consolidate approximately
80% of the storage capacity authorized by the CPUC to
ISPs in California. The effect of this dominant market share
on the Gill Ranch storage facility pricing and contracting
levels remains unknown and cannot be predicted at this
time.
In addition, in October 2015 a significant natural gas leak
occurred at a southern California gas storage facility that
persisted in 2016. During this time-frame, short-term
storage spreads for the region improved. At this time, we do
not know the long-term effects of this incident on gas
storage prices. Regulatory proceedings at both the national
and California state level have been opened in response to
the incident, and it is likely additional regulations will result
and increase short-term costs for all storage providers. The
implications of the regulatory proceeding are unknown and
cannot be predicted at this time until the rules are finalized.
summary information for these assets and results of
operations.
SEASONALITY. While the majority of our Gill Ranch
revenues are not subject to seasonality, and 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 and other
revenues. In addition, a significant portion of operating costs
at Gill Ranch are subject to fluctuations 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 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.
Asset Management
We contract with an independent energy marketing
company to provide asset management services, primarily
through the use of commodity and pipeline capacity release
transactions. The results 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 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.
TWH 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, "2016 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
12
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. 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;
variations between the estimated and actual period of
time that must be dedicated to respond to an
environmentally-contaminated site; and
the application of environmental laws that impose joint
and several liabilities on all potentially responsible
parties.
•
•
•
•
•
•
We seek recovery of environmental costs through received
insurance proceeds and customer rates, and we believe
recovery of these costs is probable. In Oregon, we have a
mechanism to recover expenses, subject to an earnings test
and allocation rules. See Part II, Item 7, "Results of
Operations—Rate Matters—Rate Mechanisms—
Environmental Costs", Note 2, Note 15, and Note 16.
Greenhouse Gas Issues
We recognize 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.
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 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, 2015, the utility workforce consisted of 598
members of the Office and Professional Employees
International Union (OPEIU) Local No. 11, AFL-CIO, and
463 non-union employees. Our labor agreement with
members of OPEIU covers wages, benefits and working
conditions. On May 22, 2014, our union employees ratified a
new labor agreement (Joint Accord) that extends to
November 30, 2019, and thereafter from year to year unless
either party serves notice of its intent to negotiate
modifications to the collective bargaining agreement.
At December 31, 2015, our subsidiaries had a combined
workforce of 15 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. For the five-year period
13
ending in 2020, capital expenditures for the utility are
estimated to be between $850 and $950 million, including
the Company's proposed investment in an expansion of our
Mist gas storage facility and excluding any potential future
gas reserves investments. In addition, we are evaluating the
impact of the five-year extension of bonus depreciation
resulting from the enactment of the Federal Protecting
Americans From Tax Hikes Act of 2016 on the mix and
profile of our investments. We expect cash tax savings from
bonus depreciation and are evaluating how to best take
advantage of these savings during the period in which they
are in effect. Our current capital expenditure range does not
consider any additional capital that may be available as a
result of this legislation.
In 2016, utility capital expenditures are estimated to be
between $155 and $175 million, and non-utility capital
investments are estimated to be less than $5 million.
Additional spend for gas storage and other investments
during and after 2016 will depend largely on future decisions
about potential expansion opportunities in gas storage
projects.
EXECUTIVE OFFICERS OF THE REGISTRANT
For information concerning our executive officers, see Part
III, Item 10.
AVAILABLE INFORMATION
We file annual, quarterly and special reports and other
information with the Securities and Exchange Commission
(SEC). Reports, proxy statements and other information
filed by us can be read and requested through the SEC by
mail at U.S. Securities and Exchange Commission, Office of
FOIA/PA Operations, 100 F Street, N.E., Washington, D.C.
20549, by facsimile at (202) 772-9337, or online at its
website (http://www.sec.gov). You can obtain information
about access to the Public Reference Room and how to
access or request records by calling the SEC at 1-800-
SEC-0330. The SEC website contains reports, proxy and
information statements and other information 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 the Company 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.
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
mean 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, commodity
hedging expense, transactions with affiliated interests,
weather adjustment mechanisms and other matters.
Similarly, in our gas storage businesses FERC has
regulatory authority over interstate storage services, the
CPUC has regulatory authority over our Gill Ranch storage
operations, and the WUTC and OPUC have regulatory
authority over our Mist storage operations.
The prices the OPUC and WUTC allow us to charge for
retail service, and the maximum FERC-approved rates
FERC authorizes us to charge for interstate storage and
related transportation services, 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 or
otherwise disallow. For example, in February 2015 the
OPUC issued an Order to the Company regarding
implementation of our SRRM that disallowed from rate
recovery approximately $15 million of approximately $95
million of our total environmental expenditures made from
2003 to 2012, due to the OPUC's application of a recently
formulated earnings test. The OPUC issued a subsequent
Order in January 2016 that, among other things, disallowed
interest on the $15 million disallowance after 2012 and
found only 96.68% of prudently incurred environmental
remediation costs to be allowable to Oregon. 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
14
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
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.
As a regulated utility, we frequently have dockets open with
our regulators. The regulatory proceedings for these
dockets typically involve multiple parties, including
governmental agencies, consumer advocacy groups, and
other third parties. Each party has differing concerns, but all
generally have the common objective of limiting amounts
included in rates. We cannot predict the timing or 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 settled with most of our historical liability insurers for
only a portion of the costs we have incurred to date and
expect to incur in the future. To the extent amounts we
recovered 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 assets 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 a recently adopted earnings test that
requires the Company to contribute additional amounts
toward environmental remediation costs above
approximately $10 million in years in which the Company
earns above its authorized Return on Equity (ROE). To the
extent the Company earns more than its authorized ROE in
a year, the Company would be required to cover
environmental expenses greater than the $10 million with
those earnings that exceed its authorized ROE. In addition,
the OPUC ordered a review of the SRRM in 2018 or when
we obtain greater certainty of environmental costs,
whichever occurs first. These ongoing prudence reviews,
the earnings test, or the three-year review could reduce the
amounts we are allowed to recover, and could adversely
affect our financial condition, results of operations and cash
flows.
Moreover, 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, the portions of these costs
allocable to us, 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 the 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
15
infrastructure and technology to respond to such
requirements, and may impact cultural perception of our
service or products negatively, diminishing the value of our
brand, all of which could adversely affect our business
practices, financial condition and results of operations.
Climate change may cause physical risks, including an
increase in sea level, intensified storms, water scarcity and
changes in weather conditions, such as changes in
precipitation, average temperatures and extreme wind or
other climate conditions. A significant portion of the nation’s
gas infrastructure is located in areas susceptible to storm
damage that could be aggravated by wetland and barrier
island erosion, which could give rise to gas supply
interruptions and price spikes.
These and other physical changes could result in
disruptions to natural gas production and transportation
systems potentially increasing the cost of gas beyond that
assumed in our PGA and affecting our ability to procure gas
to meet our customer demand. These changes could also
affect our distribution systems resulting in increased
maintenance and capital costs, disruption of service,
regulatory actions and lower customer satisfaction.
Additionally, to the extent that climate change adversely
impacts the economic health or weather conditions of our
service territory directly, it could adversely impact customer
demand or our customers' ability to pay. Such physical risks
could have an adverse effect on our financial condition,
results of operations, and cash flows.
BUSINESS DEVELOPMENT RISK. Our business development
projects may encounter unanticipated obstacles, costs,
changes or delays that could result in a project becoming
impaired, which could negatively impact our financial
condition, results of operations and cash flows.
Business development projects involve many risks. We are
currently engaged in several business development
projects, including, but not limited to, the early planning and
development stages for a regional 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. These projects may not be
successful. Additionally, 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 Trail West
pipeline, Gill Ranch storage and our gas reserves
agreements. 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 arrangements, which
operate as a hedge backed by physical gas supplies,
involve 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 laws 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
original gas reserves venture 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.
Further, any new gas reserves arrangements have not been
approved for inclusion in rates, and our regulators may
ultimately determine to not include all or a portion of future
transactions in rates. The realization of any of these
situations 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 chemicals
or compounds 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 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;
operating costs that are substantially higher than
expected;
•
•
•
• migration of natural gas through faults in the rock or to
some area of the reservoir where existing wells cannot
drain the gas effectively resulting in loss of the gas;
blowouts (uncontrolled escapes of gas from a pipeline
or well) or other accidents, fires and explosions; and
risks and hazards inherent in the drilling operations
associated with the development of the gas storage
facilities and/or wells.
•
These risks could result in personal injury or loss of human
life, damage to and destruction of property and equipment,
pollution or other environmental damage, breaches of our
contractual commitments, and may result in curtailment or
suspension of our operations, which in turn could lead to
significant costs and lost revenues. Further, because our
pipeline, storage and distribution facilities are in or near
populated areas, including residential areas, commercial
business centers, and industrial sites, any loss of human life
or adverse financial outcomes 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 security breaches of our
information technology infrastructure in the form of cyber-
attacks. These attacks could target or impact our
technology or mechanical systems that operate our natural
gas distribution, transmission or storage facilities and result
in a disruption in our operations, damage to our system and
inability 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. Additionally, large scale natural
disasters or terrorist attacks could destabilize the insurance
industry making insurance we do have unavailable, which
16
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 and liabilities. 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 largely
older workforce retires. We expect that a significant portion
of our workforce will retire within the current decade, which
will require that we attract, train and retain skilled workers to
prevent loss of institutional knowledge or skills gap. 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 November 30, 2019. 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 facility,
17
which could strain relationships with customers and state
regulators and cause a loss of revenues. Our collective
bargaining agreement may also limit our flexibility in dealing
with our workforce, and our ability to change work rules and
practices and implement other efficiency-related
improvements to successfully compete in today’s
challenging marketplace, which may negatively affect our
financial condition and results of operations.
LEGISLATIVE, COMPLIANCE AND TAXING AUTHORITY RISK.
We are subject to governmental regulation, and compliance
with local, state and federal requirements, including taxing
requirements, and unforeseen changes in or interpretations
of such requirements could affect our financial condition and
results of operations.
We are subject to regulation by federal, state and local
governmental authorities. We are required to comply with a
variety of laws and regulations and to obtain authorizations,
permits, approvals and certificates from governmental
agencies in various aspects of our business. We cannot
predict with certainty the impact of any future revisions or
changes in interpretations of existing regulations or the
adoption of new laws and regulations applicable to them.
Additionally, any failure to comply with existing or new laws
and regulations could result in fines, penalties or injunctive
measures that could affect operating assets. For example,
under the Energy Policy Act of 2005, the FERC has civil
authority under the Natural Gas Act to impose penalties for
current violations of up to $1 million per day for each
violation. In addition, as the regulatory environment for our
industry increases in complexity, the risk of inadvertent
noncompliance may also increase. Changes in regulations,
the imposition of additional regulations, and the failure to
comply with laws and regulations could negatively influence
our operating environment and results of operations.
Additionally, changes in federal, state or local tax laws and
their related regulations, or differing interpretations 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, leaks and accidents in other parts of the country
involving both distribution systems and storage facilities, 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, 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 reserves
transactions which are hedges 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, and have been
previously, 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
18
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. Further, based on current interpretations,
we are not considered a "swap dealer" or "major swap
participant" in 2015, so we are exempt from certain
requirements under the Dodd-Frank Act. If we are unable to
claim this exemption, we could be subject to higher costs for
our derivatives activities.
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
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. The recent recession slowed new
construction. While construction has resumed, it has not
returned to its original pace and has been heavily multi-
family, which is a segment that has historically used natural
gas less frequently. Insufficient growth in these markets, for
economic, political or other reasons 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. 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
19
conditions, technology, environmental impacts and public
perception.
Technological improvements in other energy sources such
as heat pumps, batteries or other alternative technologies
could 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 whom 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 11% 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 small commercial customers’
consumption. However, we do not have a conservation tariff
in Washington that provides us this margin protection on
sales to customers in that state.
RELIANCE ON TECHNOLOGY RISK. Our efforts to integrate,
consolidate and streamline our operations have resulted in
increased reliance on technology, the failure or security
breach of which could adversely affect our financial
condition and results of operations.
Over the last several years we have undertaken a variety of
initiatives to integrate, standardize, centralize and
streamline our operations. These efforts have resulted in
greater reliance on technological tools such as: an
enterprise resource planning system, an automated
dispatch system, an automated meter reading system, a
customer information system, a web-based ordering and
tracking 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. We take precautions to protect our systems, but
there is no guarantee that the procedures we have
implemented to protect against unauthorized access to
secured data and systems are adequate to safeguard
against all security breaches. 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, materially increase the costs we incur to protect
against these risks, 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.
20
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. 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 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 the ability to
expand or build 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.
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, 2020.
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 accelerated pipe
replacement programs under which we removed and
replaced 100% of our cast iron mains by the end of 2000,
and under which we eliminated all remaining known bare
steel mains and services 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, we have
only nonmaterial litigation in the ordinary course of
business.
ITEM 4. MINE SAFETY DISCLOSURES
Not applicable.
IMPAIRMENT OF LONG-LIVED ASSETS RISK. If storage
pricing does not improve, or higher value customers are not
obtained, our Gill Ranch storage asset may be impaired,
which could have a material effect on our financial condition,
or results of operations.
We review the carrying value of long-lived assets whenever
events or changes in circumstances indicate the carrying
amount of the assets might not be recoverable. The
determination of recoverability is based on the undiscounted
net cash flows expected to result from the operations of
such assets. Projected cash flows depend on the future
operating costs associated with the asset, storage pricing,
the ability to contract with higher value customers, and the
future market and price for gas storage over the remaining
life of the asset. Sustained low gas storage prices, the
failure to contract with higher value customers, or operating
costs that are above revenues from the facility could result
in an impairment of the carrying value of our Gill Ranch
storage facility. Similarly, if we were to determine to sell the
Gill Ranch storage facility, such determination may result in
an impairment of the carrying value of the facility. Any
impairment charge taken by the Company with respect to its
long-lived assets, including Gill Ranch, could be material to
the quarter that the charge is taken and could otherwise
have a material effect on the Company’s financial condition,
and results of operations.
THIRD-PARTY PIPELINE RISK. Our gas storage businesses
depend 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
operations are 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 reasons, our ability to operate
efficiently and satisfy our customers’ needs could be
compromised, thereby potentially having an adverse impact
on 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
21
PART II
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND
ISSUER PURCHASES OF EQUITY SECURITIES
Our common stock is listed and trades on the New York Stock Exchange under the symbol NWN. The high and low trades for
our common stock during the past two years were as follows:
Quarter Ended
March 31
June 30
September 30
December 31
2015
2014
High
Low
High
Low
$
52.25
$
43.35
$
44.09
$
49.77
46.74
51.85
41.32
42.00
45.03
47.32
47.50
52.57
40.05
43.06
41.81
42.29
The closing price for our common stock on December 31, 2015 and 2014 was $50.61 and $49.90, respectively.
As of February 19, 2016, there were 5,697 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
2015
2014
$
$
0.4650
$
0.4650
0.4650
0.4675
1.8625
$
0.460
0.460
0.460
0.465
1.845
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, 2015:
Period
Balance forward
10/01/15-10/31/15
11/01/15-11/30/15
12/01/15-12/31/15
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
3,279
$
26,594
1,204
31,077
47.12
46.37
48.27
46.52
—
—
—
—
—
—
2,124,528
$
16,732,648
(1) During the quarter ended December 31, 2015, 26,529 shares of our common stock were purchased on the open market to meet the
requirements of our Dividend Reinvestment and Direct Stock Purchase Plan. In addition, 4,548 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, 2015, no
shares of our common stock were accepted as payment for stock option exercises pursuant to our Restated Stock Option Plan.
(2) We have a common stock share repurchase program under which we purchase shares on the open market or through privately negotiated
transactions. We currently have Board authorization through May 31, 2016 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, 2015, 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.
22
ITEM 6. SELECTED FINANCIAL DATA
In thousands, except share data
2015
2014
2013
2012
2011
Operating revenues
Net income
$
723,791
$
754,037
$
758,518
$
730,607
$
828,055
53,703
58,692
60,538
58,779
63,044
For the year ended December 31,
Earnings per share of common stock:
Basic
Diluted
Dividends paid per share of common stock
$
1.96
$
2.16
$
2.24
$
2.19
$
1.96
1.86
2.16
1.85
2.24
1.83
2.18
1.79
2.36
2.36
1.75
Total assets, end of period
$
3,076,692
$
3,064,945
$
2,970,911
$
2,813,120
$
2,742,718
Total equity
Long-term debt
780,972
576,700
767,321
621,700
751,872
681,700
729,627
691,700
712,158
641,700
23
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,
2015, 2014, and 2013. References in this discussion to
"Notes" are to 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
including:
• 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 Trail West
Holding, LLC (TWH), which is pursuing the development of
a proposed natural gas pipeline through its wholly-owned
subsidiary, Trail West Pipeline, LLC (TWP), 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 the results of operations and
earnings amounts in total, certain financial measures are
expressed in cents per share or exclude the after-tax
regulatory disallowance related to the OPUC's 2015
environmental order, which are non-GAAP financial
measures. We present net income and earnings per share
(EPS) excluding the regulatory disallowance along with the
U.S. GAAP measures to illustrate the magnitude of this
disallowance on ongoing business and operational results.
Although the excluded amounts are properly included in the
determination of net income and earnings per share under
U.S. GAAP, we believe the amount and nature of such
disallowance make period to period comparisons of
operations difficult or potentially confusing. Financial
measures are expressed in cents per share as these
amounts reflect factors that directly impact earnings,
including income taxes. All references in this section to EPS
are on the basis of diluted shares (see Note 3). We use
such non-GAAP financial measures to analyze our financial
performance because we believe they provide useful
information to our investors and creditors in evaluating our
financial condition and results of operations.
24
EXECUTIVE SUMMARY
We manage our business and strategic initiatives with a
long-term view of providing natural gas service safely and
reliably to customers, working with regulators on key policy
initiatives, and remaining focused on growing our business.
See "2016 Outlook" below for more information. Highlights
for the year include:
•
steady annual customer growth rate at the core utility of
1.4% at December 31, 2015;
increased new meter sets installed to approximately
11,000, which is nearly 4% higher than the prior year;
invested $118.3 million in our distribution system and
facilities including $19.9 million on SIP, allowing us to
•
•
•
•
•
•
complete our bare steel replacement;
continued to make progress on our North Mist gas
storage expansion project;
decreased residential customer rates approximately 7%
in Oregon and 14% in Washington with the 2015-16
PGA effective November 1, 2015;
ranked first in residential customer satisfaction for large
gas utilities in the West in the 2015 J.D. Power and
Associates Study, making 2015 the 14th consecutive
year of top three rankings; and
increased our dividend, marking the 60th consecutive
year of increases.
Key financial highlights include:
In millions, except per share data
Amount
Per Share
Amount
Per Share
Amount
Per Share
2015
2014
2013
Consolidated net income
Adjustments:
$
53.7
$
1.96
$
58.7
$
2.16
$
60.5
$
2.24
Regulatory environmental disallowance, net of taxes $5.9(1)
9.1
0.33
—
—
—
—
Adjusted consolidated net income(1)
Utility margin
Gas storage operating revenues
ROE
$
$
62.8
$
2.29
$
58.7
$
2.16
371.4
21.4
6.9%
$ 366.1
22.2
7.7%
$
$
60.5
$
2.24
353.9
31.1
8.2%
Adjusted ROE(1)
(1) Regulatory environmental disallowance of $15 million is recorded in utility operations and maintenance expense. Adjusted EPS, net
8.1%
8.2%
7.7%
income, and ROE are non-GAAP financial measures based on the after-tax disallowance. EPS is calculated using the combined federal and
state statutory tax rate of 39.5% and 27.4 million diluted shares for the year ended December 31, 2015.
2015 COMPARED TO 2014. Overall, consolidated net income
decreased $5.0 million. The decrease was primarily due to
the $9.1 million after-tax charge related to the regulatory
disallowance associated with a February 2015 OPUC Order
in our SRRM docket. Under the Order, we were required to
forego collection of $15 million, pre-tax, out of the
approximate $95 million of environmental expenditures and
associated carrying costs deferred through 2012. This
charge is reflected in operations and maintenance expense.
Excluding the charge, net income increased $4.1 million
primarily due to the following factors:
•
a $5.3 million increase in utility margin primarily due to
customer growth and gas cost sharing, offset by the
effects of warmer weather;
a $0.9 million decrease in gas storage operating
revenues as storage was negatively impacted by a
decrease in storage prices between the 2013-14 and
2014-15 gas years;
a $5.8 million increase in other income, net related to
the recognition of equity earnings on deferred
regulatory asset balances as a result of the OPUC
SRRM Order;
a $5.5 million increase in operations and maintenance
expense mainly due to higher compensation and
benefits expense; and
a $1.7 million increase in depreciation and amortization
expenses due to additional utility capital expenditures.
•
•
•
•
During 2015, management implemented temporary cost
saving initiatives to mitigate the effects of warm weather and
the $15 million regulatory disallowance. These initiatives
resulted in approximately $5 million of operations and
maintenance expense savings that are not expected to be
repeated in the future.
2014 COMPARED TO 2013. Overall, consolidated net income
decreased $1.8 million. Our net income is most significantly
impacted by our utility business which had favorable results
during the year, but increases at the utility were more than
offset by declines from our gas storage segment. The
primary factors were:
•
a $12.2 million increase in utility margin primarily due to
customer growth and the rate-base return on our gas
reserves and other investments;
a $8.9 million decrease in gas storage operating
revenues as storage was negatively impacted by re-
contracting certain expiring firm storage capacity at
lower prices;
a $3.3 million increase in depreciation and amortization
expenses due to additional utility capital expenditures;
and
a $2.7 million decrease in other income, net due to
lower interest income on net deferred regulatory
balances.
•
•
•
25
2016 OUTLOOK
Our near-term outlook and long-term strategic goals for the business are aligned with delivering gas safely and reliably to our
customers, investing for profitable growth in our core gas distribution and gas storage businesses, and creating new ideas to
drive growth opportunities. Our 2016 strategy leverages our resources and our history of innovative solutions to continue
meeting the needs of customers, regulators, and shareholders. We consider the following goals critical in achieving these long-
term goals:
Deliver Gas
Ensure Safety and Reliability
Grow Our Businesses
Grow Utility Customers
Advance Regulatory Policies and Initiatives
Pursue Strategic Utility Investments
Promote Sustainable Energy Policies
Develop Non-utility Growth Initiatives
SAFETY AND RELIABILITY. Delivering natural gas safely and
reliably to customers and providing employees with a safe
work environment are our top priorities. During 2016, we will
continue to ensure our pipeline system and facilities are well
maintained, new facility improvements are planned and well
executed, and business continuity requirements are met.
Projects planned for 2016 include infrastructure investments
in high-growth areas such as Clark County, Washington,
refurbishing our LNG facilities, and continuing to prepare for
large-scale emergency events such as an earthquake. In
addition, we will remain proactive regarding investments in
computer systems and cybersecurity infrastructure.
REGULATION. Constructive regulation supports customers
receiving quality service at a reasonable cost and the
Company receiving timely cost recovery and earning a
reasonable return on shareholder investments. In 2016, we
will be evaluating our future rate case needs in Oregon and
Washington, progressing open dockets from 2015, and we
will also update our Integrated Resource Plan focusing on
investments needed to support the growth in our region.
Finally, we will work with regulators to further our shared
commitment to the environment with continued efforts
around the carbon solutions programs and providing gas to
rural communities.
ENERGY POLICIES. The Pacific Northwest is committed to
energy conservation, environmental sustainability, and
reducing carbon emissions. Natural gas is an important
clean energy resource for our region and the country. In
2016, we will continue to play an active role in shaping
energy policies and programs, which reflect the interests of
our customers, including progressing CNG transportation
initiatives and working on legislation that supports making
natural gas available to rural communities. In addition, we
are working hard with other potentially responsible parties to
make progress with the EPA on a solution to ensure the
Portland Harbor Superfund Site cleanup is done in a smart,
cost effective, and responsible way.
UTILITY CUSTOMERS. We intend to capitalize on natural gas
as a preferred energy choice in our service territory by
creating a comprehensive marketing program for rental
projects that further our penetration in the residential multi-
family housing sector. In addition, we remain focused on
supporting single-family and commercial markets to grow
our customer base. 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.
KEY UTILITY INVESTMENTS. Investing in new infrastructure,
operating efficiencies, and marketing opportunities position
our core business for growth now and well into the future.
A growth investment for our storage business is the planned
expansion at Mist to support a gas-fired plant built by
Portland General Electric (PGE) at their nearby Port
Westward facility. In early 2016, will be working closely with
the Oregon Energy Siting Facilities Council to finalize the
cost estimates and receive a notice to proceed. We expect
construction to begin in 2016 with an in-service date in the
winter of 2018-19.
NON-UTILITY INITIATIVES. We remain focused on creating
value in our non-utility gas storage business, working to
identify and contract with higher value customers and
position ourselves for longer-term improvement in the
California storage markets. We believe the state’s
renewable energy policies could strategically shift the value
of gas storage in California in the future.
26
DIVIDENDS
Dividend highlights include:
Per common share
Dividends paid
2015
2014
2013
$
1.86
$
1.85
$
1.83
The Board of Directors declared a quarterly dividend on our
common stock of $0.4675 cents per share, payable on
February 12, 2016, to shareholders of record on January
29, 2016, reflecting an indicated annual dividend rate of
$1.87 per share.
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 2015, approximately 89% of our
utility gas volumes and revenues were derived from Oregon
customers, with the remaining 11% 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. They 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 business is subject to
regulation by the OPUC, WUTC, 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 CPUC
regulate intrastate storage services, and the FERC
regulates interstate storage services. The OPUC and FERC
use 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 2015, approximately 72% of our
storage revenues were derived from FERC, Oregon, and
Washington regulated operations and approximately 28%
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. Effective January 1, 2009, 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.
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 were effective January 1,
2014, with the rate changes having no significant impact on
our revenues.
Regulatory Proceeding Updates
During 2015, we were involved in the regulatory activity
discussed below.
ENVIRONMENTAL COST DEFERRAL AND SITE REMEDIATION
AND RECOVERY MECHANISM (SRRM). In February 2015, the
OPUC issued an Order regarding the SRRM for recovering
prudently incurred environmental site remediation costs
through customer billings, subject to an earnings test. The
OPUC Order found the following: (1) prudence of all but $33
thousand of costs incurred through March 31, 2014; (2)
prudence of approximately $150 million of insurance
settlement proceeds, with one-third of the proceeds applied
to costs prior to December 31, 2012 and two-thirds to offset
future environmental expenses over the next 20 years; (3)
the disallowance of $15 million out of approximately $95
million of environmental remediation expenses we had
deferred from 2003 to 2012 based on the OPUC’s
determination of how an earnings test should have applied
during that period; which resulted in a non-cash $15 million
before tax expense recognized in the first quarter 2015; (4)
how the SRRM recovery mechanism would allow recovery
of past and future environmental costs; and (5) an OPUC
review of the SRRM following its third year of operation.
This Order also required us to submit a compliance filing
demonstrating how we would implement the Commission’s
determinations.
We submitted the required compliance filing demonstrating
the proposed implementation of the Order and SRRM. In
September 2015, the OPUC ordered we would not be
required to establish a secure account for the insurance
proceeds, rather we would defer proceeds to a regulatory
liability account until utilized, and we would accrue interest
to rate payers' benefit at a rate equal to the five-year
treasury rate plus 100 basis points. See "Rate Mechanisms
—Environmental Cost Deferral and SRRM", Note 15 and
Note 16.
On January 27, 2016, the OPUC issued an Order
addressing the remaining outstanding issues in the
compliance filing. See Note 16 regarding this subsequent
event.
27
GAS RESERVES. We filed with the OPUC in February 2015
seeking cost recovery on additional investments in gas
reserves. In September 2015, the OPUC adopted an all-
party settlement. See "Rate Mechanisms—Gas Reserves"
below and Note 11.
PREPAID PENSION ASSET. In August 2015, the OPUC issued
the final Order related to this docket, which confirmed the
use of accounting expense for recovery of pension costs,
but denied the utilities' request to recover the financing
costs associated with funding our pension plans in advance
of expense recognition. Although we will not recover the
financing costs associated with funding our plans, we will
continue collecting pension expense based on the amounts
set in our 2003 Oregon general rate case and will continue
deferring the difference between actual pension expense
and collected expense in our pension balancing account.
See "Rate Mechanisms—Pension Cost Deferral and
Pension Balancing Account" below.
SYSTEM INTEGRITY PROGRAM (SIP). We filed a request to
extend the SIP program in the fourth quarter of 2014. The
OPUC considered our renewal request at a public meeting
in March 2015 and suspended our filing and ordered
additional process, including involvement of other gas
utilities in the state, before making a final decision. See
"Rate Mechanisms—System Integrity Program" below.
HEDGING. In our most recent Integrated Resource Plan, we
proposed to the OPUC that we engage in continued long-
term gas hedging. The OPUC determined it wanted to
consider long-term hedging along with a general review of
overall hedging practices among all gas utilities in the
state. The OPUC therefore opened a new docket to discuss
broader gas hedging practices across gas utilities in
Oregon. Our request for the OPUC to consider long-term
hedging practices will be considered as part of this
docket. The OPUC established that this docket will follow
two phases. The first phase will be focused on an analytical
review of hedging and hedging practices, followed by a
second phase regarding potential hedging guidelines. After
these phases, a status report will be submitted to the
OPUC, and the remainder of the process will be determined
at that time.
INTERSTATE STORAGE SHARING. We received an Order
from the OPUC in March 2015 on their review of 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. The Order requires a third-party cost study
to be performed and the results of the cost study may
initiate a new docket or the re-opening of the original
docket.
CARBON SOLUTIONS PROGRAM. Oregon Senate Bill 844
(SB 844) required the OPUC to develop rules and programs
to reduce carbon emissions in Oregon. In June 2015, we
submitted our first project related to Combined Heat and
Power (CHP) for OPUC approval. The submitted CHP
program would pay owners of new commercial- and
industrial-scale CHP systems for verified carbon emission
reductions. A final decision regarding CHP is expected in
the first half of 2016.
WEATHER NORMALIZATION MECHANISM (WARM). In
Oregon, WARM is applied to residential and commercial
customers' bills to adjust for temperature variances from
average weather. In 2015, the OPUC initiated a review of
the WARM mechanism as a result of customer complaints
received this year related to surcharges applied under the
WARM mechanism due to the record warm weather in our
service territory during the 2014-15 winter. The OPUC
review is focused on ensuring the calculations were done
correctly, and to assess whether any modifications to the
mechanism are necessary. Based on the scope of this
proceeding established by the Commission, we do not
expect this proceeding to significantly reduce the value
WARM provides to us or our customers in mitigating the
impact from variations in weather. Since its inception,
WARM has resulted in a net benefit to customers, providing
customer bill savings of approximately $9.9 million as of the
end of the most recent heating season.
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, temporary rate adjustments, which
amortize balances of deferred regulatory accounts, and the
removal of temporary rate adjustments effective for the
previous year.
Each year, we typically hedge gas prices on approximately
75% of our utility's annual sales requirement based on
normal weather, including both physical and financial
hedges. We entered the 2015-16 gas year (November 1,
2015 - October 31, 2016) hedged at 75% of our forecasted
sales volumes, including 44% in financial swap and option
contracts and 31% in physical gas supplies. For further
discussion see "Regulatory Matters—Rate Mechanisms—
Purchased Gas Adjustment" above.
In addition to the amount hedged for the current gas
contract year, we are also hedged in future years at
approximately 16% for the 2016-17 gas year and between
5% and 14% for annual requirements over the following five
gas years as of December 31, 2015. Our hedge levels are
subject to change based on actual load volumes, which
depend to a certain extent on weather, economic conditions,
and estimated gas reserve production. Also, our storage
inventory levels may increase or decrease with storage
expansion, changes in storage contracts with third parties,
and/or storage recall by the utility.
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. For
the 2014-15 and 2015-16 gas years, we selected the 90%
and 80% deferral option, respectively. Under the
Washington PGA mechanism, we defer 100% of the higher
28
or lower actual gas costs, and those gas cost differences
are passed on to customers through the annual PGA rate
adjustment.
We filed our PGA in September 2015 and received OPUC
and WUTC approval in October 2015. PGA rate changes
were effective November 1, 2015. The rate changes
decreased the average monthly bills of residential
customers by approximately 7% and 14% in Oregon and
Washington, respectively. The decrease in Oregon reflected
customers' portion of adjustments for changes in wholesale
natural gas costs, offset by adjustments related to the
decoupling mechanism, environmental costs, and additional
annual adjustments based on ongoing orders with the
OPUC. Washington rates reflected the full effect of changes
in wholesale natural gas costs and some additional annual
adjustments based on ongoing orders with the WUTC.
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 or
refunded to customers. Under this provision, if we select the
80% deferral gas cost 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 2013-14 and 2014-15 PGA years, and we
selected the 80% deferral option for the 2015-16 PGA year.
The ROE threshold is subject to adjustment annually based
on movements in long-term interest rates. For calendar
years 2013, 2014, and 2015, the ROE threshold was
10.58%, 10.66%, and 10.60%, respectively. There were no
refunds required for 2013 and 2014. We do not expect a
refund for 2015 based on our results and anticipate filing the
2015 test in May 2016.
GAS RESERVES. In 2011 the OPUC approved the Encana
gas reserves transaction to provide long-term gas price
protection for our utility customers and determined our costs
under the agreement would be recovered, on an ongoing
basis through our annual PGA mechanism. Gas produced
from our interests is sold at then prevailing market prices,
and revenues from such sales, net of associated operating
and production costs and amortization, are credited to our
cost of gas. The cost of gas, including a carrying cost for the
rate base investment, is included in our annual Oregon PGA
filing, which allows us to recover these costs through
customer rates. Our net investment under the original
agreement earns a rate of return and provides long-term
price protection for our utility customers.
In March 2014, we amended the original gas reserves
agreement in response to Encana's sale of its interest in the
Jonah field located in Wyoming to Jonah Energy. Under the
amendment, we ended the drilling program with Encana, but
increased our working interests in our assigned sections of
the Jonah field and we retained the right to invest in new
wells with Jonah Energy.
In 2014, we elected to participate in some of the additional
wells drilled in the Jonah field under our amended gas
reserves agreement with Jonah Energy and may have the
29
opportunity to participate in more wells in the future. We
filed an application requesting regulatory deferral in Oregon
for these additional investments, which was granted in April
2015. In September 2015, the OPUC adopted an all-party
settlement, under which volumes produced under the
amended agreement are included in our Oregon PGA
beginning November 1, 2015 at a fixed rate of $0.4725 per
therm, which approximates the 10-year hedge rate plus
financing costs at the inception of the investment.
DECOUPLING. In Oregon, we have a decoupling
mechanism. 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 and
the baseline expected usage per customer was set in the
2012 Oregon general rate case. This mechanism employs a
use-per-customer decoupling calculation, 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. 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, 2015, 9% of total customers had
opted out. We do not have a weather normalization
mechanism approved for residential and commercial
Washington customers, which account for about 11% 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 complete the term of
their service election under our annual PGA tariff.
SYSTEM INTEGRITY PROGRAM (SIP). In the past, we have
had the approval of the OPUC for specific accounting
treatment and cost recovery for our SIP, which is an
integrated safety program that consolidates the bare steel
replacement program, the transmission pipeline integrity
management program, and the distribution integrity
management program related to pipeline safety rules
adopted by the U.S. Department of Transportation’s Pipeline
and Hazardous Materials Safety Administration (PHMSA).
We recorded these costs as capital expenditures,
accumulated the costs over each 12-month period, and
recovered the revenue requirement associated with these
costs, subject to audit, through rate changes effective with
the Oregon annual PGA. Our SIP costs were tracked into
rates annually, with the first $4 million of capital costs
subject to regulatory lag and annual rate-base recovery
capped at $12 million. Costs above the cap could also be
approved with written consent of the OPUC staff and other
interested parties and approval of the OPUC.
During 2013, the OPUC approved a temporary two-year
extension, beginning in November 2012, of our capital
expenditure tracking mechanism to recover capital costs
related to SIP and authorized a total increase of $13.7
million above the cap during the extension period.
Regulatory authority for SIP expired October 31, 2014,
although the bare steel replacement portion of the
mechanism remained in place until the end of 2015. We
filed a request to extend the SIP program in the fourth
quarter of 2014 and upon consideration of our request in
March of 2015, the OPUC ordered an additional process
and evaluation with other gas utilities in the state before
making a final decision. In the interim, we will recover our
remaining bare steel replacement costs through the
2015-16 PGA, and we expect system integrity capital costs
not tracked through our SIP mechanism would be included
in rate base in our next rate case.
ENVIRONMENTAL COST DEFERRAL AND SRRM. In Oregon,
we have a SRRM through which we track and have the
ability to recover prudently incurred past deferred and future
environmental remediation costs allocable to Oregon,
subject to an earnings test.
The SRRM defines three classes of deferred environmental
remediation expense:
•
Pre-review - This class of costs represents remediation
spend that has not yet been deemed prudent by the
OPUC. Carrying costs on these remediation expenses
are recorded at our authorized cost of capital. We
anticipate the prudence review for annual costs and
approval of the earnings test prescribed by the OPUC
to occur by the third quarter of the following year.
Post-review - This class of costs represents
remediation spend that has been deemed prudent and
allowed after applying the earnings test, but is not yet
included in amortization. We earn a carrying cost on
these amounts at a rate equal to the five-year treasury
rate plus 100 basis points.
Amortization - This class of costs represents amounts
included in current customer rates for collection and is
generally calculated as one-fifth of the post-review
deferred balance. We earn a carrying cost equal to the
amortization rate determined annually by the OPUC,
which approximates a short-term borrowing rate. We
•
•
included $8.4 million of deferred remediation expense
approved by the OPUC for collection during the
2015-2016 PGA year.
The earnings test is an annual review of our adjusted Utility
ROE compared to our authorized Utility ROE, which is
currently 9.5%. To apply the earnings test first we must
determine what if any costs are subject to the test through
the following calculation:
Annual spend
Less: $5 million base rate rider(1)
Prior year carry-over(2)
$5 million insurance + interest on insurance
Total deferred annual spend subject to earnings test
Less: over-earnings adjustment, if any
Add: deferred interest on annual spend(3)
Total amount transferred to post-review
(1) Base rate rider went into Oregon customer rates beginning
November 1, 2015.
(2) Prior year carry-over results when the prior year amount
transferred to post-review is negative. The negative amount is
carried over to offset annual spend in the following year.
(3) Deferred interest is added to annual spend to the extent the
spend is recoverable.
If the adjusted Utility ROE is greater than the authorized
Utility ROE, then we could be required to expense up to the
amount that results in the Utility earning its authorized ROE.
For 2015, we have performed this test, which will be
submitted to the OPUC in May 2016, and have concluded
that there is no earnings test adjustment for 2015.
The WUTC has also previously authorized the deferral of
environmental costs, if any, that are appropriately allocated
to Washington customers. This Order was effective in
January 2011 with cost recovery and a carrying charge to
be determined in a future proceeding.
PENSION COST DEFERRAL AND PENSION BALANCING
ACCOUNT. 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, including interest,
were $8.2 million, $4.6 million, and $9.1 million in 2015,
2014 and 2013, respectively. See "Application of Critical
Accounting Policies and Estimates" below.
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 net revenues earned from Mist gas
storage and asset management activities. Generally
amounts are credited to Oregon customers in June, while
credits are given to customers in Washington through
30
reductions in rates through the annual PGA filing in
November.
The following table presents the credits to customers:
In millions
Oregon utility
customer credit
Washington utility
customer credit
2015
2014
2013
$
9.6
$
11.4
$
0.8
0.8
8.8
0.5
Business Segments - Local Gas Distribution Utility
Operations
Utility margin results are primarily affected by customer
growth, revenues from rate-base additions, and, to a certain
extent, by changes in delivered volumes due to weather and
customers’ gas usage patterns because a significant portion
of our utility margin is derived from natural gas sales to
residential and commercial customers. In Oregon, we have
a conservation tariff (also called the decoupling
mechanism), which adjusts utility margin up or down each
month through a deferred regulatory accounting adjustment
designed 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
customer bills and our utility’s earnings. See "Regulatory
Matters—Rate Mechanisms" above.
Utility segment highlights include:
Dollars and therms in
millions, except EPS data
2015
2014
2013
Utility net income
$
53.4
$
58.6
$
EPS - utility segment
1.95
2.15
54.9
2.03
Gas sold and delivered
(in therms)
Utility margin(1)
353.9
(1) See Utility Margin Table below for a reconciliation and additional
1,146
1,029
371.4
1,093
366.1
$
$
$
detail.
2015 COMPARED TO 2014. The primary factors contributing
to the $5.2 million or $0.20 per share decrease in utility net
income were as follows:
•
the $15 million pre-tax charge, or $9.1 million after-tax
charge, for the regulatory disallowance associated with
the February 2015 OPUC Order on the recovery of past
environmental cost deferrals. This charge is reflected in
operations and maintenance expense;
a $5.3 million increase in utility margin primarily due to:
a $4.4 million increase from customer growth;
a $5.3 million increase from gas cost incentive
sharing resulting from lower gas prices than
those estimated in the PGA; partially offset by
•
an approximate $4.0 million decrease due to lower
customer usage from warmer weather, which
impacts utility margins from our Washington
customers where we do not have a weather
normalization mechanism in place, and from our
Oregon customers who opted out of weather
normalization.
a $6.6 million increase in other income, net, primarily
due to the recognition of the equity earnings on
deferred environmental expenditures as a result of the
February order;
a $7.2 million increase in operations and maintenance
expense, excluding the environmental disallowance,
primarily due to an increase in compensation and
benefit expense; and
a net $0.4 million increase in other expenses related to
increased depreciation expense from additional capital
investments and an increase in general taxes from
higher Oregon property tax expense, offset by a
decrease in interest expense due to debt redemptions
made during the year.
•
•
•
Total utility volumes sold and delivered in 2015 decreased
6% over 2014 primarily due to the impact of warmer
weather.
2014 COMPARED TO 2013. The primary factors contributing
to the $3.7 million or $0.12 per share increase in net income
were as follows:
•
a $12.2 million net increase in utility margin primarily
due to:
a $16.6 million increase from customer growth in
residential and commercial customers, industrial
margins, and added rate-base returns on certain
investments, including gas reserves; partially offset
by
a $2.1 million increase in loss from gas cost
incentive sharing mainly resulting from higher gas
prices and volumes than those estimated in the
PGA; and
the remaining decrease was primarily due to
warmer weather as measured by heating degree
days, in Washington, which does not have a
weather normalization mechanism in place, and
the effect of warmer weather on margin for Oregon
customers that opt out of weather normalization.
•
•
•
a $3.2 million increase in depreciation expense due to
additional capital expenditures;
a $3.0 million decrease in operations and maintenance
expense; and
a $2.1 million decrease in other income, net primarily
due to lower interest income on regulatory deferred
account balances.
Total utility volumes sold and delivered in 2014 decreased
5% over 2013 primarily due to the impact of warmer
weather on residential and commercial use.
31
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
2015
2014
2013
Utility volumes (therms):
Residential and commercial sales
Industrial sales and transportation
570,728
457,884
620,903
472,087
671,906
474,525
Total utility volumes sold and delivered
1,028,612
1,092,990
1,146,431
Favorable/(Unfavorable)
2015 vs.
2014
2014 vs.
2013
(50,175)
(14,203)
(64,378)
(51,003)
(2,438)
(53,441)
Utility operating revenues:
Residential and commercial sales
Industrial sales and transportation
Other revenues
Less: Revenue taxes
Total utility operating revenues
Less: Cost of gas
Less: Environmental remediation expense
Utility margin
Utility margin:(1)
Residential and commercial sales
Industrial sales and transportation
Miscellaneous revenues
Gain (loss) from gas cost incentive sharing
Other margin adjustments
Utility margin
Degree days
Average(2)
Actual
Percent colder (warmer) than average weather(2)
Customers - end of period:
Residential customers
Commercial customers
Industrial customers
$ 644,835
$ 672,440
$ 673,250
$ (27,605)
$
(810)
71,495
3,914
18,034
702,210
327,305
3,513
73,992
3,983
18,837
731,578
365,490
—
68,880
4,054
19,002
727,182
373,298
—
$ 371,392
$ 366,088
$ 353,884
$ 334,134
$ 334,247
$ 321,608
30,081
3,913
3,182
82
29,982
4,329
(2,135)
(335)
28,335
4,308
(41)
(326)
(2,497)
5,112
(69)
(803)
(29,368)
38,185
(3,513)
(71)
(165)
4,396
7,808
—
$
$
5,304
$ 12,204
(113)
$ 12,639
99
(416)
5,317
417
1,647
21
(2,094)
(9)
$ 371,392
$ 366,088
$ 353,884
$
5,304
$ 12,204
4,240
3,458
4,240
3,792
4,240
4,379
—
(9)%
—
(13)%
(18)%
(11)%
3%
646,841
637,411
66,584
1,003
66,304
929
628,634
65,321
918
9,430
8,777
280
74
983
11
Total number of customers
714,428
704,644
694,873
9,784
9,771
Customer growth:
Residential customers
Commercial customers
Industrial customers
Total customer growth
1.5 %
0.4 %
8.0 %
1.4 %
1.4 %
1.5 %
1.2 %
1.4 %
(1) Amounts reported as margin for each category of customers are operating revenues, which are net of revenue taxes, less cost of gas and
environmental remediation expense.
(2) Average weather represents the 25-year average degree days, as determined in our 2012 Oregon general rate case.
32
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:
2015
2014
2013
350.9
219.8
570.7
381.5
239.4
620.9
418.6
253.3
671.9
Residential sales
$
424.6
$
441.5
$
447.4
Commercial sales
220.2
230.9
225.9
Total operating
revenues
Utility margin:
Residential:
Sales
Weather normalization
Decoupling
Total residential utility
margin
Commercial:
Sales
Weather normalization
Decoupling
Total commercial utility
margin
$
644.8
$
672.4
$
673.3
$
211.6
$
223.6
$
234.1
14.0
7.2
5.1
4.0
(9.0)
2.6
232.8
232.7
227.7
84.8
5.8
10.7
91.6
2.2
7.7
92.1
(4.0)
5.8
101.3
101.5
93.9
Total utility margin
$
334.1
$
334.2
$
321.6
2015 COMPARED TO 2014. The primary factors contributing
to changes in the residential and commercial markets were
as follows:
•
sales volumes decreased 50.2 million therms, or 8%,
primarily reflecting 9% warmer weather, which was
partially offset by customer growth;
operating revenues decreased $27.6 million, due to the
8% decrease in sales volumes, as well as a 2%
decrease in average gas rates over last year; and
utility margin decreased $0.1 million, due to warmer
weather, almost entirely offset by increases from
commercial and residential customer growth.
•
•
2014 COMPARED TO 2013. The primary factors contributing
to changes in the residential and commercial markets were
as follows:
•
sales volumes decreased 51.0 million therms, or 8%,
primarily reflecting 13% warmer weather, which was
•
33
•
•
partially offset by customer growth and a record
February cold weather event;
operating revenues decreased $0.8 million, due to the
8% decrease in sales volumes, which was partially
offset by a 4% increase in average gas rates over last
year; and
utility margin increased $12.6 million, or 4%, primarily
related to customer growth, added loads under higher
commercial rate schedules, and added rate-base
returns from our gas reserves and other investments,
partially offset by the effect of warmer weather on our
Washington customers and Oregon customers that
opted out of the weather normalization mechanism.
Industrial Sales and Transportation
Industrial customers have the option of purchasing sales or
transportation services from the utility. Under the sales
service, the customer buys the gas commodity from the
utility. Under the transportation service, the customer buys
the gas commodity 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 options, 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 service election
on November 1, special charges for changes between
elections, and in some cases, a minimum or maximum
volume requirement before changing options.
Industrial sales and transportation highlights include:
In millions
Volumes (therms):
2015
2014
2013
Industrial - firm sales
32.4
34.0
34.3
Industrial - firm
transportation
Industrial - interruptible
sales
Industrial - interruptible
transportation
Total volumes
Utility margin:
Industrial - sales and
transportation
144.0
153.6
144.5
70.2
76.4
59.5
211.3
457.9
208.1
472.1
236.2
474.5
$
30.1
$
30.0
$
28.3
2015 COMPARED TO 2014. The primary factors contributing
to changes in the industrial sales and transportation markets
were as follows:
•
sales and transportation volumes decreased by 14.2
million therms due to lower usage from warmer weather
and lower demand from a few large volume
transportation customers on lower margin rate
schedules;
utility margin increased $0.1 million, primarily due to an
increase in industrial customers under higher margin
rate schedules partially offset by higher fee revenue in
the prior year from increased usage during the cold
weather event in February 2014.
2014 COMPARED TO 2013. The primary factors contributing
to changes in the industrial sales and transportation markets
were as follows:
•
sales and transportation volumes decreased by 2.4
million therms due to lower usage by large volume
interruptible transportation customers on lower margin
rate schedules;
utility margin increased $1.6 million, or 6% primarily
due to volume growth under higher margin rate
schedules and other customer charges stemming from
the extreme cold weather event in February 2014.
•
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 revenues from residential,
commercial and industrial firm customers.
Other revenue for 2015, 2014, and 2013 remained flat year-
over-year as expected.
In millions
2015
2014
2013
Other revenues
$
3.9
$
4.0
$
4.1
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, gas reserves costs, 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 which has been described under
"Regulatory Matters—Rate Mechanisms—Purchased Gas
Adjustment" above. In addition to the PGA incentive sharing
mechanism, gains and losses from hedge contracts entered
into after annual PGA rates are effective for Oregon
customers are also required to be shared and therefore may
impact net income. Further, we also have a regulatory
agreement whereby we earn a rate of return on our
investment in the gas reserves acquired under the original
agreement with Encana and include gas from our amended
gas reserves agreement at a fixed rate of $0.4725 per
therm, which are also reflected in utility margin. See
"Application of Critical Accounting Policies and Estimates—
Accounting for Derivative Instruments and Hedging
Activities" below.
Cost of gas highlights include:
Dollars and therms in
millions
2015
2014
2013
Cost of gas
$
327.3
$
365.5
$
373.3
Volumes sold (therms)
660
716
766
Average cost of gas
(cents per therm)
Gain (loss) from gas cost
incentive sharing
$
0.50
$
0.51
$
0.49
3.2
(2.1)
—
2015 COMPARED TO 2014. Cost of gas decreased $38.2
million, or 10% primarily due to an 8% decrease in sales
volume reflecting warmer weather during the year as well as
a 2% decrease in average cost of gas reflecting lower
market prices for natural gas.
2014 COMPARED TO 2013. Cost of gas decreased $7.8
million, or 2% primarily due to a 7% decrease in sales
volume reflecting warmer weather during the year, partially
offset by a 4% increase in average cost of gas collected
through rates.
During the extreme cold weather event in February 2014,
we experienced a record sendout and consequently, the
higher volumes of gas purchased at that time resulted in a
margin loss of $2.1 million in 2014 compared to a margin
gain of $3.2 million for 2015 as prices were lower due to the
record warmer weather, particularly in the first quarter of
2015. The effect on net income from our gas cost incentive
sharing mechanism for 2013 was a pre-tax loss in margin of
less than $0.1 million. 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% undivided 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 is subject to revenue sharing with core utility
customers. Under this regulatory incentive sharing
mechanism, we retain 80% of pre-tax income from Mist gas
storage services and 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. See
"Regulatory Matters—Open Regulatory Proceedings" above
for information regarding an open docket related to this
incentive sharing mechanism.
34
Our 75% undivided ownership interest in the Gill Ranch
facility is held by our wholly-owned subsidiary Gill Ranch,
LLC, which is also the operator of the facility. Our portion of
the facility is 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 provide asset management services at Gill
Ranch. See also Note 4.
Gas storage segment highlights include:
In millions, except EPS
data
Gas storage net income
(loss)
EPS - gas storage
segment
Operating revenues
Operating expenses
2015
2014
2013
$
0.2
$
(0.4) $
5.6
0.01
21.4
16.3
(0.01)
22.2
18.2
0.21
31.1
16.4
2015 COMPARED TO 2014. Our gas storage segment net
income increased $0.6 million primarily due to the following
offsetting factors:
•
a $0.9 million decrease in operating revenues, primarily
due to a decrease in storage prices between the
2013-14 and 2014-15 gas storage years; and
a $1.9 million decrease in operating expenses primarily
due to lower repair and power costs at our Gill Ranch
facility.
•
2014 COMPARED TO 2013. Our gas storage segment net
income decreased $5.9 million primarily due to the following
factors:
•
an $8.9 million decrease in operating revenues,
primarily reflecting recontracting expiring storage
capacity at lower prices as the gas storage market
prices remain at historic lows; and
a $1.8 million increase in operating expenses primarily
due to higher repair and power costs at our Gill Ranch
facility.
•
Our Mist gas storage facility benefits from limited
competition from other Pacific Northwest storage facilities
primarily because of its geographic location.
Over the past few years, market prices for natural gas
storage, particularly in California, were negatively affected
by the abundant supply of natural gas, low volatility of
natural gas prices, and surplus gas storage capacity. In
addition, storage prices were further affected by extreme
cold weather during the 2013-14 winter, which resulted in a
significant decline in storage levels, a rise in spot gas
prices, and lower storage values due to a flatter forward
price curve for the 2014-15 gas storage year. We re-
contracted certain expiring storage capacity for the 2014-15
gas storage year with shorter-term contracts at lower market
prices than in previous years. These trends accounted for
most of the decline in gas storage operating revenues.
Prices for the 2015-16 and 2016-17 gas years have shown
improvement, however remain low relative to the pricing in
our original long-term contracts, which ended primarily in
the 2013-14 gas storage year. In the future, we may see an
improvement in gas storage values and an increase in the
35
demand for natural gas driven by a number of factors,
including changes in electric generation triggered by
California's renewable portfolio standards, an increase in
use of alternative fuels to meet carbon reduction targets,
recovery of the California economy, growth of domestic
industrial manufacturing, potential exports of liquefied
natural gas from the west coast, and other favorable storage
market conditions in and around California. These factors, if
they occur, may contribute to higher summer/winter natural
gas price spreads, gas price volatility, and gas storage
values. We are continuing to explore opportunities to
increase revenues through enhanced services for storage
customers and capitalizing on opportunities that fit our
business-risk profile. Should storage values not improve in
the future, this could have a negative impact on our future
cash flows and could result in impairment of our Gill Ranch
gas storage facility. Refer to Note 2 for more information
regarding our accounting for impairment of long-lived
assets.
Other
Other primarily consists of NNG Financial's equity
investment in KB Pipeline, an equity investment in TWH,
which has invested in the Trail West pipeline project, and
other miscellaneous non-utility investments and business
activities. There were no significant changes in our other
activities in 2015. See Note 4 and Note 12 for further details
on other activities and our investment in TWH.
Consolidated Operations
Operations and Maintenance
Operations and maintenance highlights include:
In millions
2015
2014
2013
Operations and maintenance
$ 157.5
$ 137.0
$ 136.6
2015 COMPARED TO 2014. Operations and maintenance
expense increased $20.5 million, primarily due to the
following factors:
•
the $15 million pre-tax charge for the regulatory
disallowance associated with the February 2015 OPUC
Order on the recovery of past environmental cost
deferrals. We also expensed an additional $1 million
related to the Order; and
a $5.5 million increase in compensation and benefit
expense, including increased employee incentive
expense, retirement expense, and health care costs, as
well as higher wage rates under the new union labor
contract, which became effective June 1, 2014; offset
by
a $1.9 million decrease primarily related to 2014 repair
and power costs at our Gill Ranch gas storage facility.
•
•
During 2015, management implemented temporary cost
saving initiatives to mitigate the effects of warm weather and
the $15 million regulatory disallowance. These initiatives
resulted in approximately $5 million of operations and
maintenance expense savings that are not expected to be
repeated in the future.
2014 COMPARED TO 2013. Operations and maintenance
expense increased $0.4 million, primarily due to the
following factors:
•
a $2.4 million increase from additional repair and power
costs at our Gill Ranch storage facility;
a $1.5 million increase in professional service costs
related to our ongoing growth initiatives;
a $0.4 million increase in bad debt expense at the utility
due to lower comparable amounts in 2013 driven by a
decrease in our allowance for uncollectible accounts in
the first quarter of 2013; and
Partially offsetting the above factors was a $3.9 million
decrease in utility payroll and other costs.
•
•
•
Other Income, Net
Other income, net highlights include:
In millions
2015
2014
2013
Gains from company-
owned life insurance
$
Interest income
Loss from equity
investments
Net interest income on
deferred regulatory
accounts
Other non-operating
$
2.2
0.1
$
2.0
0.1
2.5
0.1
(0.1)
(0.2)
(0.1)
8.2
(2.7)
2.4
(2.4)
4.5
(2.3)
4.7
Total other income, net
$
7.7
$
1.9
$
Delinquent customer receivable balances continue to
remain at historically low levels. The utility's bad debt
expense as a percent of revenues was 0.1% for 2015 and
2014.
In addition to fluctuations in operation and maintenance
expense reported above, we have OPUC approval to defer
certain utility pension costs in excess of what is currently
recovered in customer rates. This pension cost deferral is
recorded to a regulatory balancing account, which stabilizes
the amount of operations and maintenance expense each
year. For the years ended December 31, 2015, 2014 and
2013 we deferred pension expenses totaling $8.2 million,
$4.6 million and $9.1 million, respectively. As a result,
increased pension costs had a minimal effect on operations
and maintenance expense in 2015 and 2014, with the
increase principally related to the costs allocated to our
Washington operations, which are not covered by the
pension balancing account. For further explanation of the
pension balancing account, see Note 8 and “Regulatory
Matters—Rate Mechanisms—
Pension Cost Deferral and Prepaid Pension Assets,” above
for further explanation of the pension balancing account.
Depreciation and Amortization
Depreciation and amortization highlights include:
In millions
2015
2014
2013
Depreciation and amortization
$
80.9
$
79.2
$
75.9
2015 COMPARED TO 2014. Depreciation and amortization
expense increased by $1.7 million due to utility plant
additions that included natural gas transmission and
distribution system investments and computer software.
2014 COMPARED TO 2013. Depreciation and amortization
expense increased by $3.3 million due to an increase in
utility depreciation expense from system investments,
resource center improvements, and gas storage facilities
enhancements.
2015 COMPARED TO 2014. Other income, net, increased $5.8
million primarily due to the recognition of the equity
component in interest income from our deferred
environmental expenses. We realized the equity earnings of
these deferred regulatory asset balances as a result of the
OPUC SRRM Order we received in February 2015.
2014 COMPARED TO 2013. Other income, net, decreased
$2.7 million primarily due to lower interest income on net
deferred regulatory balances as a result of insurance
proceeds credited to regulatory balances for environmental
costs. Our regulatory environmental deferred cost account
subject to interest accruals changed from a net regulatory
asset balance of $56 million at December 31, 2013 to a net
regulatory liability balance of approximately $30 million at
December 31, 2014 due to insurance proceeds received in
2014 exceeding amounts spent.
Interest Expense, Net
Interest expense, net highlights include:
In millions
2015
2014
2013
Interest expense, net
$
42.5
$
44.6
$
45.2
2015 COMPARED TO 2014. Interest expense, net of amounts
capitalized, decreased $2.1 million primarily due to the
redemption of $40 million of utility First Mortgage Bonds
(FMBs) in June 2015, $60 million of utility FMBs in 2014,
and the retirement of $20 million of Gill Ranch's debt in
June 2014. This was partially offset by the early retirement
of $20 million of Gill Ranch's debt in December 2015, which
included a make whole interest provision.
2014 COMPARED TO 2013. Interest expense, net of amounts
capitalized, decreased $0.6 million primarily due to the
redemptions of debt in 2014 of $50 million of utility FMBs in
July 2014 and $10 million in September 2014, and the
retirement of $20 million of debt pursuant to Gill Ranch's
amended loan agreement in June 2014.
36
Income Tax Expense
Income tax expense highlights include:
In millions
2015
2014
2013
Income tax expense
$ 35.8
$ 41.6
$ 41.7
Effective tax rate
40.0%
41.5%
40.8%
2015 COMPARED TO 2014. The decrease in the effective
income tax rate reflects the benefits of depletion deductions
from our gas reserves activity.
2014 COMPARED TO 2013. The increase in the effective
income tax rate was primarily the result of a $0.6 million
income tax charge in 2014 related to a higher statutory tax
rate in Oregon, which required the revaluation of deferred
tax balances.
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, and with a target utility capital structure
of 50% common stock and 50% long-term debt. When
additional capital is required, debt or equity securities are
issued depending on 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,
2015
2014
47.2%
46.1%
34.9
17.9
37.4
16.5
100.0%
100.0%
Liquidity and Capital Resources
At December 31, 2015 we had $4.2 million of cash and cash
equivalents compared to $9.5 million at December 31, 2014.
We did not have restricted cash at December 31, 2015
compared to $3.0 million in restricted cash at December 31,
2014 held as collateral for the long-term debt outstanding at
Gill Ranch, which we redeemed in December 2015. 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.
37
For the utility segment, the short-term borrowing
requirements typically peak during colder winter months
when the utility borrows money to cover the lag between
natural gas purchases and bill collections from customers.
Our short-term liquidity for the utility is primarily provided by
cash balances, internal cash flow from operations, proceeds
from the sale of commercial paper notes, as well as
available cash from multi-year credit facilities, short-term
credit facilities, company-owned life insurance policies, and
the sale of long-term debt. Utility long-term debt proceeds
are primarily used to finance utility capital expenditures,
refinance maturing debt of the utility, and provide temporary
funding for other general corporate purposes of the utility.
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 or issue letters of credit from our back-up credit
facility. In the event we are not able to issue new debt due
to adverse market conditions or other reasons, we expect
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
statement 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, 2015, we have Board authorization to issue
up to $325 million of additional FMBs. We also have OPUC
approval to issue up to $325 million of additional long-term
debt for approved purposes.
In the event 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 forms of collateral, which could expose us to
additional cash requirements and may trigger increases in
short-term borrowings while we were in a net loss position.
We were not near the threshold for posting collateral at
December 31, 2015. However, if the credit risk-related
contingent features underlying these contracts were
triggered on December 31, 2015, assuming our long-term
debt ratings dropped to non-investment grade levels, we
could have been required to post $21.2 million of collateral
to our counterparties. See "Credit Ratings" below and Note
13.
Other items that may have a significant impact on our
liquidity and capital resources include pension contribution
requirements, expiration of bonus tax depreciation,
environmental expenditures and insurance recoveries.
PENSION CONTRIBUTIONS. 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) and the Highway and Transportation Funding Act
of 2014 (HATFA). See "Application of Critical Accounting
Policies—Accounting for Pensions and Postretirement
Benefits" below.
BONUS DEPRECIATION. Regarding income tax, 50 percent
bonus depreciation was available for a large portion of our
capital expenditures in 2013, 2014 and 2015 for both federal
and Oregon. This generated an income tax net operating
loss (NOL) in 2013, and reduced taxable income in 2014
and 2015, providing cash flow benefits. The Federal
Protecting Americans From Tax Hikes Act of 2015 became
law on December 17, 2015 and extended federal bonus
depreciation through 2019.
ENVIRONMENTAL EXPENDITURES. Concerning
environmental expenditures, we expect to continue using
cash resources to fund our environmental liabilities. In 2015,
we received an Order from the OPUC regarding our SRRM
and began recovering amounts through utility rates in
November 2015. These expenditures are uncertain as to the
amount and timing. See Note 15, Note 16, and "Results of
Operations—Regulatory Matters—Environmental Costs"
above.
GAS STORAGE. Short-term liquidity for the gas storage
segment is supported by cash balances, internal cash flow
from operations, external financing, and equity contributions
from its parent company.
The amount and timing of our Gill Ranch facility's cash flows
from year to year are uncertain, as the majority of these
storage contracts are currently short-term. We have seen
slightly higher contract prices for the 2015-16 and 2016-17
storage years, but overall prices are still lower than the long-
term contracts that expired at the end of the 2013-14
storage year. While we expect continuing challenges for Gill
Ranch in 2016, we do not anticipate material changes in our
ability to access sources of cash for short-term liquidity.
In November 2011, Gill Ranch issued $40 million of senior
collateralized debt, with a fixed interest rate of 7.75% on
$20 million and a variable interest rate on the remaining $20
million, with an original maturity date of November 30, 2016.
Under the debt agreement, Gill Ranch was subject to
certain covenants and restrictions. We amended this
agreement twice, which resulted in repayment of the $20
million variable-rate outstanding debt during the second
quarter of 2014, suspension of the EBITDA covenant
requirement through the maturity date, and maintenance of
a debt reserve account, which was fixed at $4.5 million as of
June 30, 2015. In addition, under the amended agreement,
Gill Ranch was required to receive common equity
contributions from its parent NWN Gas Storage of at least
$2 million by August 31, 2015 and complied with this
requirement. On December 18, 2015, Gill Ranch repaid the
$20 million of fixed-rate senior secured debt using available
cash and cash flows from operations, including cash from
intercompany receivables.
CONSOLIDATED LIQUIDITY. Based on several factors,
including our current credit ratings, our commercial paper
program, current cash reserves, committed credit facilities,
and our expected ability to issue long-term debt in the
capital markets, we believe our liquidity is sufficient to meet
anticipated near-term cash requirements, including all
contractual obligations, investing, and financing activities
discussed below.
DIVIDEND POLICY. We have paid quarterly dividends on our
common stock each year since stock was first issued to the
public in 1951. Annual common stock dividend payments
per share, adjusted for stock splits, have increased each
year since 1956. The 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.
38
Contractual Obligations
The following table shows our contractual obligations at December 31, 2015 by maturity and type of obligation:
Payments Due in Years Ending December 31,
In millions
2016
2017
2018
2019
2020
Thereafter
Total
Short-term debt maturities
$
270.0
$
— $
— $
— $
— $
— $
Long-term debt maturities
Interest on long-term debt
Postretirement benefit payments(1)
Capital leases
Operating leases
Gas purchases(2)
Gas pipeline capacity commitments
Other purchase commitments(3)
Other long-term liabilities(4)
25.0
34.2
23.6
0.6
5.4
61.5
83.2
0.1
16.5
40.0
32.1
24.1
0.1
5.4
—
79.4
—
—
22.0
29.2
25.0
—
5.3
—
75.8
—
—
30.0
28.6
26.1
—
5.3
—
75.7
—
—
75.0
24.4
28.4
—
2.8
—
72.1
—
—
409.7
177.5
145.8
—
30.5
—
340.0
—
—
270.0
601.7
326.0
273.0
0.7
54.7
61.5
726.2
0.1
16.5
Total
$
520.1
$
181.1
$
157.3
$
165.7
$
202.7
$
1,103.5
$
2,330.4
(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
our withdrawal from the plan in December 2013. See Note 8.
(2) Gas purchases include contracts which use price formulas tied to monthly index prices. The commitment amounts presented incorporate
the December 2015 first of month index price for each supply basin from which gas is purchased. For a summary of gas purchase and gas
pipeline capacity commitments, see Note 14.
(3) Other purchase commitments primarily consist of base gas requirements and remaining balances under existing purchase orders.
(4) 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, 2015, 598 of our utility employees were
members of the Office and Professional Employees
International Union (OPEIU) Local No. 11. In May 2014, our
union employees ratified a new labor agreement (Joint
Accord) that expires on November 30, 2019. The Joint
Accord includes the following items: an average annualized
compensation increase of 4% effective June 1, 2014, which
includes a 7.9% wage increase to better reflect current
market competitive wages, offset by a reduction in bonus
pay opportunities for union employees; and a scheduled 3%
wage increase effective December 1 each year thereafter,
beginning in 2015 with the potential for up to an additional
3% per year based on wage inflation at or above 4%. The
Joint Accord also maintains competitive health benefits,
including a 15% to 20% premium cost sharing by
employees, job flexibility, and other flexibility provisions for
the Company.
Short-Term Debt
Our primary source of utility short-term liquidity is from the
sale of commercial paper and bank loans. In addition to
issuing commercial paper or bank loans 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 and bank loans are
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. In the fourth quarter of 2015, we
entered into a short-term credit facility loan totaling $50
million, as a short-term bridge through our peak heating
season, which was repaid on February 4, 2016.
At December 31, 2015 and 2014, our utility had short-term
debt outstanding of $270.0 million and $234.7 million,
respectively. The effective interest rate on short-term debt
outstanding at December 31, 2015 and 2014 was 0.6% and
0.4%, respectively.
39
Credit Ratings
Our credit ratings are a factor of our liquidity, potentially
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. 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 or reference to 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.
Maturity and Redemption of Long-Term Debt
The following debentures were retired:
In millions
Utility First Mortgage Bonds
Years Ended December 31,
2015
2014
2013
3.95% Series B due 2014
$
— $
8.26% Series B due 2014
4.70% Series B due 2015
Subsidiary Debt
Variable-rate
Fixed-rate
—
40
40
—
20
60
$
$
50
10
—
60
20
—
80
$
$
—
—
—
—
—
—
—
Credit Agreements
We have a $300 million credit agreement, with a feature that
allows the Company to request increases in the total
commitment amount, up to a maximum of $450 million. The
maturity date of the agreement is December 20, 2019.
All lenders under the agreement are major financial
institutions with committed balances and investment grade
credit ratings as of December 31, 2015 as follows:
In millions
Lender rating, by category
Loan Commitment
AA/Aa
A/A
BBB/Baa
Total
$
$
234
66
—
300
Based on credit market conditions, it is possible one or
more lending commitments could be unavailable to us if the
lender defaulted due to lack of funds or insolvency;
however, we do not believe this risk to be imminent due to
the lenders' strong investment-grade credit ratings.
Our credit agreement permits the issuance of letters of
credit in an aggregate amount of up to $100 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 credit agreement at December 31, 2015
or 2014. 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,
2015 and 2014, with consolidated indebtedness to total
capitalization ratios of 52.8% and 53.9%, 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. Rather, 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.
40
Cash Flows
Operating Activities
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
2015
2014
2013
Cash provided by operating
activities
$ 184.7
$ 215.7
$ 176.4
2015 COMPARED TO 2014. The significant factors
contributing to the $31.0 million decrease in operating cash
flows were as follows:
•
a decrease of $99.4 million in deferred environmental
recoveries, net of expenditures, reflecting the receipt of
insurance settlements during 2014;
an increase of $55.0 million from changes in deferred
gas costs balances, which reflected lower actual gas
prices than prices embedded in the PGA compared to
the prior year;
an increase of $15.0 million from regulatory
disallowance of prior environmental cost deferrals in
2015;
a decrease of $5.3 million from a non-cash recognition
of interest income on deferred environmental expenses
related to our SRRM order;
a net decrease of $3.6 million from changes in working
capital related to receivables, inventories and accounts
payable due to warmer weather in 2015 compared to
2014; and
an increase of $1.8 million from changes in regulatory
balances, other assets and liabilities, and accrued
taxes.
2014 COMPARED TO 2013. The significant factors
contributing to the $39.3 million increase in operating cash
flows were as follows:
•
an increase of $105.5 million in deferred environmental
recoveries, net of expenditures reflecting the receipt of
insurance settlements during 2014;
an increase of $41.0 million from changes in the
accounts receivable balance, primarily due to colder
weather in December 2013.
a decrease of $24.1 million from changes in inventory
balances due to refilling gas storage inventory after
colder weather in December 2013;
a decrease of $48.1 million from changes in regulatory
balances, an increase in pension liabilities, and an
increase in prepaids;
a decrease of $21.7 million in deferred taxes due to the
utilization of NOL carryforwards; and
a decrease of $17.9 million from changes in deferred
gas costs balances, which reflected higher actual gas
prices than prices embedded in the PGA compared to
the prior year.
•
•
•
•
•
•
•
•
•
•
During the year ended December 31, 2015, we contributed
$14.1 million to our utility's qualified defined benefit pension
plan, compared to $10.5 million for 2014 and $9.1 million for
2013. The amounts and timing of future contributions will
41
depend on market interest rates and investment returns on
the plans’ assets. See Note 8.
Bonus depreciation of 50% has been available for federal
and Oregon purposes in 2013, 2014 and 2015. This
generated an income tax NOL in 2013, and reduced taxable
income in 2014 and 2015, providing cash flow benefits.
Bonus depreciation for 2014 and 2015 was not enacted until
December 19, 2014 and December 17, 2015, respectively.
In both cases it was extended retroactively back to January
1 of the respective year. As a result, estimated income tax
payments were made throughout 2014 and 2015 without the
benefit of bonus depreciation for the year. This delayed the
cash flow benefit of bonus depreciation and contributed to
the income tax receivable of $7.9 million and $1.0 million as
of December 31, 2015 and 2014, respectively. As a result of
the Federal Protecting Americans From Tax Hikes Act of
2015, bonus depreciation is now available in years 2016
through 2019.
We have lease and purchase commitments relating to our
operating activities that are financed with cash flows from
operations. For information on cash flow requirements
related to leases and other purchase commitments, see
“Financial Condition—Contractual Obligations” above and
Note 14.
Investing Activities
Investing activity highlights include:
In millions
2015
2014
2013
Total cash used in investing
activities
Capital expenditures
Utility gas reserves
$ 115.3
$ 144.3
$ 182.1
118.3
1.5
120.1
26.8
138.9
54.1
2015 COMPARED TO 2014. The $29.0 million decrease in
cash used in investing activities was primarily due to lower
utility gas reserves investments compared to 2014; see
Note 11.
2014 COMPARED TO 2013. The $37.8 million decrease in
cash used in investing activities was primarily due to lower
investments in capital expenditures and utility gas reserves
as NW Natural ended its original drilling program with
Encana in 2014; see Note 11.
Over the five-year period 2016 through 2020, total utility
capital expenditures are estimated to be between $850 and
$950 million, including the Company's proposed investment
in an expansion of our Mist gas storage facility as well as
continued refurbishments of the Newport Liquefied Natural
Gas (LNG) facility in Oregon over the next three years with
an expected investment of approximately $25 million, and
upgrading distribution infrastructure in Clark County,
Washington, which could total approximately $25 million
over the next five years. The estimated level of utility capital
expenditures over the next five years reflects assumptions
for continued customer growth, technology investments,
distribution system maintenance and improvements, and
gas storage facilities maintenance. Most of the required
funds are expected to be internally generated over the five-
year period, and any remaining funding will be obtained
through a combination of long-term debt and equity security
issuances, with short-term debt and bridge financing
providing liquidity.
In 2016, utility capital expenditures are estimated to be
between $155 and $175 million, and non-utility capital
investments are estimated to be less than $5 million. Gas
storage segment capital expenditures in 2016 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
2015
2014
2013
Total cash (used in) provided
by financing activities
$
(74.7) $
(71.3) $
6.3
Change in short-term debt
Change in long-term debt
35.3
(60.0)
46.5
(80.0)
(2.1)
50.0
2015 COMPARED TO 2014. The $3.4 million increase in cash
used in financing activities was primarily due to redeeming
$20 million less debt in 2015 compared to 2014. Offsetting
this, we issued $11.2 million less of net commercial paper
and short-term loans in 2015 compared to 2014.
2014 COMPARED TO 2013. The $77.6 million decrease in
cash provided by financing activities was primarily due to
using the proceeds from our insurance settlements of $103
million to redeem $60 million of long-term utility debt. In
addition, Gill Ranch retired $20 million of variable interest
rate debt.
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 is allocated between operation and
maintenance expenses, capital expenditures, and the
deferred regulatory balancing account, totaled $20.8 million
in 2015, an increase of $6.6 million from 2014. The fair
market value of pension assets in this plan decreased to
$249.3 million at December 31, 2015 from $279.2 million at
December 31, 2014. The decrease was due to a loss on
plan assets of $9.6 million plus $14.1 million in employer
contributions, offset by benefit payments of $34.3 million.
We make contributions to the company-sponsored qualified
defined benefit pension plan based on actuarial
assumptions and estimates, tax regulations and funding
requirements under federal law. Our qualified defined
benefit pension plan was underfunded by $162.5 million at
December 31, 2015. We plan to make contributions during
2016 of $14.5 million. See Note 8 for further pension
disclosures.
Ratios of Earnings to Fixed Charges
For the years ended December 31, 2015, 2014, and 2013,
our ratios of earnings to fixed charges, computed using the
method outlined by the SEC, were 3.00, 3.13, and 3.16,
respectively. For this purpose, earnings consist of net
income before taxes plus fixed charges, and fixed charges
consist of interest on all indebtedness, the amortization of
debt expense and discount or premium and the estimated
interest portion of rentals charged to income. See Exhibit 12
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 “Application of
Critical Accounting Policies and Estimates” below. At
December 31, 2015, we had a net regulatory asset of $85.9
million for deferred environmental costs, which includes
deferred payments and interest of $51.8 million, $125.0
million for additional costs expected to be paid in the future,
and the remaining amortization to be collected in 2016 of
$6.8 million, partially offset by $96.5 million of insurance
recoveries and $1.2 million of a tariff rider collected in 2015
to be applied to deferred costs. If it is determined that future
customer rate recovery of such costs are not probable, then
the costs will be charged to expense in the period such
determination is made. See Note 15, Note 16, and "Results
of Operations—Regulatory Matters—Rate Mechanisms—
Environmental Costs" above.
New Accounting Pronouncements
For a description of recent accounting pronouncements that
may have an impact on our financial condition, results of
operations or cash flows, see Note 2.
42
APPLICATION OF CRITICAL ACCOUNTING POLICIES
AND ESTIMATES
In preparing our financial statements in accordance with
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;
• environmental contingencies; and
• impairment of long-lived assets.
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.
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 and regulatory competitive
conditions, we believe it is reasonable to expect continued
application of regulatory accounting for our utility activities.
Further, it is reasonable to expect the recovery or refund of
our regulatory assets and liabilities at December 31, 2015
through future customer rates. If we should determine 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, 2015 and 2014
was an asset of $70.7 million and $101.2 million,
respectively. See Note 2.
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
For a description of our policy regarding accrued unbilled
revenue for both the utility and non-utility revenues, see
Note 2. 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.
2015
Up 1%
Down 1%
$
0.5
$
(0.5)
—
—
—
—
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. We enter into financial derivative contracts to
hedge a portion of 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
43
variability. A small portion of our derivative hedging strategy
involves foreign currency exchange contracts.
Derivative instruments are recorded on our balance sheet at
fair value. If certain regulatory conditions are met, then the
derivative instrument fair value is recorded together with an
offsetting entry to a regulatory asset or liability account
pursuant to regulatory accounting (see Note 2, "Industry
Regulation"), and no unrealized gain or loss is recognized in
current income. The gain or loss from the fair value of a
derivative instrument subject to regulatory deferral is
included in the recovery from, or refund to, utility customers
in future periods (see "Regulatory Accounting", above). If a
derivative contract is not subject to regulatory deferral, then
the accounting treatment for unrealized gains and losses is
recorded in accordance with accounting standards for
derivatives and hedging (see Note 2, "Derivatives” and
"Industry Regulation") which is either in current income or in
accumulated other comprehensive income or loss (AOCI or
AOCL). Our derivative contracts outstanding at December
31, 2015 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.
The following table summarizes the amount of gains and
losses realized from commodity price transactions for the
last three years:
In millions
2015
2014
2013
Net utility gain (loss) on:
Commodity
Swaps
Options
$
(37.7) $
10.5
$
(11.0)
—
—
—
Total net gain (loss)
realized
$
(37.7) $
10.5
$
(11.0)
Realized gains and losses from commodity hedges shown
above were recorded as decreases or increases to cost of
gas, respectively, and were included in our annual PGA
rates.
Pensions and Postretirement Benefits
We maintain a qualified non-contributory defined benefit
pension plan, 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. The qualified defined benefit
retirement plan for union and non-union employees was
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
44
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. 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,
2015, the cumulative amount deferred for future pension
cost recovery was $43.7 million. The regulatory balancing
account includes the recognition of accrued interest on the
account balance at the utility's authorized rate of return, with
the equity portion of this interest being deferred until
amounts are collected in rates.
A number of factors, as discussed above, are considered in
developing pension and postretirement benefit assumptions.
For the December 31, 2015 measurement date, we
reviewed and updated the following key assumptions:
•
our weighted-average discount rate assumptions for
pensions went from 3.85% for 2014 to 4.21% for 2015,
and our weighted-average discount rate assumptions
for other postretirement benefits went from 3.74% for
2014 to 4.00% for 2015. 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 decreased slightly to a range of 3.25%
to 4.50%;
our expected long-term return on qualified defined
benefit plan assets, which remained unchanged at a
rate of 7.50%;
our mortality rate assumptions were updated to the new
Society of Actuaries Scale MP-2015, which projects a
mortality detriment compared to the previous table
used, thereby decreasing benefit plan liabilities; and
other key assumptions, which were based on actual
plan experience and actuarial recommendations.
•
•
•
•
At December 31, 2015, our net pension liability (benefit
obligations less market value of plan assets) for the
qualified defined benefit plan decreased $9.5 million
compared to 2014. The decrease in our net pension liability
is primarily due to the $39.4 million decrease in our pension
benefit obligation, offset by a decrease of $29.8 million in
plan assets. The liability for non-qualified plans decreased
$2.3 million, and the liability for other postretirement benefits
decreased $1.0 million in 2015.
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,
2015, the actual annualized returns on plan assets, net of
management fees, for the past one-year, five-years, and 10-
years were (3.2%), 4.7%, and 4.0%, 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
changes in certain actuarial assumptions:
Change in
Assumption
(0.25)%
Impact on
2015
Retirement
Benefit
Costs
Impact on
Retirement
Benefit
Obligations
at Dec. 31,
2015
$
1.3
$
—
0.1
14.4
1.0
1.0
(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 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
45
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 August 2014,
HATFA was signed and extends certain aspects of MAP-21
as well as modifies the phase-out periods for the limitations.
As a result we anticipate lower contributions over the next
five years with contributions increasing thereafter.
Income Taxes
Valuation Allowances
We recognize deferred tax assets to the extent that we
believe these assets are more likely than not to be realized.
In making such a determination, we consider the available
positive and negative evidence, including future reversals of
existing taxable temporary differences, projected future
taxable income, tax-planning strategies, and results of
recent operations. The most significant deferred tax asset
currently recorded is for alternative minimum tax credits. We
have determined that we are more likely than not to realize
all recorded deferred tax assets as of December 31, 2015.
See Note 9.
Uncertain Tax Benefits
The calculation of our tax liabilities involves dealing with
uncertainties in the application of complex tax laws and
regulations in the jurisdictions in which we operate. A tax
benefit from a material uncertain tax position will only be
recognized when it is more likely than not that the position,
or some portion thereof, will be sustained upon examination,
including resolution of any related appeals or litigation
processes, on the basis of the technical merits. The
Company participates in the Compliance Assurance
Process (CAP) with the Internal Revenue Service (IRS).
Under the CAP program the Company works with the IRS to
identify and resolve material tax matters before the federal
income tax return is filed each year. No reserves for
uncertain tax benefits were recorded during 2013, 2014, or
2015. See Note 9.
Regulatory Matters
Regulatory tax assets and liabilities are recorded to the
extent we believe they will be recoverable from, or refunded
to, customers in future rates. At December 31, 2015 and
2014, we have regulatory income tax assets of $47.4 million
and $51.8 million, respectively, representing future rate
recovery of deferred tax liabilities resulting from differences
in utility plant financial statement and tax basis and utility
plant removal costs. These deferred tax liabilities, and the
associated regulatory income tax assets, are currently being
recovered through customer rates. See Note 2.
Tax Legislation
When significant proposed or enacted changes in income
tax rules occur we consider whether there may be a
material impact to our financial position, results of
operations, cash flows, or whether the changes could
materially affect existing assumptions used in making
estimates of tax related balances.
The final tangible property regulations applicable to all
taxpayers were issued on September 13, 2013 and were
generally effective for taxable years beginning on or after
January 1, 2014. In addition, procedural guidance related to
the regulations was 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 2016. We will further
evaluate the effect of these regulations after this guidance is
issued, but believe our current method is materially
consistent with the new regulations and do not expect these
regulations to have a material effect on our financial
statements.
The Federal Protecting Americans From Tax Hikes Act of
2015 became law on December 17, 2015 and extended
federal bonus depreciation through 2019. See "Financial
Conditions—Cash Flows" above.
Environmental Contingencies
We account for environmental liabilities in accordance with
accounting standards under the loss contingency guidance
when it is probable that a liability has been incurred and the
amount of the loss is reasonably estimable. For a complete
discussion of our environmental policy refer to Note 2. For a
discussion of our current environmental sites and liabilities
refer to Note 15 and "Contingent Liabilities" above. In
addition, for information regarding the regulatory treatment
of these costs and our regulatory recovery mechanism, see
"Results of Operations—Rate Matters—Rate Mechanisms
—Environmental Costs" above.
Impairment of Long-Lived Assets
We review the carrying value of long-lived assets whenever
events or changes in circumstances indicate 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.
When such factors are present, we assess the recoverability
by determining whether the carrying value of the asset will
be recovered through expected future cash flows. An asset
is determined to be impaired when the carrying value of the
asset exceeds the expected undiscounted future cash flows
from the use and eventual disposition of the asset. If an
impairment is indicated, we record an impairment loss for
the difference between the carrying value and the fair value
of the long-lived assets. Fair value is estimated using
appropriate valuation methodologies, which may include an
estimate of discounted cash flows.
We determined there were no long-lived asset impairments
in 2015; however our Gill Ranch Storage facility within our
Gas Storage Segment was reviewed for impairment. The
undiscounted cash flows are in excess of the carrying value
of the asset and no impairment was indicated. The cash
flows assume a recovery of storage pricing and the ability to
contract with higher value customers. Accordingly, if
46
storage pricing does not improve and/or new higher value
customers are not obtained, future analysis may result in an
impairment of these long-lived assets.
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
and off-system storage facilities, to meet expected
requirements of our core utility customers. Our long-term
gas supply 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. Notional amounts under physical gas
contracts were $7.0 million and $4.8 million as of December
31, 2015 and 2014, respectively.
Commodity Price Risk
Natural gas commodity prices are subject to market
fluctuations due to unpredictable factors including weather,
pipeline transportation congestion, drilling technologies,
market speculation, and other factors that affect supply and
demand. We manage commodity price risk with financial
swaps and physical gas reserves from a long-term
investment in working interests in gas leases operated by
Jonah Energy. These financial hedge contracts and gas
reserves volumes are generally included in our annual PGA
filing for recovery, subject to a regulatory prudence review.
Notional amounts under financial derivative contracts were
$95.5 million and $108.4 million as of December 31, 2015
and 2014, respectively. The fair value of financial swaps as
of December 31, 2015 was an unrealized loss of $23.2
million with future cash flows of $19.8 million in 2016, $2.7
million in 2017 and $0.7 million in 2018.
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. We did not have any interest rate
swaps outstanding as of December 31, 2015 or 2014.
Foreign Currency Risk
The costs of certain pipeline and off-system storage
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-related demand and reservation charges paid in
Canadian dollars. Notional amounts under foreign currency
forward contracts were $9.0 million and $12.2 million as of
December 31, 2015 and 2014, respectively. If all of the
foreign currency forward contracts had been settled on
December 31, 2015, a loss of $0.4 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 daily or monthly market
index price tied to liquid exchange points, and we have
adequate storage flexibility, we believe it is unlikely a
supplier default would have a material adverse effect on our
financial condition or results of operations.
Credit Exposure to Financial Derivative Counterparties
Based on estimated fair value at December 31, 2015, our
overall credit exposure relating to commodity contracts is
considered immaterial as it reflects amounts owed to
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, 2015, we do not have any actual derivative
credit risk exposure for amounts financial derivative
counterparties owe to us.
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 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 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 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
Our credit exposure to insurance companies for loss or
damage claims could be material. We regularly monitor the
financial condition of insurance companies who provide
general liability insurance policy coverage to NW Natural
and its predecessors.
Weather Risk
We have a weather normalization mechanism in Oregon;
however, 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. Our weather normalization
mechanism in Oregon is 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, 2015,
approximately 9% of our Oregon customers had opted out.
In addition to the Oregon customers opting out, our
Washington residential and commercial customers account
for approximately 11% 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 20% of all residential
and commercial customers. See "Results of Operations—
Regulatory Matters—Rate Mechanism—Weather
Normalization Tariff" above.
In millions
AA/Aa
A/A
Total
$
Financial Derivative Position by Credit Rating
Unrealized Fair Value Loss
2015
2014
(20.0)
(3.2)
(23.2) $
(27.2)
(3.4)
(30.6)
47
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, 2015, 2014, and 2013
Consolidated Balance Sheets at December 31, 2015 and 2014
Consolidated Statements of Shareholders’ Equity for the Years Ended December 31, 2015, 2014, and 2013
Consolidated Statements of Cash Flows for the Years Ended December 31, 2015, 2014, and 2013
Notes to Consolidated Financial Statements
Quarterly Financial Information (Unaudited)
Supplementary Data for the Years Ended December 31, 2015, 2014, and 2013:
Financial Statement Schedule
Schedule II – Valuation and Qualifying Accounts and Reserves
Supplemental Schedules Omitted
Page
49
50
51
52
54
55
56
85
85
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.
48
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) or 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, 2015. 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 (2013).
Based on our assessment and those criteria, management has concluded that we maintained effective internal control over
financial reporting as of December 31, 2015.
The effectiveness of internal control over financial reporting as of December 31, 2015 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
Chief Executive Officer
/s/ Gregory C. Hazelton
Gregory C. Hazelton
Senior Vice President, Chief Financial Officer, and Treasurer
February 26, 2016
49
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 index present fairly, in all material respects, the
financial position of Northwest Natural Gas Company and its subsidiaries at December 31, 2015 and 2014, and the results of
their operations and its cash flows for each of the three years in the period ended December 31, 2015 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 index 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, 2015, based on criteria established in Internal
Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission
(COSO). The Company's management is responsible for these financial statements, 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 26, 2016
50
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
Environmental remediation
General taxes
Depreciation and amortization
Total operating expenses
Income from operations
Other income, 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 ($988) for 2015, $2,857
for 2014, and ($1,304) for 2013
Amortization of non-qualified employee benefit plan liability, net of taxes of ($883)
for 2015, ($438) for 2014, and ($608) for 2013
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,
2015
2014
2013
$ 723,791
$ 754,037
$ 758,518
327,305
157,521
3,513
30,281
80,923
599,543
124,248
7,747
42,539
89,456
35,753
53,703
365,490
136,982
—
29,407
79,193
611,072
142,965
1,933
44,563
373,298
136,613
—
29,956
75,905
615,772
142,746
4,669
45,172
100,335
102,243
41,643
58,692
41,705
60,538
1,561
1,353
(4,364)
1,998
646
935
$
56,617
$
54,974
$
63,471
27,347
27,417
27,164
27,223
26,974
27,027
$
$
1.96
1.96
1.86
$
2.16
2.16
1.85
2.24
2.24
1.83
See Notes to Consolidated Financial Statements
51
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,
2015
2014
$
4,211
$
68,228
57,987
(870)
69,178
2,719
70,868
17,094
7,900
—
34,748
332,063
9,534
69,818
57,963
(969)
68,562
243
77,832
20,020
1,000
23,785
34,772
362,560
3,089,380
2,992,560
906,717
870,967
2,182,663
2,121,593
114,552
370,711
27
68,066
—
8,610
129,280
368,908
—
68,238
3,000
11,366
2,744,629
2,702,385
$
3,076,692
$
3,064,945
See Notes to Consolidated Financial Statements
52
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 27,427
and 27,284 at December 31, 2015 and 2014, respectively
Retained earnings
Accumulated other comprehensive loss
Total equity
Total liabilities and equity
See Notes to Consolidated Financial Statements
As of December 31,
2015
2014
$
270,035
$
234,700
25,000
73,219
10,420
5,873
29,927
22,092
41,148
477,714
576,700
530,021
339,287
223,105
3,447
145,446
40,000
91,366
10,031
6,079
19,105
29,894
38,235
469,410
621,700
530,965
317,205
236,735
3,515
118,094
1,241,306
1,206,514
—
—
383,144
404,990
(7,162)
780,972
375,117
402,280
(10,076)
767,321
$
3,076,692
$
3,064,945
53
NORTHWEST NATURAL GAS COMPANY
CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY
In thousands
Balance at December 31, 2012
Comprehensive income
Dividends on common stock
Tax expense from employee stock plans
Stock-based compensation
Issuance of common stock
Balance at December 31, 2013
Comprehensive income (loss)
Dividends on common stock
Tax expense from employee stock plans
Stock-based compensation
Issuance of common stock
Balance at December 31, 2014
Comprehensive income
Dividends on common stock
Tax expense from employee stock plans
Stock-based compensation
Issuance of common stock
Balance at December 31, 2015
Common
Stock
Retained
Earnings
Accumulated
Other
Comprehensive
Income (Loss)
Total
Equity
$
356,571
$
382,347
$
(9,291) $
729,627
—
—
(242)
2,169
6,051
364,549
—
—
(117)
1,646
9,039
375,117
—
—
(118)
3,277
4,868
60,538
(49,204)
—
—
—
393,681
58,692
(50,093)
—
—
—
402,280
53,703
(50,993)
—
—
—
2,933
—
—
—
—
(6,358)
(3,718)
—
—
—
—
(10,076)
2,914
—
—
—
—
63,471
(49,204)
(242)
2,169
6,051
751,872
54,974
(50,093)
(117)
1,646
9,039
767,321
56,617
(50,993)
(118)
3,277
4,868
$
383,144
$
404,990
$
(7,162) $
780,972
See Notes to Consolidated Financial Statements
54
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
Qualified defined benefit pension plan expense
Contributions to qualified defined benefit pension plans
Deferred environmental (expenditures) recoveries, net
Regulatory disallowance of prior environmental cost deferrals
Interest income on deferred environmental expenses
Amortization of environmental remediation
Other
Changes in assets and liabilities:
Receivables, net
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 (used in) provided by financing activities
(Decrease) 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, net of capitalization
Income taxes paid, net of refunds
See Notes to Consolidated Financial Statements
55
Year Ended December 31,
2015
2014
2013
$ 53,703
$ 58,692
$ 60,538
80,923
17,991
26,972
5,697
79,193
19,335
24,772
4,984
75,905
11,089
46,483
5,666
(14,120)
(10,500)
(11,700)
(10,568)
88,849
(16,679)
15,000
(5,322)
3,513
3,709
2,373
6,964
(6,541)
(17,175)
(206)
—
—
—
—
—
—
1,853
(2,580)
14,948
(26,094)
(17,163)
1,709
(2,020)
(1,024)
6,933
286
7,422
1,150
31,918
(23,114)
(5,245)
(10,143)
(24,857)
23,216
184,688
215,657
176,390
(118,320)
(120,092)
(138,924)
(1,549)
(26,798)
(54,077)
410
3,000
1,161
175
1,000
1,392
8,638
—
2,231
(115,298)
(144,323)
(182,132)
3,875
—
8,986
—
(60,000)
(80,000)
5,964
50,000
—
35,335
46,500
(2,050)
(49,243)
(50,093)
(49,204)
(4,680)
3,336
(74,713)
(71,271)
(5,323)
9,534
63
9,471
$
4,211
$
9,534
$
1,580
6,290
548
8,923
9,471
$ 39,634
$ 42,602
$ 44,022
17,306
19,445
870
2. SIGNIFICANT ACCOUNTING POLICIES
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 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 and WUTC.
Accounting records and practices of our regulated
businesses conform to the requirements and uniform system
of accounts prescribed by these regulatory authorities in
accordance with U.S. GAAP. Our businesses regulated by
the OPUC, WUTC, and FERC earn a reasonable return on
invested capital from approved cost-based rates, while our
business regulated by the CPUC earns a return to the extent
we are able to charge competitive prices above our costs
(i.e. market-based rates).
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
provide 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.
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
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 facilities located in Oregon and
California. In addition, we have investments and other non-
utility activities we aggregate and report as other.
Our core utility business assets and operating activities are
largely included in the parent company, NW Natural. 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 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 Trail
West Holdings, LLC (TWH) 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 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.
Certain prior year balances in our consolidated financial
statements and notes have been reclassified to conform
with the current presentation. These reclassifications had no
effect on our prior year’s consolidated results of operations,
financial condition, or cash flows.
56
At December 31, the amounts deferred as regulatory assets
and liabilities were as follows:
In thousands
Current:
Regulatory Assets
2015
2014
Unrealized loss on derivatives(1)
$ 22,092
$ 29,889
Gas costs
Environmental costs(2)
Decoupling(3)
Other(4)
Total current
Non-current:
Unrealized loss on derivatives(1)
Pension balancing(5)
Income taxes
Pension and other postretirement
benefit liabilities
Environmental costs(2)
Gas costs
Other(4)
8,717
9,270
18,775
10,324
21,794
—
7,505
9,374
$ 69,178
$ 68,562
$
3,447
$
3,515
43,748
43,049
32,541
47,427
184,223
201,845
76,584
1,949
17,711
58,859
5,971
18,750
Total non-current
$ 370,711
$ 368,908
In thousands
Current:
Gas costs
Unrealized gain on derivatives(1)
Other(4)
Total current
Non-current:
Gas costs
Unrealized gain on derivatives(1)
Accrued asset removal costs(6)
Other(4)
Regulatory Liabilities
2015
2014
$ 14,157
$
5,700
2,659
240
13,111
13,165
$ 29,927
$ 19,105
$
8,869
$
2,507
27
—
327,047
311,238
3,344
3,460
Total non-current
$ 317,205
(1) Unrealized gains or losses on derivatives are non-cash items
and, therefore, do not earn a rate of return or a carrying
charge. These amounts are recoverable through utility rates as
part of the annual Purchased Gas Adjustment (PGA)
mechanism when realized at settlement.
$ 339,287
(2) Environmental costs relate to specific sites approved for
regulatory deferral by the OPUC and WUTC. In Oregon, we
earn a carrying charge on cash amounts paid, whereas
amounts accrued but not yet paid do not earn a carrying
charge until expended. We also accrue a carrying charge on
insurance proceeds for amounts owed to customers. In
Washington, a carrying charge related to deferred amounts will
be determined in a future proceeding. Current environmental
costs represent remediation costs management expects to
collect from customers in the next 12 months. Amounts
included in this estimate are still subject to a prudence and
earnings test review by the OPUC and do not include the $5
million base rate rider. The amounts allocable to Oregon are
recoverable through utility rates, subject to an earnings test.
See Note 15.
This deferral represents the margin adjustment resulting from
differences between actual and expected volumes.
(3)
57
(4)
(5)
These balances primarily consist of deferrals and amortizations
under approved regulatory mechanisms. The accounts being
amortized typically earn a rate of return or carrying charge.
The deferral of certain pension expenses above or below the
amount set in rates was approved by the OPUC, 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, with the equity portion of interest
income recognized when amounts are collected in rates.
(6) Estimated costs of removal on certain regulated properties are
collected through rates. See "Accounting Policies—Plant,
Property, and Accrued Asset Removal Costs" below.
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 other 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,
2015 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.
Environmental Regulatory Accounting
On February 20, 2015, the OPUC issued an Order (2015
Order) addressing outstanding implementation items related
to the Site Remediation and Recovery Mechanism (SRRM).
Under the Order, $15 million of $95 million in total
environmental remediation expenses deferred through 2012
were disallowed. The OPUC found the $95 million to be
prudent but disallowed the $15 million from rate recovery
based on its determination of how an earnings test should
apply to years between 2003 and 2012, with adjustments for
other factors the OPUC deemed relevant. We recognized the
$15 million pre-tax disallowance, or $9.1 million after-tax
charge, during the first quarter of 2015. The charge was
recorded in operations and maintenance expense. Also, as a
result of the order, we recognized $5.3 million pre-tax of
interest income related to the equity earnings on our
deferred environmental expenses.
On January 27, 2016, the OPUC issued an Order
addressing the outstanding issues. In November 2015, we
began collecting revenues from customers through the
SRRM. These collections are included in utility operating
revenues and are offset by environmental remediation
expense included in operating expense. See Note 15 and
Note 16 regarding our SRRM.
New Accounting Standards
Recently Adopted Accounting Pronouncement
PRESENTATION OF DEFERRED TAXES. On November
20, 2015, the FASB (Financial Accounting Standards Board)
issued ASU 2015-17, "Balance Sheet Classification of
Deferred Taxes." The ASU requires deferred tax liabilities
and assets to be classified as noncurrent in a classified
statement of financial position. The new requirements are
effective for us beginning January 1, 2017 and may be
applied either prospectively to all deferred tax liabilities and
assets or retrospectively to all periods presented. We have
early adopted the change in accounting principle on a
prospective basis, and it is reflected within our consolidated
balance sheet for the period ended December 31, 2015.
Prior periods were not retrospectively adjusted.
Recently Issued Accounting Pronouncements
BENEFIT PLAN ACCOUNTING. On July 31, 2015, the
FASB issued ASU 2015-12, "Plan Accounting: Defined
Benefit Pension Plans, Defined Contribution Pension Plans,
and Health and Welfare Benefit Plans." The ASU outlines a
three part update. Only part two of the update is applicable
for us, which simplifies the investment disclosure
requirements for employee benefit plans by allowing certain
disclosures at an aggregated level, reducing the number of
ways assets must be grouped and analyzed, and no longer
requiring investment strategy disclosures for certain
investments. The new requirements are effective for us
beginning January 1, 2016, with early adoption permitted.
We will be required to apply the disclosure guidance
retrospectively and do not expect the ASU to materially affect
our financial statements and disclosures.
FAIR VALUE MEASUREMENT. On May 1, 2015, the FASB
issued ASU 2015-07, "Disclosures for Investments in Certain
Entities That Calculate Net Asset Value per Share (or its
Equivalent)." The ASU removes the requirement to
categorize within the fair value hierarchy all investments for
which fair value is measured using the net asset value per
share practical expedient and also removes certain
disclosure requirements. The new requirements are effective
for us beginning January 1, 2016 with retrospective
application to all periods presented required and early
adoption permitted. We do not expect the ASU to materially
affect our financial statements and disclosures.
INTANGIBLES - GOODWILL AND OTHER - INTERNAL-
USE SOFTWARE. On April 15, 2015 the FASB issued ASU
2015-05, "Customer’s Accounting for Fees Paid in a Cloud
Computing Arrangement." The ASU provides customers
guidance on how to determine whether a cloud computing
arrangement includes a software license. The new
requirements are effective for us beginning January 1, 2016.
The ASU can be applied prospectively or retrospectively and
early adoption is permitted. We intend to apply the guidance
prospectively and do not expect the ASU to materially affect
our financial statements and disclosures.
DEBT ISSUANCE COSTS. On April 7, 2015, the FASB
issued ASU 2015-03, "Simplifying the Presentation of Debt
Issuance Costs," which requires the presentation of debt
issuance costs in the balance sheet as a direct deduction
from the associated debt liability. The new requirements are
58
effective for us beginning January 1, 2016. The new
guidance will be applied on a retrospective basis. We do not
expect the ASU to materially affect our financial statements
and disclosures.
REVENUE RECOGNITION. On May 28, 2014, the FASB
issued ASU 2014-09 "Revenue From Contracts with
Customers." The underlying principle of the guidance
requires entities to recognize revenue depicting the transfer
of goods or services to customers at amounts the entity is
expected to be entitled to in exchange for those goods or
services. The model provides a five-step approach to
revenue recognition: (1) identify the contract(s) with the
customer; (2) identify the separate performance obligations
in the contract(s); (3) determine the transaction price; (4)
allocate the transaction price to separate performance
obligations; and (5) recognize revenue when, or as, each
performance obligation is satisfied. The new requirements
prescribe either a full retrospective or simplified transition
adoption method. On August 12, 2015, the FASB deferred
the effective date by one year to January 1, 2018 for annual
reporting periods beginning after December 15, 2017. The
FASB also permitted early adoption of the standard, but not
before the original effective date of January 1, 2017. We are
currently assessing the effect of this standard on our
financial statements 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 “AFUDC” 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 U.S.
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
on which the regulated utility has the opportunity to earn its
allowed rate of return.
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,
and the gain or loss is recorded in operating income 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% for 2015, 2014, and 2013,
reflecting the approximate weighted-average economic life of
the property. This includes 2015 weighted-average
depreciation rates for the following asset categories: 2.7%
for transmission and distribution plant, 2.2% for gas storage
facilities, 4.6% for general plant, and 2.7% 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 rate was
0.4% in 2015, and 0.3% in 2014 and 2013, respectively.
IMPAIRMENT OF LONG-LIVED ASSETS. We review the
carrying value of long-lived assets whenever events or
changes in circumstances indicate the carrying amount of
the assets may 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.
When such factors are present, we assess the recoverability
by determining whether the carrying value of the asset will
be recovered through expected future cash flows. An asset
is determined to be impaired when the carrying value of the
asset exceeds the expected undiscounted future cash flows
from the use and eventual disposition of the asset. If an
impairment is indicated, we record an impairment loss for the
difference between the carrying value and the fair value of
the long-lived assets. Fair value is estimated using
appropriate valuation methodologies, which may include an
estimate of discounted cash flows.
We determined there were no long-lived asset impairments
in 2015; however our Gill Ranch Storage facility within our
Gas Storage Segment was reviewed for impairment. The
undiscounted cash flows are in excess of the carrying value
of the asset and no impairment was indicated. The cash
flows assume a recovery of storage pricing and the ability to
contract with higher value customers. Accordingly, if storage
pricing does not improve and/or new higher value customers
59
are not obtained, future analysis may result in an impairment
of these long-lived assets.
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, 2015 and 2014,
outstanding checks of approximately $2.5 million and $5.5
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
the 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, 2015 and 2014 was $58.0
million.
Non-utility revenues are derived primarily from the gas
storage segment. At our Mist underground storage facility,
revenues are primarily firm service revenues in the form of
fixed monthly reservation charges. 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 from an independent energy marketing company
that optimizes commodity, storage, 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.
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.
Revenue taxes were $18.0 million, $18.8 million, and $19.0
million for 2015, 2014, and 2013, respectively.
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. We
establish an allowance for uncollectible accounts (allowance)
for trade receivables, including accrued unbilled revenue,
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. A
specific allowance is established and recorded for large
individual customer receivables 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 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 natural gas prices. The allowance for uncollectible
accounts is adjusted quarterly, 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 injected into storage are priced in
inventory based on actual purchase costs. Utility gas
inventories 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, mainly consist
of natural gas 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, is recorded at original
cost, and classified as a long-term plant asset.
Materials 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 $59.3 million
and $68.0 million at December 31, 2015 and 2014,
respectively. At December 31, 2015 and 2014, our materials
and supplies inventories totaled $11.6 million and $9.8
million, respectively.
Gas Reserves
Gas reserves are payments to acquire and produce natural
gas reserves. Gas reserves are stated at cost, adjusted for
regulatory amortization, with the associated deferred tax
benefits recorded as liabilities 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
Derivatives are measured at fair value and recognized as
either assets or liabilities on the balance sheet. Changes in
the fair value of the derivatives are recognized currently in
earnings unless specific regulatory or 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
60
deferral under regulatory accounting. Our 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 during the PGA year
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 year in Oregon beginning
November 1, 2015, we selected the 80% deferral of gas cost
differences, and for the PGA years in Oregon beginning
November 1, 2014, and 2013, 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 on quoted prices for identical
instruments traded in active markets;
Level 2: Valuation is based on 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
market participants would use in valuing the asset or
liability.
•
•
When developing fair value measurements, it is our policy to
use quoted market prices whenever available, or to
maximize the use of observable inputs and minimize the use
of unobservable inputs when quoted market prices are not
available. Fair values are primarily developed using industry-
standard models that consider various inputs including: (a)
quoted future prices for commodities; (b) forward currency
prices; (c) time value; (d) volatility factors; (e) current market
and contractual prices for underlying instruments; (f) market
interest rates and yield curves; (g) credit spreads; and (h)
other relevant economic measures.
Income Taxes
We account for income taxes under the asset and liability
method, which requires the recognition of deferred tax
assets and liabilities for the expected future tax
consequences of events that have been included in the
financial statements. Under this method, deferred tax assets
and liabilities are determined on the basis of the differences
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. The effect of
a change in tax rates on deferred tax assets and liabilities is
recognized in income in the enactment date period unless a
regulatory Order specifies deferral of the effect of the change
in tax rates over a longer period of time.
Deferred income tax assets and liabilities are also
recognized for temporary differences where the deferred
income tax benefits or expenses have previously been
flowed through in the ratemaking process of the regulated
utility. Regulatory tax assets and liabilities are recorded on
these deferred tax assets and liabilities to the extent the
Company believes they will be recoverable from or refunded
to customers in future rates. At December 31, 2015 and
2014, regulatory income tax assets of $47.4 million and
$51.8 million, respectively, were recorded, a portion of which
is recorded in current assets. These regulatory income tax
assets primarily represent future rate recovery of deferred
tax liabilities, resulting from differences in utility plant
financial statement and tax bases and utility plant removal
costs, which were previously flowed through for rate making
purposes and to take into account the additional future
taxes, which will be generated by that recovery. These
deferred tax liabilities, and the associated regulatory income
tax assets, are currently being recovered through customer
rates.
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.
The Company recognizes interest and penalties related to
unrecognized tax benefits, if any, within income tax expense
and accrued interest and penalties within the related tax
liability line in the consolidated balance sheets. No accrued
interest or penalties for uncertain tax benefits have been
recorded. See Note 9.
Environmental Contingencies
Loss contingencies are recorded as liabilities when it is
probable 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
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, 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. See Note 15.
Subsequent Events
See Note 16 for information regarding the resolution of the
environmental SRRM docket.
61
3. EARNINGS PER SHARE
Basic earnings per share are computed using net income and the weighted average number of common shares outstanding for
each period presented. Diluted earnings per share are computed in the same manner, except it uses the weighted average
number of common shares outstanding plus the effects of the assumed exercise of stock options and the payment of estimated
stock awards from other stock-based compensation plans that are outstanding at the end of each period presented. Antidilutive
stock awards are excluded from the calculation of diluted earnings per common share. 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:
Antidilutive shares
4. SEGMENT INFORMATION
We primarily operate in two 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 are
aggregated and reported 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 the utility portion of our Mist underground storage
facility in Oregon and NWN Gas Reserves, which is a
wholly-owned subsidiary of Energy Corp. 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 TWH, which is pursuing development
of a cross-Cascades transmission pipeline project.
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 89% of our customers are located in
Oregon and 11% 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
62
2015
2014
2013
$
53,703
$
58,692
$
27,347
70
27,417
27,164
59
27,223
$
$
1.96
1.96
$
$
2.16
2.16
$
$
60,538
26,974
53
27,027
2.24
2.24
12
18
26
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
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, the results of
which are included in this business segment.
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 Mist facility also include
revenue, net of amounts shared with utility customers, from
management of utility assets at Mist and upstream capacity
when not needed to serve utility customers. We retain 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
recorded to a deferred regulatory account for crediting back
to utility customers.
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. Revenues are primarily related to firm storage
capacity as well as asset management revenues.
Other
We have non-utility investments and other business
activities, which are aggregated and reported as other.
Other primarily consists of an equity method investment in
TWH, which was formed to build and operate an interstate
gas transmission pipeline in Oregon (TWP) and other
pipeline assets in NNG Financial. For more information on
TWP, see Note 12. Other also includes some corporate
operating and non-operating revenues and expenses that
cannot be allocated to utility operations.
NNG Financial's 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 $0.7 million and $0.8 million at December
31, 2015 and 2014, respectively.
Segment Information Summary
Inter-segment transactions were insignificant for the periods presented. The following table presents summary financial
information concerning the reportable segments:
In thousands
2015
Utility
Gas Storage
Other
Total
Operating revenues
$
702,210
$
21,356
$
225
$
Depreciation and amortization
Income from operations
Net income
Capital expenditures
74,410
119,215
53,391
115,272
6,513
5,032
174
3,048
—
1
138
—
723,791
80,923
124,248
53,703
118,320
Total assets at December 31, 2015
2,800,018
261,750
14,924
3,076,692
2014
Operating revenues
$
731,578
$
22,235
$
224
$
Depreciation and amortization
Income from operations
Net income (loss)
Capital expenditures
72,660
138,711
58,587
117,322
6,533
3,987
(364)
2,770
—
267
469
—
754,037
79,193
142,965
58,692
120,092
Total assets at December 31, 2014
2,775,011
273,813
16,121
3,064,945
2013
Operating revenues
$
727,182
$
31,112
$
224
$
—
11
49
—
758,518
75,905
142,746
60,538
138,924
16,447
2,970,911
Depreciation and amortization
Income from operations
Net income
Capital expenditures
Total assets at December 31, 2013
69,420
128,066
54,920
137,466
2,644,367
6,485
14,669
5,569
1,458
310,097
63
Utility Margin
Utility margin is a financial measure consisting of utility operating revenues, which are reduced by revenue taxes, the associated
cost of gas, and environmental recovery revenues. The cost of gas purchased for utility customers is generally a pass-through
cost in the amount of revenues billed to regulated utility customers. Environmental recovery revenues represent collections
received from customers through our environmental recovery mechanism in Oregon. These collections are offset by the
amortization of environmental liabilities, which is presented as environmental remediation expense in our operating expenses.
By subtracting cost of gas and environmental remediation expense 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 gas storage segment
and other emphasize growth in operating revenues as opposed to margin because they do not incur a product cost (i.e. cost of
gas sold) like the utility and, therefore, use operating revenues and net income to assess performance.
The following table presents additional segment information concerning utility margin:
In thousands
Utility margin calculation:
Utility operating revenues (1)
Less: Utility cost of gas
Environmental remediation expense
Utility margin
2015
2014
2013
$
$
702,210
$
731,578
$
327,305
3,513
365,490
—
727,182
373,298
—
371,392
$
366,088
$
353,884
(1) Utility operating revenues include environmental recovery revenues, which are collections received from customers through our
environmental recovery mechanism in Oregon, offset by environmental remediation expense.
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, 2012
Sales to employees under ESPP
Stock-based compensation
Sales to shareholders under DRPP
Balance, December 31, 2013
Sales to employees under ESPP
Stock-based compensation
Sales to shareholders under DRPP
Balance, December 31, 2014
Sales to employees under ESPP
Stock-based compensation
Sales to shareholders under DRPP
Balance, December 31, 2015
Shares
26,917
16
42
100
27,075
24
83
102
27,284
19
78
46
27,427
5. COMMON STOCK
Common Stock
As of December 31, 2015 and 2014, we had 100 million
shares of common stock authorized. As of December 31,
2015, we had reserved 78,857 shares for issuance of
common stock under the Employee Stock Purchase Plan
(ESPP) and 297,879 shares under our Dividend
Reinvestment and Direct Stock Purchase Plan (DRPP). At
the Company's election, shares sold through our DRPP may
be purchased in the open market or through original
issuance of shares reserved for issuance under the DRPP.
In July 2015 we moved DRPP to open market purchases.
The Restated Stock Option Plan (SOP) was terminated with
respect to new grants in 2012; however, options granted
before the Restated SOP was terminated will remain
outstanding until the earlier of their expiration, forfeiture, or
exercise. There were 352,688 options outstanding at
December 31, 2015, which were granted prior to termination
of the plan.
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 2016 to repurchase up to
an aggregate of the greater of 2.8 million shares or $100
million. No shares of common stock were repurchased
pursuant to this program during the year ended December
31, 2015. 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.
64
6. STOCK-BASED COMPENSATION
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.
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, 2015. Shares
awarded under the LTIP may be purchased on the open
market or issued as original shares.
Of the 850,000 shares of common stock authorized for LTIP
awards at December 31, 2015, there were 186,979 shares
available for issuance under any type of award and 250,000
shares available for option grants. This assumes market,
performance, and service based grants currently
outstanding are awarded at the target level. There were no
outstanding grants of restricted stock or stock options under
the LTIP at December 31, 2015 or 2014. 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:
Dollars in thousands
Estimated award:
2013-2015 grant(3)
Actual award:
2012-2014 grant
2011-2013 grant
Shares(1)
Expense
During Award
Year(2)
Total
Expense
for Award
8,465
$
312
$
1,240
8,621
9,819
582
390
1,821
960
(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) Amount represents the expense recognized in the third year of
(3)
the vesting period noted above.
This represents the estimated number of shares to be
awarded as of December 31, 2015 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 2016.
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
2015
Expense
Cumulative Expense
December 31, 2015
2013-15
2014-16
2015-17
Total
34,100
39,725
43,950
117,775
68,200
$
312
$
79,450
87,900
235,550
$
632
853
1,797
1,240
1,250
853
For the 2013-2015 performance period, awards will be
based on total shareholder return (TSR factor) 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
(strategic factor). In addition to the TSR and strategic
factors, the 2014-2016 and 2015-2017 performance period
awards also included weighting for EPS and Return on
Invested Capital (ROIC) factors. Compensation expense is
recognized in accordance with accounting standards 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, 2015
and 2014 was $49.09 and $42.06 per share,
respectively. The weighted-average grant date fair value of
shares vested during the year was $46.64 per share and for
shares granted during the year was $51.78 per share. As of
December 31, 2015, there was $2.3 million of unrecognized
compensation expense related to the unvested portion of
performance awards expected to be recognized through
2017.
Restricted Stock Units
In 2012, the Company began granting RSUs under the LTIP
instead of stock options under the Restated SOP.
Generally, the RSUs awarded are forfeitable and include a
performance-based threshold as well as a vesting period of
4 years from the grant date. Upon vesting, the RSU holder
is issued 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 that portion of
the RSU. The fair value of an RSU is equal to the closing
market price of the Company's common stock on the grant
date. During 2015, total RSU expense was $1.3 million
compared to $0.9 million in 2014. As of December 31, 2015,
there was $2.6 million of unrecognized compensation cost
from grants of RSUs, which is expected to be recognized
over a period extending through 2019.
65
Information regarding the RSU activity is summarized as
follows:
Number
of
RSUs
Weighted -
Average
Price Per
RSU
Nonvested, December 31, 2012
24,864
$
Granted
Vested
Forfeited
Nonvested, December 31, 2013
Granted
Vested
Forfeited
Nonvested, December 31, 2014
Granted
Vested
Forfeited
Nonvested, December 31, 2015
25,748
(5,455)
(590)
44,567
38,765
(12,060)
(478)
70,794
37,264
(19,003)
(468)
88,587
47.57
45.38
48.01
46.58
46.27
42.19
46.52
45.47
44.00
46.29
44.81
44.99
44.78
Restated Stock Option Plan
The Restated SOP was terminated for new option grants in
2012; however, options 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.
Options under the Restated SOP were granted 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 seven
days from the date of grant. Option holders may exchange
shares they have owned for at least 6 months, valued at the
current market price, to purchase shares at the option price.
Information regarding the Restated SOP activity is
summarized as follows:
Weighted -
Average
Price Per
Share
Intrinsic
Value
(In millions)
Option
Shares
Balance outstanding,
December 31, 2012
529,925
$
42.22
$
Exercised
Forfeited
Balance outstanding,
December 31, 2013
Exercised
Forfeited
Balance outstanding,
December 31, 2014
Exercised
Forfeited
Balance outstanding
and exercisable,
December 31, 2015
(33,800)
(3,975)
492,150
(69,662)
(6,400)
416,088
(62,900)
(500)
32.16
43.72
42.89
39.82
43.59
43.40
39.96
45.74
352,688
44.00
1.3
0.3
n/a
0.6
0.5
n/a
2.7
0.5
n/a
2.3
During 2015, cash of $2.5 million was received for stock
options exercised and $0.1 million related tax expense was
recognized. During 2015, 2014, and 2013, the total fair
value of options that vested was $0.2 million, $0.4 million
and $0.5 million, respectively. The weighted average
remaining life of options exercisable and outstanding at
December 31, 2015 was 3.6 years.
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 $21,227 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
2015
2014
2013
Operations and maintenance
expense, for stock-based
compensation
$ 2,673 $ 2,309 $ 1,876
Income tax benefit
(1,012)
(861)
(765)
Net stock-based compensation
effect on net income
$ 1,661 $ 1,448 $ 1,111
Amounts capitalized for stock-based
compensation
$
661 $
597 $
331
7. DEBT
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.
In the fourth quarter of 2015, we entered into a short-term
credit facility loan totaling $50 million, as a short-term bridge
through our peak heating season, which was repaid on
February 4, 2016.
At December 31, 2015, total short-term debt outstanding
was $270 million, which includes $220 million of commercial
paper and a $50 million credit facility. At December 31, 2014
total short-term debt outstanding was $234.7 million, which
was comprised entirely of commercial paper. The weighted
average interest rate at December 31, 2015 and 2014 was
0.6% and 0.4%, respectively.
66
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, 2015, our commercial paper had
a maximum maturity of 77 days and an average maturity of
36 days.
We have a $300 million credit agreement, with a feature that
allows us to request increases in the total commitment
amount up to a maximum amount of $450 million. The
maturity of the agreement is December 20, 2019. We have
a letter of credit of $100 million. Any principal and unpaid
interest owed on borrowings under the agreement is 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, 2015 and
2014.
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,
2015 and 2014.
Long-Term Debt
The issuance of first mortgage bonds (FMBs), which
includes our medium-term notes, under the Mortgage and
Deed of Trust (Mortgage) is limited by eligible property,
adjusted net earnings and other provisions of the Mortgage.
The Mortgage constitutes a first mortgage lien on
substantially all of our utility property.
Maturities and Outstanding Long-Term Debt
Retirement of long-term debt for each of the 12-month
periods through December 31, 2020 and thereafter are as
follows:
In thousands
Year
2016
2017
2018
2019
2020
Thereafter
$
25,000
40,000
22,000
30,000
75,000
409,700
67
The following table presents our debt outstanding as of
December 31:
In thousands
First Mortgage Bonds
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 % due 2042
2015
2014
—
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
601,700
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
641,700
Subsidiary Senior Secured Debt
Gill Ranch debt due 2016
Less: Current maturities
Total long-term debt
—
601,700
25,000
$ 576,700
20,000
661,700
40,000
$ 621,700
Subsidiary Senior Secured Debt
On December 18, 2015, Gill Ranch repaid $20 million of
fixed-rate senior secured debt outstanding with an interest
rate of 7.75%, which included a make whole interest
provision using available cash and cash flows from
operations, including cash from intercompany receivables.
Retirements of Long-Term Debt
The utility redeemed $40 million of FMBs with a coupon rate
of 4.70% in June 2015.
Fair Value of Long-Term Debt
Our outstanding debt does not trade in active markets. We
estimate the fair value of our debt using utility companies
with similar credit ratings, terms, and remaining maturities to
our debt that actively trade in public markets. 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,
2015
2014
Carrying amount
$
601,700
$
Estimated fair value
667,168
661,700
756,808
8. PENSION AND OTHER POSTRETIREMENT BENEFIT COSTS
We maintain a qualified non-contributory defined benefit pension plan, 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. 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 January 1,
2007 and 2010, the qualified defined benefit retirement plans and postretirement benefits for non-union employees and union
employees, respectively, were closed to new participants. 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
Plan amendments(1)
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
Postretirement Benefit Plans
Pension Benefits
Other Benefits
2015
2014
2015
2014
$
487,278
$
391,089
$
32,072
$
28,754
8,267
18,360
—
(32,354)
(35,923)
7,213
18,198
—
90,710
(19,932)
527
1,179
(3,435)
2,724
(2,018)
483
1,252
—
3,454
(1,871)
$
445,628
$
487,278
$
31,049
$
32,072
$
279,164
$
267,062
$
(9,599)
15,696
(35,923)
19,957
12,077
(19,932)
— $
—
2,018
(2,018)
—
—
1,871
(1,871)
—
Fair value of plan assets at December 31
$
249,338
$
279,164
$
— $
Funded status at December 31
(32,072)
(1) We amended our qualified defined benefit pension plan to establish a health retirement account (HRA) plan for participants. The HRA plan
(208,114) $
(196,290) $
(31,049) $
$
permits participants to obtain reimbursement of health care expenses on a nontaxable basis, and the amendment is effective April 1, 2016.
Our qualified defined benefit pension plan has an aggregate benefit obligation of $411.8 million and $451.2 million at December
31, 2015 and 2014, respectively, and fair values of plan assets of $249.3 million and $279.2 million, respectively.
The following table presents amounts realized through regulatory assets or in other comprehensive loss (income) for the years
ended December 31:
Regulatory Assets
Other Comprehensive Loss (Income)
Pension Benefits
Other Postretirement Benefits
Pension Benefits
In thousands
2015
2014
2013
2015
2014
2013
2015
2014
2013
Net actuarial loss (gain)
$
419
$ 83,027
$ (51,892) $ 2,724
$
3,454
$
(4,283) $
(2,549) $
7,221
$
(3,302)
Amortization of:
Prior service cost
Actuarial loss
(230)
(230)
(230)
(16,372)
(9,823)
(16,744)
(197)
(554)
(197)
(221)
(197)
(733)
—
7
7
(2,236)
(1,091)
(1,550)
Total
$ (16,183) $ 72,974
$ (68,866) $ 1,973
$
3,036
$
(5,213) $
(4,785) $
6,137
$
(4,845)
68
The following table presents amounts recognized in regulatory assets and accumulated other comprehensive loss (AOCL) at
December 31:
In thousands
Prior service cost (credit)
Net actuarial loss
Total
Regulatory Assets
AOCL
Pension Benefits
Other Postretirement Benefits
Pension Benefits
2015
2014
2015
2014
2015
2014
$
$
406
$
637
$
(3,143) $
488
$
1
$
176,894
192,846
10,067
7,898
11,870
177,300
$
193,483
$
6,924
$
8,386
$
11,871
$
2
16,604
16,606
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 2016, an estimated $13.3 million will be amortized from
regulatory assets to net periodic benefit costs, consisting of
$13.5 million of actuarial losses, and $0.2 million of prior
service credits. A total of $1.3 million will be amortized from
AOCL to earnings related to actuarial losses in 2016.
Our assumed discount rate for the pension plan and other
postretirement benefit plans was determined independently
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 our 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 for the qualified pension plan 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 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
expectations. All investments are expected to satisfy the
prudent investments rule under the Employee Retirement
Income Security Act of 1974. The approved asset classes
may include cash and short-term investments, fixed income,
common stock and convertible securities, absolute and real
Year Ended December 31,
2015
2014
$
$
(10,076) $
2,549
—
2,236
4,785
(1,871)
2,914
(7,162) $
(6,358)
(7,221)
(7)
1,091
(6,137)
2,419
(3,718)
(10,076)
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. The retirement trust fund is not currently invested in
NW Natural securities.
The following table presents the pension plan asset target
allocation at December 31, 2015:
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
Target Allocation
18.0%
10.0
18.0
5.0
20.0
5.0
5.0
7.0
12.0
Our non-qualified supplemental defined benefit plan
obligations were $33.8 million and $36.1 million at
December 31, 2015 and 2014, respectively. These plans
are not subject to regulatory deferral, and the changes in
actuarial gains and losses, prior service costs and transition
assets, or obligations are recognized in AOCL, net of tax
until they are amortized as a component of net periodic
benefit cost. These are unfunded, non-qualified plans with
no plan assets; however, we indirectly fund a significant
portion of our obligations with company- and trust-owned life
insurance and other assets.
69
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, the amortization of actuarial gains and losses and
the expected returns on plan assets, which are based in
part on a market-related valuation of assets. The market-
related valuation reflects differences between expected
returns and actual investment returns with the differences
recognized over a three-year or less period from the year in
which they occur, thereby reducing year-to-year net periodic
benefit cost volatility.
The following table provides the components of net periodic benefit cost for the Company's pension and other postretirement
benefit plans for the years ended December 31:
In thousands
Service cost
Interest cost
Expected return on plan assets
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
2015
2014
2013
2015
2014
2013
$
8,267
$
7,213
$
8,698
$
527
$
483
$
18,360
(20,676)
231
18,609
24,791
(6,834)
(8,241)
18,198
16,400
1,179
1,252
(19,496)
(18,721)
223
10,914
17,052
(4,625)
(4,578)
223
18,294
24,894
(6,712)
(9,115)
—
197
554
2,457
(808)
—
—
197
221
2,153
(702)
—
656
1,157
—
197
734
2,744
(856)
—
Net amount charged to expense
$
9,716
$
7,849
$
9,067
$
1,649
$
1,451
$
1,888
(1) The deferral of defined benefit pension expenses above or below the amount set in rates was approved by the OPUC, with recovery of
these deferred amounts through the implementation of a balancing account. The balancing account includes the expectation of higher net
periodic benefit costs than costs recovered in rates in the near-term with lower net periodic benefit costs than costs recovered in rates
expected in future years. Deferred pension expense balances include accrued interest at the utility’s authorized rate of return, with the
equity portion of the interest recognized when amounts are collected in rates. See Note 2.
Net periodic benefit costs are reduced by amounts capitalized to utility plant based on approximately 25% to 35% payroll
overhead charge. In addition, a certain amount of net periodic benefit costs are recorded to the regulatory balancing account for
pensions. Net periodic pension cost less amounts charged to capital accounts and regulatory balancing accounts are expenses
recognized in earnings.
The following table provides the assumptions used in measuring periodic benefit costs and benefit obligations for the years
ended December 31:
Pension Benefits
Other Postretirement Benefits
2015
2014
2013
2015
2014
2013
Assumptions for net periodic benefit cost:
Weighted-average discount rate
3.82%
4.71%
3.84%
3.74%
4.45%
3.56%
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%
7.50%
n/a
n/a
n/a
n/a
n/a
n/a
Assumptions for year-end funded status:
Weighted-average discount rate
4.21%
3.85%
4.73%
4.00%
3.74%
4.45%
Rate of increase in compensation
3.25-4.5%
3.25-5.0%
3.25-5.0%
Expected long-term rate of return
7.50%
7.50%
7.50%
n/a
n/a
n/a
n/a
n/a
n/a
70
(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 and increases the operational
costs of running a pension plan. In 2014, the Highway and
Transportation Funding Act (HATFA) was signed and
extends certain aspects of MAP-21 as well as modifies the
phase-out periods for the limitations.
Our qualified defined benefit pension plan is currently
underfunded by $162.5 million at December 31, 2015.
Including the impacts of MAP-21 and HATFA, we made
cash contributions totaling $14.1 million to our qualified
defined benefit pension plan for 2015. During 2016, we
expect to make contributions of approximately $14.5 million
to this plan.
Multiemployer Pension Plan
In addition to the Company-sponsored defined benefit plans
presented above, prior to 2014 we contributed 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). The plan's employer identification number is
94-6076144. 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 were assessed a withdrawal liability of
$8.3 million, plus interest, which requires NW Natural to pay
$0.6 million each year to the plan for 20 years beginning in
July 2014. The cost of the withdrawal liability was deferred
to a regulatory account on the balance sheet.
We made payments of $0.6 million for 2015, and as of
December 31, 2015 the liability balance was $7.8 million.
For 2014 and 2013, contributions to the plan were $0.4
million and $0.5 million, respectively, which was
approximately 4% to 5% of the total contributions to the plan
by all employer participants in those years.
Defined Contribution Plan
The Retirement K Savings Plan is a qualified defined
contribution plan under Internal Revenue Code Section
401(k). Employer contributions totaled $3.7 million, $3.4
million, and $2.2 million for 2015, 2014, and 2013,
respectively. 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.
The assumed annual increase in health care cost trend
rates used in measuring other postretirement benefits as of
December 31, 2015 was 7.50% for both pre- and 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
4.75% by 2024.
Assumed health care cost trend rates can have a significant
effect on the amounts reported for the health care plans;
however, other postretirement benefit plans have a cap on
the amount of costs reimbursable from the Company. 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
$
100
$
(74)
742
(665)
We review mortality assumptions annually and will update
for material changes as necessary. In 2015, we adopted the
Society of Actuaries Scale MP-2015, which projects a
mortality detriment compared to the previous table used,
thereby decreasing benefit plan liabilities.
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
$
12,077
$
Employer Contributions:
2014
2015
2016 (estimated)
Benefit Payments:
2013
2014
2015
Estimated Future Benefit Payments:
2016
2017
2018
2019
2020
15,696
16,695
18,855
19,932
35,923
21,589
22,028
22,974
23,950
26,242
1,871
2,018
2,035
1,895
1,871
2,018
2,035
2,060
2,073
2,132
2,178
2021-2025
134,736
11,068
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 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 2012
the Moving Ahead for Progress in the 21st Century Act
71
Fair Value
Below 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 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 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. This is a level 2 asset
consisting of an open-end mutual fund where the NAV price
is not published but the investment can be readily disposed
of at the NAV. This asset class includes investments
primarily in common stocks in emerging markets.
FIXED INCOME. This is a level 2 asset consisting of a mutual
fund, valued at NAV, where NAV is not published, but the
investment can be readily disposed of at the 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 a commingled
trust and 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. This is a level 2 asset 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. This is a level 1 asset 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. This is a level 1 asset 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) equity
securities globally.
ABSOLUTE RETURN STRATEGY. This is a level 2 asset
consisting of a hedge fund of funds where the 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 primarily includes
investments in common stocks and fixed income securities.
REAL RETURN STRATEGY. This is a Level 1 asset
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. This is a Level 2 asset
representing mutual funds without published NAV's but the
investment can be readily disposed of at the NAV. The
mutual funds are valued at the NAV of the shares held by
the plan at the valuation date. This asset class 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 such
changes could materially affect our investment account
balances and the amounts reported as plan assets available
for benefit payments.
72
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
Long government/credit
High yield bonds
Emerging market debt
Real estate funds
Absolute 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, 2015
Level 1
Level 2
Level 3
Total
$
44,528
$
23,495
20,725
—
—
—
7,746
17,261
—
—
— $
—
22,823
11,120
48,456
12,298
—
—
36,758
4,116
— $
—
—
—
—
—
—
—
—
—
44,528
23,495
43,548
11,120
48,456
12,298
7,746
17,261
36,758
4,116
$
113,755
$
135,571
$
— $
249,326
December 31, 2014
Level 1
Level 2
Level 3
Total
$
39,405
$
122
$
— $
27,172
16,369
—
—
40,584
—
9,133
18,890
—
8,308
—
85
17,221
7,145
598
40,235
13,087
—
—
37,065
—
1,720
—
—
—
—
—
—
—
—
—
—
—
39,527
27,257
33,590
7,145
598
80,819
13,087
9,133
18,890
37,065
8,308
1,720
$
159,861
$
117,278
$
— $
277,139
December 31,
2015
2014
486
$
88
574
$
510
1,694
2,204
562
249,338
$
$
179
279,164
$
$
$
$
73
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 December 31:
Dollars in thousands
2015
2014
2013
Income taxes at federal
statutory rate
Increase (decrease):
Current state income tax,
net of federal tax benefit
Amortization of investment
tax credits
Differences required to be
flowed-through by
regulatory commissions
Gains on company and
trust-owned life insurance
Other, net
Total provision for income
taxes
$ 31,310
$ 35,117
$ 35,785
4,195
4,666
4,674
(118)
(201)
(271)
2,357
2,357
2,357
(766)
(1,225)
(689)
393
(864)
24
$ 35,753
$ 41,643
$ 41,705
Effective tax rate
40.0%
41.5%
40.8%
The decrease in the effective income tax rate for 2015
compared to 2014 was primarily due to the benefits of
depletion deductions from gas reserves activity. The
increase from 2014 compared to 2013 was primarily the
result of a $0.6 million income tax charge in 2014 related to
a higher statutory tax rate in Oregon, which required the
revaluation of deferred tax balances.
The provision (benefit) for current and deferred income
taxes consists of the following at December 31:
In thousands
Current
Federal
State
Deferred
Federal
State
2015
2014
2013
$ 10,558
$ 14,823
$
61
24
10,619
14,847
(62)
(11)
(73)
18,729
18,635
6,405
8,161
25,134
26,796
35,109
6,669
41,778
Total provision for
income taxes
$ 35,753
$ 41,643
$ 41,705
The following table summarizes the total provision (benefit)
for income taxes for the utility and non-utility business
segments for December 31:
In thousands
Utility:
Current
Deferred
Deferred investment tax
credits
Non-utility business
segments:
Current
Deferred
2015
2014
2013
$ 15,890
$ 24,317
$
(73)
20,834
19,518
38,073
(118)
(201)
(271)
36,606
43,634
37,729
(5,271)
4,418
(853)
(9,470)
7,479
(1,991)
—
3,976
3,976
Total provision for income
taxes
$ 35,753
$ 41,643
$ 41,705
The following table summarizes the tax effect of significant
items comprising our deferred income tax accounts at
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:
Pension and postretirement
obligations
Alternative minimum tax credit
carryforward
Loss and credit carryforwards
Total
2015
2014
$ 408,342
$ 386,732
47,427
46,400
49,683
51,805
55,776
48,683
$ 551,852
$ 542,996
$
4,666
$
6,537
16,699
514
21,879
16,788
12,657
35,982
Deferred income tax liabilities, net
529,973
507,014
Deferred investment tax credits
48
166
Deferred income taxes and investment
tax credits
$ 530,021
$ 507,180
Management assesses the available positive and negative
evidence to estimate if sufficient taxable income will be
generated to utilize the existing deferred tax assets. Based
upon this assessment, we have determined we are more
likely than not to realize all deferred tax assets recorded as
of December 31, 2015.
74
10. PROPERTY, PLANT, AND EQUIPMENT
The following table sets forth the major classifications of our
property, plant, and equipment and accumulated
depreciation at December 31:
In thousands
2015
2014
Utility plant in service
$2,745,485
$2,661,097
Utility construction work in progress
39,288
24,886
Less: Accumulated depreciation
867,377
836,510
Utility plant, net
Non-utility plant in service
Non-utility construction work in
progress
Less: Accumulated depreciation
1,917,396
1,849,473
296,839
297,295
7,768
39,340
9,282
34,457
Non-utility plant, net
265,267
272,120
Total property, plant, and equipment
$2,182,663
$2,121,593
Capital expenditures in accrued
liabilities
$
8,985
$
8,757
The weighted average depreciation rate was 2.8% for utility
assets and 2.2% for non-utility assets in 2015, 2014, and
2013.
Accumulated depreciation does not include the accumulated
provision for asset removal costs of $327.0 million and
$311.2 million at December 31, 2015 and 2014,
respectively. These accrued asset removal costs are
reflected on the balance sheet as regulatory liabilities. See
Note 2. During 2014, we acquired $1.3 million of equipment
under capital leases. In 2015, we did not acquire any
equipment under capital leases.
The Company estimates it has Oregon net operating loss
(NOL) carryforwards of $3.9 million at December 31, 2015.
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 NOL carryforwards before they begin to
expire in 2028. Alternative minimum tax (AMT) credits of
$16.7 million, general business credits of $0.3 million, and
charitable contribution carryforwards of $2.3 million are also
available. The AMT credits do not expire, and we anticipate
fully using the general business credits and charitable
contribution carryforwards before they begin to expire in
2033 and 2016, respectively.
As a result of certain realization requirements prescribed in
the accounting guidance for income taxes, the tax benefit of
statutory depletion is recognized no earlier than the year in
which the depletion is deductible on the Company’s federal
income tax return. Income tax expense was decreased by
$0.9 million in 2015 as a result of realizing deferred
depletion benefit from 2013 and 2014. This benefit is
included in Other in the statutory rate reconciliation table.
Uncertain tax positions are accounted for in accordance
with accounting standards that require management’s
assessment of the anticipated settlement outcome of
material uncertain tax positions taken in a prior year, or
planned to be taken in the current year. Until such positions
are sustained, we would not recognize the uncertain tax
benefits resulting from such positions. No reserves for
uncertain tax positions existed as of December 31, 2015,
2014, or 2013.
The Company’s examination by the Internal Revenue
Service (IRS) for tax years 2009 through 2011 was
completed during the first quarter of 2014. The examination
did not result in a material change to the returns as
originally filed or previously adjusted for net operating loss
carrybacks. The IRS Compliance Assurance Process (CAP)
examinations of the 2013 and 2014 tax years were
completed in the first and fourth quarters of 2015,
respectively. There were no material changes to these
returns as filed. The 2015 year is currently under IRS CAP
examination. The Company’s 2016 CAP application has
been accepted by the IRS. Under the CAP program the
Company works with the IRS to identify and resolve material
tax matters before the tax return is filed each year. As of
December 31, 2015, tax year 2012 remains open for federal
examination, and tax years 2012 through 2015 remain open
for state examination.
75
11. GAS RESERVES
We have invested $188 million through our gas reserves
program in the Jonah Field located in Wyoming as of
December 31, 2015. Gas reserves are stated at cost, net of
regulatory amortization, with the associated deferred tax
benefits recorded as liabilities on the balance sheet. Our
investment in gas reserves provides long-term price
protection for utility customers and currently incorporates
two agreements: the original agreement with Encana Oil &
Gas (USA) Inc. under which we invested $178 million and
the amended agreement with Jonah Energy LLC under
which an additional $10 million was invested.
We entered into our original agreements with Encana in
2011 under which we hold working interests in certain
sections of the Jonah Field. Gas produced in these sections
is sold at prevailing market prices, and revenues from such
sales, net of associated operating and production costs and
amortization, are credited to the utility's cost of gas. The
cost of gas, including a carrying cost for the rate base
investment, is included in our annual Oregon PGA filing,
which allows us to recover these costs through customer
rates. Our net investment under the original agreement
earns a rate of return.
In March 2014, we amended the original gas reserves
agreement in order to facilitate Encana's proposed sale of
its interest in the Jonah field to Jonah Energy. Under the
amendment, we ended the drilling program with Encana,
but increased our working interests in our assigned
sections of the Jonah field. We also retained the right to
invest in new wells with Jonah Energy. The amended
agreements allow us to invest in additional wells on a well-
by-well basis with drilling costs and resulting gas volumes
shared at our amended proportionate working interest for
each well in which we invest. We elected to participate in
some of the additional wells drilled in 2014, and may have
the opportunity to participate in more wells in the future.
In September 2015, the OPUC adopted an all-party
settlement, under which volumes produced from the
additional wells drilled in 2014 are included in our Oregon
PGA beginning November 1, 2015 at a fixed rate of
$0.4725 per therm, which approximates the 10-year hedge
rate plus financing costs at the inception of the investment.
Gas reserves acted to hedge the cost of gas
for approximately 11% and 10% of our utility's gas supplies
for the years ended December 31, 2015 and 2014,
respectively.
The following table outlines our net gas reserves
investment at December 31:
In thousands
2015
2014
Gas reserves, current
$
17,094
$
20,020
Gas reserves, non-current
170,453
167,190
Less: Accumulated amortization
55,901
37,910
Total gas reserves(1)
Less: Deferred taxes on gas reserves
Net investment in gas reserves(1)
131,646
149,300
27,203
18,551
$ 104,443
$ 130,749
(1) Our investment in additional wells included in total gas
reserves was $8.0 million ($4.3 million net of deferred taxes)
and $9.2 million ($8.4 million net of deferred taxes) at
December 31, 2015 and December 31, 2014, respectively.
Our investment is included on our balance sheet under gas
reserves with our maximum loss exposure limited to our
current investment balance.
12. INVESTMENTS
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
2015
2014
Investments in life insurance policies
$ 52,308
$ 52,366
Investments in gas pipeline
Other
13,866
13,962
1,892
1,910
Total other investments
$ 68,066
$ 68,238
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.
Investments in Gas Pipeline
TWP, a wholly-owned subsidiary of TWH, is pursuing the
development of a new gas transmission pipeline that would
provide an interconnection with our utility distribution
system. NWN Energy, a wholly-owned subsidiary of NW
Natural owns 50% of TWH, and 50% is owned by
TransCanada American Investments Ltd., an indirect wholly-
owned subsidiary of TransCanada Corporation.
76
VIE Analysis
TWH is a VIE, with our investment in TWP reported under
equity method accounting. We have determined we are not
the primary beneficiary of TWH’s activities as we only have
a 50% share of the entity and there are no stipulations that
allow us a disproportionate influence over it. Our
investments in TWH and TWP are included in other
investments on our balance sheet. If we do not develop this
investment, then our maximum loss exposure related to
TWH is limited to our equity investment balance, less our
share of any cash or other assets available to us as a 50%
owner. Our investment balance in TWH was $13.4 million at
December 31, 2015 and 2014.
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. If it is determined 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, TWP 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.
TWP 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.
Our equity investment was not impaired at December 31,
2015 as the fair value of expected cash flows from planned
development exceeded our remaining equity investment of
$13.4 million at December 31, 2015. 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 $13.4 million based on the current amount of
our equity investment, net of cash and working capital at
TWP. We will continue to monitor and update our
impairment analysis as required.
13. DERIVATIVE INSTRUMENTS
We enter into financial derivative contracts to hedge a
portion of 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.
We enter into these financial derivatives, up to prescribed
limits, primarily 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 third-
party asset management of our gas portfolio, some of which
are derivatives that do not qualify for hedge accounting or
regulatory deferral, but are subject to our regulatory sharing
agreement. These derivatives are recognized in operating
revenues in our gas storage segment, net of amounts
shared with utility customers.
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,
2015
2014
346,875
287,475
404,645
420,980
$ 9,025
$ 12,230
Purchased Gas Adjustment (PGA)
Derivatives entered into by the utility for the procurement or
hedging of natural gas for future gas years generally receive
regulatory deferral accounting treatment. Derivative
contracts entered into after the start of the PGA period are
subject to our PGA incentive sharing mechanism in Oregon.
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 reflected in our weighted-average cost of
gas in the PGA filing. As of November 1, 2015, we reached
our target hedge percentage of approximately 75% for the
2015-16 gas year. These hedge prices were included in the
PGA filings and qualified for regulatory deferral.
77
Unrealized and Realized Gain/Loss
The following table reflects the income statement presentation for the unrealized gains and losses from our derivative
instruments:
In thousands
Expense to cost of gas
Operating revenues
Less:
Amounts deferred to regulatory accounts on balance sheet
December 31, 2015
December 31, 2014
Natural gas
commodity
Foreign
exchange
Natural gas
commodity
Foreign
exchange
$
(22,600) $
226
(419) $
—
(32,784) $
—
22,434
419
32,782
(382)
—
382
—
Total gain (loss) in pre-tax earnings
$
60
$
— $
(2) $
UNREALIZED GAIN/LOSS. Outstanding derivative instruments related to regulated utility operations are deferred in accordance
with regulatory accounting standards. 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.
REALIZED GAIN/LOSS. We realized net losses of $37.7 million and net gains of $10.5 million for the years ended December
31, 2015 and 2014, respectively, from the settlement of natural gas financial derivative contracts. Realized gains and losses are
recorded in cost of gas, deferred through our regulatory accounts, and amortized through customer rates in the following year.
Credit Risk Management of Financial Derivatives
Instruments
No collateral was posted with or by our counterparties as of
December 31, 2015 or 2014. 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
Our financial derivative instruments are subject to master
netting arrangements; however, they are presented on a
gross basis in 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 a
defaulting party, a credit change due to a merger affecting
either party, or any other termination event.
credit limits and portfolio diversification, we have not been
subject to collateral calls in 2015 or 2014. 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 commodity financial swap and option
contracts outstanding, which reflect unrealized losses of
$23.2 million at December 31, 2015, we have estimated the
level of collateral demands, with and without potential
adequate assurance calls, using current gas prices and
various credit downgrade rating scenarios for NW Natural as
follows:
Credit Rating Downgrade Scenarios
(Current
Ratings)
A+/A3
BBB+/
Baa1
BBB/
Baa2
BBB-/
Baa3
Specul-
ative
$
— $ — $ — $4,852
$ 21,185
—
—
— 4,164
15,497
In thousands
With
Adequate
Assurance
Calls
Without
Adequate
Assurance
Calls
If netted by counterparty, our derivative position would result
in an asset of $2.7 million and a liability of $25.5 million as
of December 31, 2015. As of December 31, 2014, our
derivative position would have resulted in an asset of $0.2
million and a liability of $33.4 million.
We are exposed to derivative credit and liquidity risk
primarily through securing fixed price natural gas commodity
swaps to hedge the risk of price increases for our natural
gas purchases made on behalf of customers. We utilize
master netting arrangements through International Swaps
and Derivatives Association contracts to minimize this risk
along with collateral support agreements with counterparties
based on their credit ratings. In certain cases we require
guarantees or letters of credit from counterparties 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 use 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
78
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 $5.5 million, $5.9 million, and $5.1 million for the
years ended December 31, 2015, 2014, and 2013,
respectively. The following table reflects the future minimum
lease payments due under non-cancelable leases at
December 31, 2015. These commitments relate principally
to the lease of our office headquarters, underground gas
storage facilities and computer equipment.
In thousands
Operating
leases
Capital
leases
$
5,417
$
564
$
5,363
5,348
5,313
2,765
30,475
156
3
—
—
—
Minimum
lease
payments
5,981
5,519
5,351
5,313
2,765
30,475
$
54,681
$
723
$
55,404
2016
2017
2018
2019
2020
Thereafter
Total
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.
consideration of credit ratings, credit default swap spreads,
bond market credit spreads, financial condition, government
actions and market news. We use a Monte-Carlo simulation
model to estimate the change in credit and liquidity risk from
the volatility of natural gas prices. The results of the model
are used to establish earnings-at-risk trading limits. Our
credit risk for all outstanding financial derivatives at
December 31, 2015 extends to March 2018.
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; however, we would expect such
a loss to be eligible for regulatory deferral and rate recovery,
subject to a prudence review. All of our existing
counterparties currently have investment-grade credit
ratings.
Fair Value
In accordance with fair value accounting, we include non-
performance 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 models
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, 2015. As of December 31, 2015 and 2014,
the net fair value was a liability of $22.8 million and a liability
of $33.2 million, respectively, using significant other
observable, or level 2, inputs. No level 3 inputs were used in
our derivative valuations, and there were no transfers
between level 1 or level 2 during the years ended December
31, 2015 and 2014. See Note 2.
79
The aggregate amounts of these agreements were as
follows at December 31, 2015:
In thousands
2016
2017
2018
2019
2020
Thereafter
Total
Less: Amount
representing
interest
Total at present
value
Gas
Purchase
Agreements
Pipeline
Capacity
Purchase
Agreements
Pipeline
Capacity
Release
Agreements
$
61,464
$
79,487
$
3,739
—
—
—
—
—
61,464
79,370
75,796
75,683
72,091
340,027
722,454
—
—
—
—
—
3,739
123
110,899
11
$
61,341
$
611,555
$
3,728
Our total payments for fixed charges under capacity
purchase agreements were $85.2 million for 2015, $94.3
million for 2014, and $98.2 million for 2013. Included in the
amounts were reductions for capacity release sales of $4.4
million for 2015, $4.8 million for 2014, and $4.5 million for
2013. 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
Refer to Note 15 for a discussion of environmental
commitments and contingencies.
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
(PRPs). When amounts are prudently expended related to
site remediation, we have a recovery mechanism in place to
collect 96.68% of remediation costs from Oregon
customers, and we are allowed to defer environmental
remediation costs allocated to customers in Washington
annually until they are reviewed for prudence at a
subsequent proceeding.
Our sites are subject to the remediation process prescribed
by the Environmental Protection Agency (EPA) and the
Department of Environmental Quality (ODEQ). The process
begins with a remedial investigation (RI) to determine the
nature and extent of contamination and then a risk
assessment (RA) to establish whether the contamination at
the site poses unacceptable risks to humans and the
environment. Next, a feasibility study (FS) or an engineering
evaluation/cost analysis (EE/CA) evaluates various remedial
alternatives. It is at this point in the process when we are
able to estimate a range of remediation costs and record a
reasonable potential remediation liability, or make an
adjustment to our existing liability. From this study, the
regulatory agency selects a remedy and issues a Record of
Decision (ROD).
After the ROD is issued, we negotiate a consent decree or
consent judgment for designing and implementing the
remedy. We have the ability to further refine estimates of
remediation liabilities at that time.
Remediation may include treatment of contaminated media
such as sediment, soil and groundwater, removal and
disposal of media, or institutional controls such as legal
restrictions on future property use. Following construction of
the remedy, the EPA and ODEQ also have requirements for
ongoing maintenance, monitoring and other post-
remediation care that may continue for many years. Where
appropriate and reasonably known, we will provide for these
costs in our remediation liabilities described above.
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 where a range of
potential loss is available. Unless there is an estimate within
the 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 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 addition to
remediation costs, we could also be subject to Natural
Resource Damages (NRD) claims. We will assess the
likelihood and probability of each claim and recognize a
liability if deemed appropriate. As of December 31, 2015,
we have not received any material NRD claims.
80
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
PORTLAND HARBOR SITE. The Portland Harbor is an
EPA listed Superfund site that is approximately 10 miles
long on the Willamette River and is adjacent to NW
Natural's Gasco uplands and the Siltronic uplands sites. We
are a PRP to the Superfund site and have joined with some
of the other PRPs (the Lower Willamette Group or LWG) to
develop a Portland Harbor Remedial Investigation/
Feasibility Study (RI/FS), which we submitted to the EPA in
2012. In August 2015, the EPA issued its own Draft
Feasibility Study (Draft FS) for comment. The EPA Draft FS
provides a new range of remedial costs for the entire
Portland Harbor Superfund Site, which includes the Gasco/
Siltronic Sediment site, discussed below. The range of
present value costs estimated by the EPA for various
remedial alternatives for the entire Portland Harbor, as
provided by the EPA's Draft FS, is $791 million to $2.45
billion. The range provided in the EPA's Draft FS is based
on cost alternatives the EPA estimates to have an accuracy
between -30% and +50% of actual costs, depending on the
scope of work. While the EPA's Draft FS provides a higher
range of costs than the LWG's submission in 2012, our
potential liability is still 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 PRPs. We are participating in a non-
binding allocation process in an effort to settle this potential
liability. The new EPA Draft FS does not provide any
additional clarification around allocation of costs.
We manage our liability related to the Superfund site as two
distinct remediation projects, the Gasco/Siltronic Sediments
and Other Portland Harbor projects.
Current Liabilities
Non-Current Liabilities
2015
2014
2015
2014
$
2,229
$
1,767
$
42,641
$
38,019
1,972
10,599
951
25
1,155
—
1,934
9,535
957
171
1,020
—
5,073
52,117
337
—
7,748
179
4,338
37,117
348
—
122
179
$
16,931
$
15,384
$
108,095
$
80,123
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 uplands and
Siltronic uplands sites. We submitted a draft 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 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 range from
$44.9 million to $350 million. We have recorded a liability of
$44.9 million for the sediment clean-up, which reflects the
low end of the range. 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. NW Natural also incurs costs
related to natural resource damages from these sites. The
Company and 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
recorded a liability for these claims which is at the low end
of the range of the potential liability; the high end of the
range cannot be reasonably estimated at this time. This
liability is not included in the range of costs provided in the
draft FS for the Portland Harbor or noted above.
81
GASCO UPLANDS SITE. A predecessor of NW Natural
owned 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
noted above. We manage the Gasco site in two parts, the
uplands portion and the groundwater source control action.
We submitted a revised Remedial Investigation Report for
the uplands to ODEQ in May 2007. In March 2015, ODEQ
approved the RA NW Natural submitted in 2010, enabling us
to begin work on the FS in 2016. 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; the
high end of the range cannot be reasonably estimated at
this time.
In September 2013, we completed construction of 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 at this time
due to the uncertainty associated with the duration of
running the water treatment station, which is highly
dependent on the remedy determined for both the upland
portion as well as the final remedy for our Gasco sediment
exposure.
Beginning November 1, 2013, capital asset costs of $19.0
million for the Gasco water treatment station were placed
into rates with OPUC approval. The OPUC deemed these
costs prudent. Beginning November 1, 2014, the OPUC
approved the application of $2.5 million from insurance
proceeds plus interest to reduce the total amount of Gasco
capital costs to be recovered through rate base. A portion of
these proceeds was noncash in 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 remediation and in the case of the
Oregon Steel Mills site, pending litigation, liabilities for each
of these sites have been recognized at their respective low
end of the range of potential liability; the high end of the
range could not be reasonably estimated at this time.
Siltronic Upland. A portion of the Siltronic property adjacent
to the Gasco site was formerly owned by Portland Gas and
Coke, NW Natural's predecessor. 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
82
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 (the
former Portland Gas Manufacturing site, or PGM). At
ODEQ’s request, we conducted a sediment and source
control investigation and provided findings to ODEQ. In
December 2015, we completed a FS on the former Portland
Gas Manufacturing site. The FS provided a range of $7.6
million to $12.9 million for remedial costs. We have recorded
a liability at the low end of the range of possible loss as no
alternative in the range is considered more likely than
another. Further, we have recognized an additional liability
of $1.3 million for additional studies and design costs as well
as regulatory oversight throughout the clean-up that will be
required to assist in ODEQ making a remedy selection and
completing a design.
Oregon Steel Mills site. Refer to the “Legal Proceedings,”
below.
Site Remediation and Recovery Mechanism
We have a SRRM through which we track and have the
ability to recover past deferred and future prudently incurred
environmental remediation costs allocable to Oregon,
subject to an earnings test.
REGULATORY ACTIVITIES. An Order from the OPUC in
February 2015 deemed certain environmental remediation
expenses and associated carrying costs deferred through
March 31, 2014 prudent. Our settlement with insurance
carriers resulting in insurance proceeds received was also
deemed prudent in the Order. Under the Order, we were
required to forgo the collection of $15 million out of
approximately $95 million of environmental remediation
expenses and associated carrying costs we had deferred
through 2012. The OPUC disallowed this amount from rate
recovery based on its determination of how an earnings test
should apply to amounts deferred from 2003 to 2012, with
adjustments for other factors the OPUC deemed relevant.
See Note 2 for information regarding the regulatory
disallowance of past deferred costs under the Order
received from the OPUC in February 2015.
We submitted the required compliance filing demonstrating
the proposed implementation of the Order and SRRM in
March 2015. In September 2015, as a result of discussions
with the parties, we withdrew our original compliance filing
and submitted a revised filing. The parties raised three
issues with our proposed implementation of the Order. First,
the parties asserted that interest on the $15 million charge
should be separately disallowed, in addition to the specified
$15 million. This interest would total approximately $2.8
million. Second, the parties raised issues with how the state
allocation rates from the Order are applied to our
environmental remediation sites. Third, a customer group
disagreed with our treatment of expenses put into the
SRRM amortization account.
In addition, we requested clarification from the OPUC
regarding the amount of Oregon-allocated insurance
proceeds to be held in a secured account. In September
2015, the OPUC resolved the issue by adopting an all-party
settlement, which provided that we did not need to obtain a
secured account. Instead, under the order, insurance
proceeds used to offset future environmental expenses will
accrue interest at a rate equal to the five-year treasury rate
plus 100 basis points. Currently, Oregon-allocated insurance
proceeds total approximately $93 million on a pre-tax basis.
On January 27, 2016, the OPUC issued an Order
addressing the outstanding issues. See Note 16 regarding
this subsequent event.
COLLECTIONS FROM CUSTOMERS. The SRRM provides
us with the ability to recover past deferred and future
prudently incurred environmental remediation costs
allocable to Oregon, subject to an earnings test. The SRRM
created three classes of deferred environmental remediation
expense:
• Pre-review - This class of costs represents remediation
spend that has not yet been deemed prudent by the
OPUC. Carrying costs on these remediation expenses are
recorded at our authorized cost of capital. The Company
anticipates the prudence review for annual costs and
approval of the earnings test prescribed by the OPUC to
occur by the third quarter of the following year.
• Post-review - This class of costs represents remediation
spend that has been deemed prudent and allowed after
applying the earnings test, but is not yet included in
amortization. We earn a carrying cost on these amounts
at a rate equal to the five-year treasury rate plus 100
basis points.
• Amortization - This class of costs represents amounts
included in current customer rates for collection and is
generally calculated as one-fifth of the post-review
deferred balance. We earn a carrying cost equal to the
amortization rate determined annually by the OPUC,
which approximates a short-term borrowing rate. We
included $8.4 million of deferred remediation expense
approved by the OPUC for collection during the
2015-2016 PGA year.
In addition to the collection amount noted above, the Order
also provides for the annual collection of $5 million from
Oregon customers through a tariff rider. As we collect
amounts from customers, we recognize these collections as
revenue and separately amortize our deferred regulatory
asset balance through operating expense.
We received total environmental insurance proceeds of
approximately $150 million as a result of settlements from
our litigation that was dismissed in July 2014. Under the
OPUC Order, one-third of the Oregon allocated proceeds
were applied to costs deferred through 2012, and the
remaining two-thirds will be applied to costs over the next 20
years. Annually, the Order provided for the application of $5
million of insurance proceeds against deferred remediation
expense deemed prudent in the same annual period; annual
amounts not utilized are carried forward to apply against
future prudently incurred costs. We accrue interest on the
insurance proceeds in the customer’s favor at a rate equal
to the five-year treasury rate plus 100 basis points. As of
December 31, 2015, we have applied $53.2 million of
insurance proceeds to prudently incurred remediation costs.
83
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
Total regulatory asset deferral(1)
Current regulatory assets(2)
2015
2014
$ 124,325
$ 113,740
85,854
9,270
76,584
58,859
—
58,859
Long-term regulatory assets
(1)
Includes cash paid, remaining liability and interest, net of
insurance reimbursement, amounts collected from customers,
and amounts reclassified to utility plant for the water treatment
station.
(2) Environmental costs relate to specific sites approved for
regulatory deferral by the OPUC and WUTC. In Oregon, we
earn a carrying charge on cash amounts paid, whereas
amounts accrued but not yet paid do not earn a carrying
charge until expended. We also accrue a carrying charge on
insurance proceeds for amounts owed to customers. In
Washington, a carrying charge related to deferred amounts will
be determined in a future proceeding. Current environmental
costs represent remediation costs management expects to
collect from customers in the next 12 months. Amounts
included in this estimate are still subject to a prudence and
earnings test review by the OPUC and do not include the $5
million base rate rider. The Oregon amounts are recoverable
through utility rates, subject to an earnings test.
ENVIRONMENTAL EARNINGS TEST. The Order directed
us to implement an annual environmental earnings test for
our prudently incurred remediation expense. Prudently
incurred Oregon allocated annual remediation expense and
interest in excess of the $5 million tariff rider and $5 million
insurance proceeds application plus interest on the
insurance proceeds are recoverable through the SRRM, to
the extent the utility earns at or below our authorized Return
On Equity (ROE). To the extent the utility earns more than
its authorized ROE in a year, the utility is required to cover
environmental expenses and interest on expenses greater
than the $10 million (plus interest from insurance proceeds)
with those earnings that exceed its authorized ROE.
Under the Order, the OPUC will revisit the deferral and
amortization of future remediation expenses, as well as the
treatment of remaining insurance proceeds three years from
the original Order, or earlier if the Company gains greater
certainty about its future remediation costs, to consider
whether adjustments to the mechanism may be appropriate.
WASHINGTON DEFERRAL. 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. Annually, we
review all regulatory assets for recoverability or more often if
circumstances warrant. If we should determine 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 a
determination is made.
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, we do not
expect that the ultimate disposition of any of these matters
will have a material effect on our financial condition, results
of operations or cash flows. 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 Evraz
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 the ultimate disposition of this
matter will have a material effect on our financial condition,
results of operations or cash flows. For additional
information regarding other commitments and
contingencies, see Note 14.
16. SUBSEQUENT EVENT
On January 27, 2016, the Public Utility Commission of
Oregon (OPUC) issued an Order (2016 OPUC Order)
deciding the three issues raised as a result of our required
Site Remediation Recovery Mechanism (SRRM) compliance
filing. The OPUC ordered: (1) the disallowance of $2.8
million of interest earned on the previously disallowed
environmental expenditures amounts; (2) the allocation of
96.68% of environmental remediation costs for all
environmental sites to Oregon; and (3) our treatment of
$13.8 million of expenses put into the SRRM amortization
account was correct and in compliance with prior OPUC
orders.
Under a prior OPUC order we were required to forgo
collection of $15 million out of approximately $95 million of
environmental remediation expenses and associated
carrying costs that the Company had deferred through 2012
based on the OPUC’s determination of how an earnings test
should apply to amounts deferred from 2003 to 2012, with
adjustments for other factors the OPUC deemed relevant.
We recognized interest of approximately $2.8 million on the
$15 million charge after that time. This interest is shown as
a regulatory asset in our financial statements, and the
disallowance will result in a $2.8 million pre-tax charge in
the first quarter of 2016. Consistent with our accounting
policy for recognition of regulatory actions, we recognize the
financial impacts in the period in which the order was
received.
With respect to allocation of 96.68% of environmental
remediation costs to Oregon, we currently have a deferral
order in Washington to defer environmental costs and
insurance proceeds; however, recovery of those costs has
not yet been determined. We have deferred costs for certain
sites that only served Oregon customers and have, as a
result of this order, determined it appropriate to reserve
against 3.32% of these deferrals until resolution of recovery
in Washington can be determined. The total reserve amount
is approximately $0.5 million and will be recorded in the first
quarter of 2016 in accordance with the Company’s policy.
Consistent with our compliance filing filed in September
2015, the OPUC also ordered the same allocation factors
should be applied to insurance proceeds, resulting in the
application of 96.68% of the Company’s recovered
insurance proceeds to Oregon.
With respect to a third issue raised in the proceeding by a
customer group that the Company should not be allowed to
apply and recover portions of the SRRM amounts in 2013,
2014, and 2015 because that would constitute retroactive
ratemaking, the OPUC ordered in the Company’s favor.
The OPUC ordered our treatment of $13.8 million of
expenses put into the SRRM amortization account, to be
amortized over five years, was correct and complied with
the original order. For more information regarding our
SRRM, see Note 15.
84
NORTHWEST NATURAL GAS COMPANY
QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
Quarter ended
In thousands, except share data
March 31
June 30
September 30
December 31
2015
Operating revenues
Net income (loss)
Basic earnings (loss) per share(1)
Diluted earnings (loss) per share(1)
2014
Operating revenues
Net income (loss)
Basic earnings (loss) per share(1)
Diluted earnings (loss) per share(1)
$
261,665
$
138,280
$
93,128
$
28,486
1.04
1.04
2,197
0.08
0.08
(6,685)
(0.24)
(0.24)
$
293,386
$
133,169
$
87,199
$
37,884
1.40
1.40
1,071
0.04
0.04
(8,733)
(0.32)
(0.32)
230,718
29,705
1.08
1.08
240,283
28,470
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.
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)
2015
Reserves deducted in balance sheet from
assets to which they apply:
Allowance for uncollectible accounts
2014
Reserves deducted in balance sheet from
assets to which they apply:
Allowance for uncollectible accounts
2013
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
969
$
760
$
— $
859
$
870
1,656
$
599
$
— $
1,286
$
969
2,518
$
199
$
— $
1,061
$
1,656
85
ITEM 9. CHANGES IN AND DISAGREEMENTS
WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None.
ITEM 9A. CONTROLS AND PROCEDURES
(a) Evaluation of Disclosure Controls and Procedures
Our management, under the supervision and with the
participation of our Chief Executive Officer and Chief
Financial Officer, has completed an evaluation of the
effectiveness of the design and operation of our disclosure
controls and procedures (as defined in Rules 13a-15(e) and
15d-15(e) of the Securities Exchange Act of 1934, as
amended (the Exchange Act)). Based upon this evaluation,
our Chief Executive Officer and Chief Financial Officer have
concluded that, as of the end of the period covered by this
report, our disclosure controls and procedures were
effective to ensure that information required to be disclosed
by us and included in our reports filed or submitted under
the Exchange Act is recorded, processed, summarized and
reported within the time periods specified in the Securities
and Exchange Commission (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.
(b) Changes in Internal Control Over Financial Reporting
Our management is responsible for establishing and
maintaining adequate internal control over financial
reporting, as such term is defined in the Exchange Act Rule
13a-15(f).
There have been no changes in our internal control over
financial reporting that occurred during the quarter ended
December 31, 2015 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
On February 24, 2016, the Organization and Executive
Compensation Committee of the Company’s Board of
Directors approved, and the Company entered into, an
amendment to the Long Term Incentive Award Agreement
dated February 25, 2015 between the Company and Gregg
S. Kantor, Chief Executive Officer of the Company. The
amendment changes the minimum age to qualify for a pro-
rated payment on retirement under the agreement from 60
to 55. The Company has previously announced that Mr.
Kantor intends to retire as an employee of the Company on
December 31, 2016, which is four months before his 60th
birthday. Accordingly, the effect of the amendment will be to
make Mr. Kantor eligible for a pro rata payout of his
2015-2017 performance share award upon his planned
retirement. Assuming retirement on December 31, 2016, the
pro-rated target number of shares of Company common
stock under this award will be 9,500 shares, and the award
can payout between 0% and 200% of target based on
Company performance. The same change was made in the
agreement for Mr. Kantor’s 2016-2018 performance share
award granted on February 24, 2016. Assuming retirement
on December 31, 2016, the pro-rated target number of
shares of Company common stock under this award will be
2,525 shares, and this award also can payout between 0%
and 200% of target based on Company performance.
86
PART III
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
The "Information Concerning Nominees and Continuing Directors", "Corporate Governance", and "Section 16(a) Beneficial
Ownership Reporting Compliance" contained in our definitive Proxy Statement for the May 26, 2016 Annual Meeting of
Shareholders is hereby incorporated by reference.
Name
Gregg S. Kantor
Age at
Dec. 31, 2015
58
David H. Anderson
Gregory C. Hazelton
Lea Anne Doolittle
MardiLyn Saathoff
David R. Williams
Grant M. Yoshihara
C. Alex Miller
Ngoni Murandu
Shawn M. Filippi
Kimberly A. Heiting
Thomas J. Imeson
Margaret D. Kirkpatrick
Brody J. Wilson
David A. Weber
54
51
60
59
62
60
58
41
43
46
65
60
36
56
Positions held during last five years
Chief Executive Officer (2009- ); President (2009-2015); President and Chief
Operating Officer (2007-2008); Executive Vice President (2006-2007); Senior Vice
President, Public and Regulatory Affairs (2003-2006).
President and Chief Operating Officer (2016- ); Executive Vice President and Chief
Operating Officer (2014-2015); Executive Vice President Operations and Regulation
(2013-2014); Senior Vice President and Chief Financial Officer (2004-2013).
Senior Vice President, Chief Financial Officer and Treasurer (2016- ); Senior Vice
President and Chief Financial Officer (2015-2016); Vice President of Finance,
Treasurer and Controller, Hawaiian Electric Industries, Inc. (2013-2015); Managing
Director, UBS Investment Bank, Global Power and Utilities Group; Associate
Director, UBS Investment Bank, Global Power and Utilities Group (2011-2013);
Executive Director, UBS Investment Bank, Global Power and Utilities Group
(2008-2011).
Senior Vice President and Chief Administrative Officer (2013- ); Senior Vice
President (2008-2013); Vice President, Human Resources (2000-2007).
Senior Vice President, General Counsel and Regulation (2016- )Senior Vice
President and General Counsel (2015-2016); Vice President Legal, Risk and
Compliance (2013-2014); Deputy General Counsel (2010-2013); Chief Governance
Officer and Corporate Secretary (2008-2014).
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 (2013-2016); Vice President, Finance and
Regulation (2009-2013); Assistant Treasurer (2008-2013); General Manager of
Rates and Regulatory Affairs (2002-2009).
Vice President and Chief Information Officer (2016- ); Chief Information Officer
(2014-2016); Vice President and Chief Information Officer, NANA Development
Corporation (2010-2014).
Vice President, Chief Compliance Officer and Corporate Secretary (2016- ); Vice
President and Corporate Secretary (2015-2016); Senior Legal Counsel (2011-2014);
Assistant Corporate Secretary (2010-2014); Associate Legal Counsel (2005-2010).
Vice President, Communications and Chief Marketing Officer (2015- ); Chief
Marketing & Communications Officer (2013-2014); Chief Corporate Communications
Officer (2011-2013); Communications Director (2005-2011).
Vice President of Public Affairs (2014- ); Director of Public Affairs, Port of Portland
(2006-2014).
Senior Vice President, Environmental Policy and Affairs (2015); Senior Vice
President and General Counsel (2013-2014); Vice President and General Counsel
(2005-2013).
Chief Accounting Officer, Controller and Assistant Treasurer (2016- ); Controller
(2013-2015); 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 26, 2016. 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.
87
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 26,
2016 Annual Meeting of Shareholders is hereby incorporated by reference. Information related to Executive Officers as of
December 31, 2015 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, 2015 (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(3)
Restated Stock Option Plan
Employee Stock Purchase Plan
Equity compensation plans not approved by security holders:
Executive Deferred Compensation Plan (EDCP)(4)
Directors Deferred Compensation Plan (DDCP)(4)
Deferred Compensation Plan for Directors and Executives (DCP)(5)
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))
117,775
88,587
—
352,688
$
20,726
1,251
48,370
149,485
778,882
n/a
n/a
—
44.00
40.51
n/a
n/a
n/a
393,210
393,210
643,210
—
58,131
n/a
n/a
n/a
701,341
(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, 2015, the number of shares shown in column (a) would increase by 117,775 shares and the number of shares shown in
column (c) would decrease by the same amount of shares.
The aggregate 393,210 shares are available for future issuance under the LTIP as Restricted Stock Units, Performance Share Awards, or
stock options. An additional 250,000 shares are available for LTIP Stock Option Issuance at December 31, 2015, but those additional
shares are not available for issuance of LTIP Restricted Stock Units or Performance Share Awards.
(2)
(3) Shares balance includes 393,210 shares available for future issuance under the LTIP as Restricted Stock Units, Performance Share
Awards, or stock options; and an additional 250,000 shares available for LTIP Stock Option Issuance only at December 31, 2015, and are
not available for issuance of LTIP Restricted Stock Units or Performance Share Awards.
(4) 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.
(5) 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.
88
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 26, 2016
Annual Meeting of Shareholders is incorporated herein by reference.
ITEM 13. CERTAIN RELATIONSHIPS AND
RELATED TRANSACTIONS, AND DIRECTOR
INDEPENDENCE
The information captioned "Transactions with Related
Persons" and "Corporate Governance" in the Company’s
definitive Proxy Statement for the May 26, 2016 Annual
Meeting of Shareholders is hereby incorporated by
reference.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND
SERVICES
The information captioned "2015 and 2014 Audit Firm Fees"
in the Company’s definitive Proxy Statement for the May 26,
2016 Annual Meeting of Shareholders is hereby
incorporated by reference.
89
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 92.
90
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
Chief Executive Officer
Date: February 26, 2016
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons
on behalf of the registrant and in the capacities and on the date indicated.
Signature
Title
Date
/s/ Gregg S. Kantor
Gregg S. Kantor
Chief Executive Officer
/s/ Gregory C. Hazelton
Gregory C. Hazelton
Senior Vice President, Chief Financial Officer and
Treasurer
/s/ Brody J. Wilson
Brody J. Wilson
Chief Accounting Officer, Controller and Assistant
Treasurer
Principal Executive Officer and Director
February 26, 2016
Principal Financial Officer
February 26, 2016
Principal Accounting Officer
February 26, 2016
/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
/s/ Malia H. Wasson
Malia H. Wasson
Director
Director
Director
Director
Director
Director
Director
Director
Director
91
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)
)
)
)
)
)
)
)
February 26, 2016
)
)
)
)
)
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)
)
)
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NORTHWEST NATURAL GAS COMPANY
Exhibit Index to Annual Report on Form 10-K
For the Fiscal Year Ended December 31, 2015
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 quarter ended June 30, 2008, File No. 1-15973).
Bylaws as amended May 22, 2014 (incorporated herein by reference to Exhibit 3.1 to Form 8-K dated May 22, 2014,
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. 1-15973).
Form of Secured Medium-Term Notes, Series B (incorporated herein by reference to Exhibit 4.1 to Form 8-K dated
October 4, 2004, File No. 1-15973).
Form of Unsecured Medium-Term Notes, Series B (incorporated herein by reference to Exhibit 4.2 to Form 8-K dated
October 4, 2004, File No. 1-15973).
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).
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 maturity date of the Credit Agreement
between Northwest Natural Gas Company and each financial institution, effective as of December 20, 2013
(incorporated herein by reference to Exhibit 4k to Form 10-K for 2013, File No. 1-15973).
92
*4k.
*4l.
*10a
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 maturity date of the Credit Agreement
between Northwest Natural Gas Company and each financial institution, effective as of December 20, 2014
(incorporated herein by reference to Exhibit 4m to Form 10-K for 2014, File No. 1-15973).
First Amendment to Credit Agreement, between the Company 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, dated as of December 20, 2014
(incorporated herein by reference to Exhibit 4n to Form 10-K for 2014, File No. 1-15973).
Carry and Earning Agreement by and between Encana Oil & Gas (USA) Inc. and Northwest Natural Gas Company,
dated effective as of May 1, 2011, and First Amendment to Carry and Earning Agreement dated March 11, 2011
(incorporated herein by reference to Exhibit 10.1 to Form 10-Q for the quarter ended March 31, 2011, File No.
1-15973). †
*10b
Second Amendment to Carry and Earning Agreement by and between Encana Oil and Gas (USA) Inc. and NWN Gas
Reserves, LLC., dated as of March 7, 2014 (incorporated herein by reference to Exhibit 10 to Form 10-Q for the
quarter ended March 31, 2014, 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:
*10c.
Executive Supplemental Retirement Income Plan 2010 Restatement (incorporated herein by reference to Exhibit 10b.
to Form 10-K for 2009, File No. 1-15973).
*10d.
Supplemental Executive Retirement Plan, 2011 Restatement (incorporated herein by reference to Exhibit 10.1 to
Form 10-Q for the quarter ended September 30, 2011, File No. 1-15973).
*10e.
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).
*10f.
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).
*10g.
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).
*10h.
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).
93
*10i.
Form of Restated Stock Option Plan Agreement (incorporated herein by reference to Exhibit 10h. to Form 10-K for
2009, File No. 1-15973).
*10j.
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).
*10k.
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).
*10l.
Deferred Compensation Plan for Directors and Executives effective January 1, 2005, restated as of September 24,
2015 (incorporated herein by reference to Exhibit 10a to Form 10-Q for the quarter ended September 30, 2015).
*10m.
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).
*10n.
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).
*10o.
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).
10p.
Executive Annual Incentive Plan, effective February 23, 2012, as amended effective January 1, 2016.
*10q.
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).
*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 2012, File No. 1-15973).
*10s.
Severance Agreement between Northwest Natural Gas Company and an executive officer, dated as of June 30, 2015
(incorporated herein by reference to Exhibit 10.1 to Form 8-K dated June 24, 2015).
*10t.
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).
*10u.
Form of Long-Term Incentive Award Agreement under the Long Term Incentive Plan (2014-2016) (incorporated herein
by reference to Exhibit 10v. to Form 10-K for 2013, File No. 1-15973).
*10v.
Form of Long-Term Incentive Award Agreement under the Long Term Incentive Plan (2015-2017) (incorporated by
reference to Exhibit 10w to Form 10-K for 2014, File No. 1-15973).
10w.
Form of Long-Term Incentive Award Agreement under the Long Term Incentive Plan (2016-2018).
10x.
10y.
*10z.
Form of Long-Term Incentive Award Agreement under the Long Term Incentive Plan between the Company and an
Executive Officer (2016-2018).
Agreement to Amend the Long-Term Incentive Award Agreement, under the Long-Term Incentive Plan dated February
25, 2016 by and between the Company and an executive officer.
Form of Consent dated December 14, 2006 entered into by each executive officer with respect to amendments to the
Executive Supplemental Retirement Income Plan, the Supplemental Executive Retirement Plan and certain change in
control severance agreements (incorporated herein by reference to Exhibit 10.1 to Form 8-K dated December 19,
2006, File No. 1-15973).
94
*10aa. 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).
10bb.
Form of Restricted Stock Unit Award Agreement under Long-Term Incentive Plan (2016).
*10cc. 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).
*10dd. 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 20, 2011, File No. 1-15973).
*10ee. 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).
*10ff.
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 Form 10-Q for the quarter ended March 31, 2014, File
No. 1-15973).
*10gg. Form of Special Retention Restricted Stock Unit Award Agreement between the Company and an executive officer,
dated as of June 30, 2015 (incorporated herein by reference to Exhibit 10.2 to Form 8-K dated June 24, 2015).
*10hh. Hire-On Bonus Agreement between the Company and an executive officer, dated as of June 30, 2015 (incorporated
herein by reference to Exhibit 10.3 to Form 8-K dated June 24, 2015).
10ii.
Annual Incentive Plan for NW Natural Gas Storage, LLC, as amended effective January 1, 2016.
10jj.
Long-Term Incentive Plan for NW Natural Gas Storage, LLC, as amended effective January 1, 2016.
101.
The following materials from Northwest Natural Gas Company's Annual Report on Form 10-K for the fiscal year ended
December 31, 2015, 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
† Certain portions of the exhibit have been omitted based upon a request for confidential treatment filed by us with the Securities
and Exchange Commission. The omitted portions of the exhibit have been separately filed by us with the Securities and
Exchange Commission.
95
NORTHWEST NATURAL GAS COMPANY
Ratios of Earnings to Fixed Charges
(Unaudited)
EXHIBIT 12
In thousands, except share data
Fixed Charges, as defined:
Interest on Long-Term Debt
Other Interest
Amortization of Debt Discount and Expense
Interest Portion of Rentals
Total Fixed Charges, as defined
Earnings, as defined:
Net Income
Taxes on Income
Fixed Charges, as above
Total Earnings, as defined
Ratios of Earnings to Fixed Charges
Year Ended December 31,
2015
2014
2013
2012
2011
$
$
37,918
3,173
1,760
1,976
44,827
$
40,066
2,718
1,963
2,302
47,049
$
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
53,703
35,753
44,827
$ 134,283
3.00
58,692
41,643
47,049
$ 147,384
3.13
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
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 26, 2016 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,
/s/ PricewaterhouseCoopers LLP
Portland, Oregon
February 26, 2016
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 26, 2016
/s/ Gregg S. Kantor
Gregg S. Kantor
Chief Executive Officer
CERTIFICATION
I, Gregory C. Hazelton, 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 26, 2016
/s/ Gregory C. Hazelton
Gregory C. Hazelton
Senior Vice President, Chief Financial Officer, and Treasurer
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, Chief Executive Officer, and GREGORY C. HAZELTON, the Senior Vice
President, Chief Financial Officer, and Treasurer 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, 2015 (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 26th day of
February 2016.
/s/ Gregg S. Kantor
Gregg S. Kantor
Chief Executive Officer
/s/ Gregory C. Hazelton
Gregory C. Hazelton
Senior Vice President,
Chief Financial Officer, and
Treasurer
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.
INVESTOR AND SHAREHOLDER INFORMATION
CORPORATE INFORMATION
Nikki Sparley
Director, Investor Relations
Toll free (800) 422-4012, Ext. 2530
Direct (503) 721-2530
nikki.sparley@nwnatural.com
Chu Lee
Manager, Shareholder Services
Toll free (800) 422-4012, Ext. 2402
Direct (503) 220-2402
chu.lee@nwnatural.com
Stock transfer agent and registrar
For common stock:
American Stock Transfer & Trust Company
6201 15th Avenue
Brooklyn, NY 11219
(888) 777-0321
web: amstock.com
email: info@amstock.com
Trustee and bond paying agent
For bond issues:
Deutsche Bank Trust Company Americas
60 Wall Street
New York, NY 10005
(800) 735-7777
COMMUNITY & SUSTAINABILITY REPORT
Learn more about NW Natural’s community involvement and philanthropic contributions, environmental
stewardship, employee safety efforts and other company initiatives.
View the Community & Sustainability Annual Report at nwnatural.com/aboutnwnatural/community.
LOW-INCOME PROGRAMS
NW Natural helps low-income customers manage their bills through a variety of programs. Shareholders
and customers support the Gas Assistance Program (GAP), which supplements the federal and
state assistance programs. In addition, the Oregon Low-Income Gas Assistance Program (OLGA)
uses public purpose fees to help low-income customers pay their utility bills. The Oregon Low-Income
Energy Efficiency Program (OLIEE), also paid for by public purpose charges, helps customers in need
acquire high-efficiency equipment and weatherization.
View the Low-Income Programs at nwnatural.com/residential.
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/residential.
220 nw second avenue
portland, oregon 97209
nwnatural.com
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