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lead. Innovate. grow.
corporate profile
nW natural (nYse: nWn) is a
156-year-old natural gas local dis-
tribution company headquartered in
portland, oregon. nW natural serves
more than 700,000 utility customers in
oregon and southwest Washington
FINANCIAL OVERVIEW
earnings
financial facts ($000):
operating revenues
Utility margin
net income
and provides gas storage to customers
financial ratios (%):
on the West coast. in keeping with its
return on average common equity
steady growth strategy, the company
has increased dividends paid to share-
holders for 59 consecutive years.
capital structure at year-end:
long-term debt
common stock equity
2014
2013
percent
increase
(decrease )
754,037
366,088
58,692
758,518
353,884
60,538
7.7
44.8
55.2
8.2
47.6
52.4
service territory
and storage facilities
WASHINGTON
ASTORIA
MIST STORAGE
VANCOUVER
GASCO LNG
WASHINGTON
LINCOLN CITY
PORTLAND
THE DALLES
TRAINING
CENTER
ASTORIA
MIST STORAGE
SALEM
ALBANY
NEWPORT LNG
VANCOUVER
GASCO LNG
PORTLAND
THE DALLES
EUGENE
OREGON
LINCOLN CITY
TRAINING
CENTER
COOS BAY
NEWPORT LNG
SALEM
ALBANY
COOS BAY
EUGENE
OREGON
KEY
NW NATURAL SERVICE TERRITORY
TRAINING CENTER
REGIONAL RESOURCE CENTER
LNG PLANT
UNDERGROUND STORAGE
HEADQUARTERS
common stock
shareholder data (000):
average shares outstanding – diluted
Year-end shares outstanding
27,223
27,284
27,027
27,075
per share data ($):
diluted earnings
dividends paid
Book value at year-end
Market value at year-end
operating highlights
2.16
1.85
28.12
49.90
2.24
1.83
27.77
42.82
gas sales and transportation deliveries (000 therms)
1,092,990
1,146,431
degree days
customers at year-end
employees at year-end
3,792
704,644
1,084
4,379
694,873
1,081
dividends paid on common stock (per share)
paYMent date
february 15
May 15
august 15
november 15
$ 0.460
$ 0.455
0.460
0.460
0.465
0.455
0.455
0.460
total dividends paid
$ 1.845
$ 1.825
(1 )
3
(3 )
(6 )
(6 )
5
1
1
(4 )
1
1
17
(5 )
(13 )
1
-
NEVADA
diluted earnings per share
(in dollars)
dividends paid per share
(in dollars)
$2.00
$1.90
$1.80
$1.70
$1.60
$1.50
$1.40
NEVADA
2010
2011
2012
2013
2014
diluted earnings per share were $2.16 in 2014.
SAN FRANCISCO
GILL RANCH
STORAGE
FRESNO
CALIFORNIA
$3.00
$2.50
$2.00
$1.50
$1.00
$0.50
$0.00
SAN FRANCISCO
LOS ANGELES
GILL RANCH
STORAGE
FRESNO
CALIFORNIA
2010
2011
2012
2013
2014
Annual dividends paid per share in 2014
increased for the 59th consecutive year.
The current indicated annual dividend is
$1.86 per share.
LOS ANGELES
Kruse Village in Lake Oswego, Oregon
shown behind NW Natural President and
CEO Gregg Kantor, is an example of new
commercial development spurred by the
Northwest’s rebounding economy.
letter to shareholders
3
For NW Natural, 2014 was a year of
both opportunity and challenge, a year
marked by important milestones and
continued innovation.
In the midst of these varying forces, NW Natural de-
livered earnings of $2.16 per share, while providing a
total shareholder return of approximately 22 percent.
In 2014, our utility delivered on its most fundamental
mission: we operated safely, reliably and with great
customer service. We continued to grow, adding our
700,000th customer. And we continued to innovate,
advancing initiatives that hold great promise for the
company’s future, such as the potential expansion of
our Mist gas storage facility and the development of a
new Carbon Solutions Program.
But the company also faced challenges. Weak storage
values hurt the financial performance of our Gill ranch
storage business in California. Higher natural gas prices
increased our utility’s cost of gas – producing a loss from
our regulatory incentive sharing mechanism. And a recent
2014 highlights
• reported net income of $59 million or $2.16 per share,
compared to $61 million or $2.24 per share in 2013.
• earned the highest customer satisfaction score among
large utilities in the West in the 2014 J.D. Power Gas Utility
residential Customer Satisfaction Study.
• Increased our investment in gas reserves, bringing the total
amount invested since 2011 to $188 million.
• received insurance settlements totaling $103 million in 2014,
which brought cumulative recoveries for environmental costs
to approximately $150 million.
• Increased our annual customer growth rate to 1.4 percent,
adding our 700,000th customer.
• leveraged our new online customer portal, converting to
natural gas 25 percent of those consumers that inquired
decision by the Public Utility Commission of oregon
about gas availability through the online tool.
(oPUC) required a write-down of $15 million in 2015
for the disallowance of environmental cost deferrals.
While this write-down was disappointing, going forward
the company now has approval to fully recover in rates
prudently incurred environmental costs through our
Site remediation and recovery Mechanism.
• launched enhancements to the portal, providing new self-
service features for builders and contractors, and automating
new construction and conversion work orders.
• Increased common dividends paid for the 59th consecutive
year, one of the longest dividend increase records of any
company on the NYSe.
4
letter to shareholders
With the environmental deci-
sion behind us and our core
utility business on solid footing,
we look ahead with optimism
and a laser focus on advanc-
ing our growth initiatives and
operational priorities.
Operations milestones
We started the year proving
our system’s reliability. We
set a new gas sendout record
when an east wind made
a bitter cold day feel even
colder. on Feb. 6, 2014,
the company delivered
more than 9 million therms
to customers in 24 hours.
that’s almost double the
bare steel and cast iron replacement
L
E
E
T
S
E
R
A
B
F
O
S
E
L
M
I
1,250
1,000
750
500
250
0
1986
1991
1996
2001
2006
2014
BARE STEEL
CAST IRON
250
200
150
100
50
0
N
O
R
I
T
S
A
C
F
O
S
E
L
M
I
reinforcement project near
Monmouth, oregon. the
project included a six-
mile, coated steel pipeline
that replaced old bare
steel pipe. We expect to
replace the remaining bare
steel in our system during
2015, ensuring we have
one of the most modern
pipeline systems
in the nation.
But our dedication to
safety doesn’t stop
with distribution system
The company has less than three miles of bare steel main left in our system. All cast
iron pipe has been removed. The company’s System Integrity Program has been
key to helping us modernize our pipeline system.
improvements. last year,
we applied a remarkable
normal sendout for a typical winter day. our
pipeline system and gas storage facilities were
fully prepared to meet the substantial increase
in demand.
We credit our ability to serve customers reliably
and safely, as we did during the February cold
technology tool, Visual
Fusion,® to emergency response. By integrating a variety of data into one
easy-to-view interface, our resource Management team receives a full picture
of emergency situations – instantly. Staff can quickly determine critical factors
such as the closest available emergency resource and estimated drive time.
As a result, our first responders can reach the scene faster and be more
prepared for the situation when they arrive.
snap, to careful planning and implementation of
As part of our ongoing efforts to improve facilities and reduce our buildings’
system improvements. As an example, we recently
environmental footprint, we completed the remodel of our Salem resource
invested in a 2.2 mile, high-pressure pipeline
center. this facility contains a satellite call center, as well as field operations
extension in Vancouver, Washington, and this
and technical support services for the Mid-Willamette Valley.
addition is helping us meet demand in the fastest-
growing county in our service territory.
the remodel touched nearly every inch of the 1966 building. Major improve-
ments ranged from more energy-efficient natural lighting and a high-efficiency
Another example of our commitment to improving
heating and cooling system to seismic upgrades and more effective use of
reliability and service was in the Willamette Valley,
space. the site will also serve a dual purpose as the backup business
where we completed the second phase of a major
continuity site for the company’s primary call center in Portland.
Sophisticated mapping and communication technology help employees across the company plan, mobilize and respond to meet the needs
of our customers.
letter to shareholders
5
And at our new Sherwood facility, located about 15 miles from NW Natural’s
With these new features, we have the capability to
Portland headquarters, we are now equipped for backup emergency man-
automate roughly 85 percent of our work orders.
agement operations covering gas control, resource planning, dispatch and
Most importantly, our trade partners see the portal
incident command center functions.
our outstanding record of reliability, service and innovation has made a positive
impression on our customers. For the fifth time in eight years, we ranked first
in the West in the annual J.D. Power Gas Utility residential Customer Satisfac-
tion Study. this also marks the seventh time in eight years that NW Natural was
among the two highest-scoring gas utilities in the nation.
New tools for a recovering market
the Northwest’s economy made positive gains in 2014, with oregon’s employ-
ment rebounding to pre-recession levels and unemployment rates continuing
to fall. the housing sector was on an upward trend as well, with Portland home
sales up nearly 4 percent and the average sale price up 7 percent compared
to 2013. Clark County, Washington, home sales increased 8 percent, with the
average sale price increasing 10 percent. these improvements helped drive an
increase in our customer growth rate to 1.4 percent last year.
With our customers paying less for natural gas today than they did 10 years
ago and a substantial price advantage over electricity and oil – the company is
as key to helping them manage projects more
efficiently and close sales faster.
“The online tool is great.
I have used it several times with
success. Once I was able to
order a new service on a Friday
evening while sitting at a
customer’s dining room table.”
- Andrew Scheidt,
Central Air, Heating & Air Conditioning, Inc.
well positioned competitively.
the regulatory arena
to take full advantage of the preference for natural gas in the housing market,
we leveraged our new Customer Connections Portal. this industry-leading
online tool allows prospective customers to learn if gas is available in their area,
run cost comparisons, evaluate equipment offers and sign up for a contractor
visit – all from any convenient location with a computer or mobile device.
Since its release, more than 12,000 prospective customers have used the portal
to inquire about gas service, providing us with important website analytics that
we are using in our marketing efforts.
In August of 2014, we launched the portal’s second phase, designed specifically
for contractors and home builders. Using a secure site, our trade allies can sign
up for gas service by job type, manage multiple projects with us and check the
status of their orders throughout a job’s life cycle.
utility customers at year-end
720,000
700,000
680,000
660,000
640,000
620,000
600,000
580,000
560,000
540,000
2010
2011
2012
2013
2014
INDUSTRIAL
COMMERCIAL
RESIDENTIAL
last year a major regulatory milestone was submis-
sion of an Integrated resource Plan (IrP) to oregon
and Washington regulators. the document encom-
passes a wide array of issues associated with our
ability to meet customer needs, key among them
were the following findings:
• Fast-growing Clark County, Washington will
require several gas infrastructure investments
to serve new homes and businesses.
• the company will need to invest up to
$25 million to modernize the Newport liquefied
Natural Gas (lNG) plant, originally built in 1977.
• the regional supply scenario holds some
uncertainties as regulators and investors consider
a variety of proposals including new pipelines,
export facilities and large industrial expansions.
Given what we know today, the least-cost
option for NW Natural’s customers is a new
pipeline from Madras to Molalla – if no lNG
export terminal is built in oregon.
on February 24, 2015, we received acknowledg-
ment of the IrP from the oregon commission, and
we expect to receive notification from the Washington
commission by this summer.
In 2014, we also amended our 2011 agreement
with encana to develop gas reserves that provide
price stability for a portion of the gas we serve to
We added 9,771 new customers in 2014, ending the year with 704,644 customers.
oregon utility customers. the amendment was in
6
letter to shareholders
response to encana’s sale of its Jonah Field
interests to Jonah energy, llC. While it ended
the original drilling program, it also increased our
working interests in the Jonah Field, and going
forward, allows us to further invest in the field
on a well-by-well basis.
Under this new arrangement, we participated in
the drilling of seven wells in 2014, and we have
filed with the oPUC to recover those costs as part
of our oregon utility hedge portfolio.
last year, we continued to work through the three
remaining dockets from our 2012 oregon rate case.
on February 20, 2015, the oregon commission
issued its decision on one of those dockets – how
our Site remediation and recovery Mechanism
(SrrM) will be implemented.
oregon & washington residential rates
(in dollars per therm)
$1.60
$1.40
$1.20
$1.00
$0.80
$0.60
2005
2006
2007
2008
2009
2010
2011
2012
2013
2014
OREGON RESIDENTIAL RATES
WASHINGTON RESIDENTIAL RATES
Today’s residential rates are lower than they were 10 years ago.
the application of an earnings test and other factors. this disallowance was
As part of NW Natural’s last rate case, the
equivalent to a $9.1 million after-tax loss that will be recognized as a charge
oPUC approved the SrrM, which allows recovery
to net income in the first quarter of 2015.
of costs the company has prudently incurred and
will continue to incur for environmental remedia-
tion at sites historically used to manufacture gas
the oPUC order also specified that insurance settlements, which resulted in
the collection of approximately $150 million, were entered into prudently.
for customers. the oPUC ordered a separate
Going forward, the order allows $10 million to be applied to environmental
docket to determine the prudence of deferred
expenditures each year, with $5 million collected in rates and $5 million from
environmental costs, the allocation of insurance
insurance proceeds. In a year where environmental costs are less than $10
proceeds and how an earnings test would be
million, the balance remaining for that year will roll forward to offset the next
applied to recover past and future deferred
year’s costs. In a year where environmental costs exceed $10 million and the
costs from utility customers.
company earns above its allowed return on equity, an earnings test will be ap-
In its final order, the oPUC found that all but
plied and the company will contribute to offset that year’s environmental costs.
$33,400 of the $114 million of environmental re-
While we were disappointed by the write-down, we view our ability to fully
mediation expenses and associated carrying costs
recover future environmental clean-up costs as the key issue in a very complex
incurred by NW Natural through March 2014 were
docket. We are pleased the environmental spend and insurance settlements
prudently incurred. However, the oPUC disallowed
were approved, and overall, we believe this order provides us with a reason-
recovery of expenses totaling $15 million due to
able path forward.
In 2014, NW Natural upgraded Miller Station, the 24/7 operations center for the Mist Underground Storage Field.
letter to shareholders
7
We have two remaining issues carried over from our 2012 rate case. As part
conversion program that would encourage resi-
of our interstate storage sharing docket, the oPUC recently directed the par-
dents to convert from inefficient oil furnaces to
ties engaged in the proceeding to select a third-party to conduct an evaluation
efficient natural gas units; and a solicitation to large
and cost allocation study this year. Also in 2015, the commission is expected
commercial and industrial customers to propose
to rule on the pension cost recovery docket that involves all oregon utilities.
combined heat and power or distributed generation
storage operations
last year, operations at our underground storage facility near Mist, oregon
performed well, providing critical support for our utility customers as well as
profitably serving storage customers across the Pacific Northwest.
In 2014, we received approval from a local electric company, Portland General
electric (PGe), to move forward with the permitting and land acquisition work
required for a potential expansion project at Mist. the project would be designed
to provide no-notice underground gas storage services to PGe’s natural gas-fired
generating plants at Port Westward, oregon.
projects that use natural gas to increase energy
efficiency.
With implementation rules approved by the oPUC
in December, our plan for 2015 is to refine concepts
and file a number of projects for consideration.
the Carbon Solutions Program offers an excellent
opportunity to demonstrate our spirit of innovation,
and showcase the important role natural gas can play
in helping our region meet its environmental goals
while adding to the company’s bottom line.
the potential North Mist expansion Project would include a new reservoir
providing up to 2.5 billion cubic feet of available storage, an additional com-
looking ahead
pressor station with design capacity of 120,000 dekatherms of gas per day
over the years, we’ve developed a reputation
and a 13-mile pipeline to connect to PGe’s gas plants at Port Westward.
among our peers for introducing successful new
In 2015, NW Natural will be working to obtain the required permits and certain
property rights. Assuming successful completion of those necessary elements,
the current estimated cost of the expansion is approximately $125 million, with
a potential in-service date in the 2018/2019 winter season, depending on the
permitting process and construction schedule.
Mist’s unique location and relative competitive position in the Northwest has
helped shield it from low storage values found in other geographic areas. that
has not been the case for our Gill ranch storage facility in California where
low, stable gas prices have continued to affect storage values.
ideas – from decoupling our rates to investing in
physical gas reserves. In 2014, we demonstrated
once again that we can continue to bring innova-
tion to the business of natural gas distribution.
In 2015, we intend to further our 156-year legacy
of operating a safe, reliable natural gas system and
providing exceptional customer service. We will
stay focused on those fundamentals, but also strive
for innovation in business development, regulation
and technology. Bringing these attributes together,
In the last year, however, Gill ranch has added several high-value customers,
we are confident in the value that our company
and we continue to seek new avenues for leveraging this asset. As the West
and product can bring to the region’s economy and
Coast increases renewable power generation that requires more natural gas
environmental goals, as well as to our customers
backup, we believe storage values will rebound.
and shareholders.
reducing greenhouse gases, adding opportunities
As a result of Senate Bill 844 passed by the oregon legislature, the oPUC
can now incent gas utilities financially to undertake projects that will reduce
greenhouse gas emissions. We see this legislation as opening new paths
to serve customers and communities while encouraging positive action on
climate change issues.
As always, we are grateful for your continued
support. NW Natural’s officers, managers and
employees look forward to working on your behalf
in the year ahead.
our Carbon Solutions Program team has been assessing a number of pos-
sible projects spanning several areas. examples of potential projects involve
reducing methane emissions during pipeline maintenance and repair; an oil
Gregg S. Kantor
President and Ceo
8 CorPorAte officers
Front
margaret d. kirkpatrick
Senior Vice President and
General Counsel
lea anne doolittle
Senior Vice President and
Chief Administrative officer
david h. anderson
executive Vice President
and Chief operating officer
gregg s. kantor
President and Chief
executive officer
stephen p. feltz
Senior Vice President and
Chief Financial officer
Back
grant m. yoshihara
Vice President
Utility operations
tom imeson
Vice President
Public Affairs
c. alex miller
Vice President
regulation and
treasurer
david r. williams
Vice President
Utility Services
j. keith white
Vice President Business
Development and
energy Supply and
Chief Strategic officer
mardilyn saathoff
Vice President legal,
risk and Compliance
and Corporate
Secretary
brody j. wilson
Controller and
Chief Accounting
officer
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
President and Chief
executive officer
NW Natural
jane l. peverett
Former President and
Chief executive officer
British Columbia trans-
mission Corporation
kenneth thrasher
Chairman
of the Board
Compli Corporation
malia wasson
Former executive
Vice President of
Commercial Banking,
U.S. Bank
SHAreHolDer iNformatioN
9
Notice of annual meeting
the 2015 Annual Meeting will be held at 2 p.m., thursday, May 28, 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 9, 2015, 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.
dividend reinvestment and
direct stock purchase plan
contact the NW Natural Board
request for publications
Concerns may be directed to the non-
the following publications may be
Participants may make an initial invest-
management directors by writing to
obtained without charge by contacting
ment in company stock and common
NW Natural Board of Directors,
the Corporate Secretary at NW Natural’s
shareholders of record may reinvest all
c/o Corporate Secretary.
address: Annual report; Form 10-K; Form
or part of their dividends in additional
10-Q; Corporate Governance Standards;
shares under the company’s plan. Cash
forward-looking statements
Director Independence Standards; Code
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.
scheduled dividend payment dates
February 13, 2015
May 15, 2015
August 14, 2015
November 13, 2015
certifications
the Chief executive officer certified
to the NYSe on June 17, 2014, 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, 2013, the certifi-
cates 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, 2014, the certificates of
the Chief executive officer and Chief
Financial officer are attached as exhibits
31.1 and 31.2 to the Form 10-K included
in this Annual report.
the statements made in this Annual
report that are not purely historical,
including statements regarding strat-
egy, growth and growth initiatives,
dividends, earnings, future demand for
gas, commodity costs and competitive-
ness, revenues, customer growth, gas
supplies and reserves, hedge efficacy,
capital expenditures, investments and
returns, business development, potential
projects, costs and project timelines,
pipeline replacement and safety and first
responder programs, system reliability,
storage performance values, recovery
and expansion, governmental policy
and legislation, regulatory cost recovery
mechanisms, including, but not limited
to, the SrrM, regulatory prudence
reviews, regulatory proceedings and ac-
tions, economic recovery factors, market
trends and the competitive environment
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
(202) 551-8090.
comparison of five-year
cumulative total return
(Based on $100 invested on 12/31/2009)
$250
$200
are forward-looking statements within the
$150
“safe harbor” provisions of the Private
Securities litigation reform Act of 1995.
$100
NW Natural’s actual results could differ
materially from those anticipated in these
$50
forward-looking statements as a result
of risks and uncertainties, including those
$0
described in the attached report on
Form 10-K.
2009
2010
2011
2012
2013
2014
NWN
S&P UTILITIES INDEX
S&P 500 INDEX
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.
Total shareholder return (annualized) over the five
years ending December 31, 2014 for NW Natural
was 6.1%, compared to Standard & Poor’s (S&P)
Utilities Index return of 13.3%, and the S&P 500
Index return of 15.5%.
10 lIVING oUr missioN & values
our missioN
We provide safe, reliable
and affordable energy in an
environmentally responsible
way to better the lives of
the public we serve.
our core values
Integrity
Safety
Service ethic
Caring
environmental Stewardship
Produced by NW Natural’s Corporate Communications
photo credits
Cover - Customer service representative, NW Natural trucks: Corky Miller.
Page 3 - Gregg Kantor, Kruse Village: Jeff Lee.
Page 4 - Customer service and gas control: Corky Miller.
Page 6 - Mist Storage: Corky Miller; Gas pipe: Robbie McClaran.
Page 8 - Corporate Officers: Jeff Lee; Board of Directors: Robbie McClaran.
Inside back cover - Robert Hess and Chu Lee: Robbie McClaran.
printing
RR Donnelley
Form 10-K
Annual Report
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2014
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.
[ ]
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, 2014, the registrant had 27,171,581 shares of its Common Stock outstanding, of which 26,805,283 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 $1,263,869,093.
At February 20, 2015, 27,304,169 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 2015 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, 2014
TABLE OF CONTENTS
PART I
Glossary of Terms and Abbreviations
Forward-Looking Statements
Item 1.
Business
Overview
Business Model
Local Gas Distribution
Gas Storage
Other
Environmental Issues
Employees
Additions to Infrastructure
Executive Officers of the Registrant
Available Information
Item 1A. Risk Factors
Item 1B. Unresolved Staff Comments
Properties
Legal Proceedings
Mine Safety Disclosures
Item 2.
Item 3.
Item 4.
PART II
Item 5.
Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer
Item 6.
Item 7.
Purchases of Equity Securities
Selected Financial Data
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Item 8.
Item 9.
Financial Statements and Supplementary Data
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
Item 9A. Controls and Procedures
Item 9B. Other Information
PART III
Item 10. Directors, Executive Officers and Corporate Governance
Item 11. 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
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GLOSSARY OF TERMS AND ABBREVIATIONS
AFUDC
AM Best
Allowance for Funds Used During Construction
A.M. Best Co. is a global independent credit rating agency
AOCI / AOCL
Accumulated Other Comprehensive Income (Loss)
ARO
ASC
ASU
Asset Retirement Obligation
Accounting Standards Codification
Accounting Standards Update as issued by the FASB
Average Weather
The 25-year average heating degree days based on temperatures established in our last
Oregon general rate case.
Bcf
Btu
CAP
CNG
CO2
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 Btus 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
measurement.
Engineering Evaluation / Cost Analysis
Encana Oil & Gas Inc.
Energy Corp
Northwest Energy Corporation, a wholly-owned subsidiary of NW Natural
EPA
EPS
FASB
FERC
Firm Service
FMB
GAAP
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
General Rate Case
A periodic filing with state or federal regulators to establish billing rates for utility
customers.
GHG
Gill Ranch
Greenhouse gases
Gill Ranch Storage, LLC, a wholly-owned subsidiary of NWN Gas Storage
1
Gill Ranch Facility
GTN
Heating Degree Days
Underground natural gas storage facility near Fresno, California, with 75% owned by Gill
Ranch and 25% owned by PG&E.
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
Net Operating Loss
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
OPEIU
OPUC
PBGC
PG&E
PGA
PGE
PHMSA
RI/FS
ROE
ROR
S&P
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
Portland Harbor Remedial Investigation / Feasibility Study
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 (formerly Palomar Gas Holdings, LLC), which is 50% owned by
NWN Energy
Trail West Pipeline, LLC, a subsidiary of TWH (formerly Palomar Gas Transmissions,
LLC)
TransCanada
TransCanada Pipelines Limited, owner of TAIL and GTN
Transportation Service
Service provided whereby a customer purchases natural gas commodity directly from a
supplier but pays the utility to transport the gas over its distribution system to the
customer’s facility.
Utility Margin
A financial measure consisting of utility operating revenues less the associated cost of
gas and franchise tax.
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 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
This report contains forward-looking statements within the
meaning of the U.S. Private Securities Litigation Reform Act
of 1995. Forward-looking statements can be identified by
words such as anticipates, intends, plans, seeks, believes,
estimates, expects, and similar references to future periods.
Examples of forward-looking statements include, but are not
limited to statements regarding the following:
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
plans;
objectives;
goals;
strategies;
assumptions and estimates;
future events or performance;
trends;
risks;
timing and cyclicality;
earnings and dividends;
capital structure;
growth;
customer rates;
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 recovery or refunds;
impacts of laws, rules and regulations;
tax liabilities or refunds;
levels and pricing of gas storage contracts;
outcomes and effects of potential claims, litigation,
regulatory actions, and other administrative matters;
projected obligations under retirement plans;
availability, adequacy, and shift in mix, of gas supplies;
approval and adequacy of regulatory deferrals;
effects of regulatory mechanisms; and
environmental, regulatory, litigation and insurance costs
and recoveries, and timing thereof.
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
Forward-looking statements are based on our current
expectations and assumptions regarding our business, the
economy and other future conditions. Because forward-
looking statements relate to the future, they are subject to
inherent uncertainties, risks and changes in circumstances
that are difficult to predict. Our actual results may differ
materially from those contemplated by the forward-looking
statements. We therefore caution you against relying on any
of these forward-looking statements. They are neither
statements of historical fact nor guarantees or assurances
of future performance. Important factors that could cause
actual results to differ materially from those in the forward-
looking statements are discussed at Item 1A., "Risk
Factors" of Part I and Item 7. and Item 7A., "Management’s
Discussion and Analysis of Financial Condition and Results
of Operations" and "Quantitative and Qualitative Disclosures
About Market Risk", respectively, of Part II of this report.
Any forward-looking statement made by us in this report
speaks only as of the date on which it is made. Factors or
events that could cause our actual results to differ may
emerge from time to time, and it is not possible for us to
predict all of them. We undertake no obligation to publicly
update any forward-looking statement, whether as a result
of new information, future developments or otherwise,
except as may be required by law.
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. However, our company and its predecessors have
supplied gas service to the public since 1859, and we have
been doing business as NW Natural since 1997. We
maintain operations in Oregon, Washington, and California
and conduct business through NW Natural and its
subsidiaries. References in this discussion to "Notes" are
the Notes to the Consolidated Financial Statements in Item
8 of this report.
We have two core businesses: our regulated local gas
distribution business, referred to as the utility segment,
which serves residential, commercial, and industrial
customers in Oregon and southwest Washington; and our
gas storage businesses, referred to as the gas storage
segment, which provides storage services for utilities, gas
marketers, electric generators, and large industrial users
from storage facilities located in Oregon and California. In
addition, we have investments and other non-utility activities
that we aggregate and report as other.
The utility business is our largest segment, while our gas
storage businesses account for the majority of our
remaining net income. The following table reflects the
percentage allocation between segments and other as of
December 31, 2014:
Non-Utility(1)
Utility
Gas
Storage(2)
Other
Total
Assets
90.5%
9.0 %
0.5%
100.0%
Net Income
(1)
99.8%
(0.6)%
100.0%
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.
0.8%
(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
700,000 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.
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,
5
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 in the retail, manufacturing, and high-technology
industries are located in our service territory.
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, 2014:
Residential
Commercial
Industrial
Total
Number of
Customers
% of
Volumes
% of Utility
Margin (1)
637,411
66,304
929
704,644
35%
22%
43%
100%
64%
28%
8%
100%
(1) Utility margin is also derived from 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 in less
than 60% of residential single-family dwellings in our service
territory. Therefore, growth in the region comes from both
new single and multi-family housing construction and
existing homes converting to natural gas. Prior to the most
recent recession, our customer growth rate averaged over
3% for many years. From 2009 to 2012, growth dipped
below 1%, but in 2013 and 2014, the 12-month growth rate
increased to 1.3% and 1.4%, respectively. Natural gas is a
preferred energy resource in our service territory, as it is a
low-cost, reliable, clean energy choice, and as such, we
believe there is potential for continued growth. 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
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.
6
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.
The utility's most recent general rate case in Oregon was
effective November 1, 2012, and the latest Washington rate
case was effective January 1, 2009. Our current approved
rates and recovery mechanisms for each service area
include:
Authorized Rate Structure:
ROE
ROR
Oregon
Washington(1)
9.5%
7.8%
10.1%
8.4%
Debt/Equity Ratio
50%/50%
49%/51%
Key Regulatory Mechanisms:
PGA
Incentive Sharing
Weather Normalization Tariff
Decoupling
SIP
Pension Balancing
Environmental Cost Deferral
SRRM
X
X
X
X
X
X
X
X
X
X
(1) Although we do not have the same specific regulatory
mechanisms in Washington, we do have approved regulatory
deferral orders that allow us to defer certain costs for future
recovery through the PGA or future general rate cases, such as our
environmental cost deferral order.
In general, these rates and regulatory mechanisms do not
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 original gas
reserves investment 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. Except for as described below, we
can earn an authorized return on the equivalent rate base
investment on our gas reserves.
For a complete discussion of regulatory matters, open
dockets, current regulatory activities, and additional details
on each rate mechanism, see Part II, Item 7, "Results of
Operations—Regulatory Matters" and "Gas Storage" below.
Gas Supply
The utility strives to secure sufficient, reliable supplies of
natural gas to meet the needs of customers at the lowest
reasonable cost, 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; and
• Cost Management - 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 optimize price
differentials. For 2014, 66% 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 off-
peak months during 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)
2.7
0.5
0.5
0.6
1.2
5.5
10.0
1.1
4.0
0.9
0.6
16.6
(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 2.7 million therms of daily deliverability
and 10 Bcf of storage capacity are reserved for core utility
customers.
(2) The storage facility is located near Chehalis, Washington and is
contracted from Northwest Pipeline, a subsidiary of The Williams
Companies. A portion of the related pipeline transportation service
from this facility is subject to curtailment and considered secondary
firm capacity. As a result, NW Natural is evaluating the reliability of
the capacity as part of the IRP process.
(3) This resource does not add to our total peak day capacity, but
helps to manage 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 plans to
recall 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.
In addition, we have the ability to recall pipeline capacity
and supply resources from certain customers if needed.
7
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 2014, we purchased a total of 761 million therms
under contracts with durations outlined in the chart below:
Contract Duration (primary term)
Long-term (one year or longer)
Short-term (more than one month, less than one
year)
Spot (one month or less)
Total
Percent of
Purchases
30%
25
45
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 2014.
Gas Cost Management Strategy
The cost of gas sold to utility customers primarily consists of
the following items, which are included in annual PGA rates:
purchase price paid to suppliers; charges paid to pipeline
companies to store and transport gas to our distribution
system; our gas reserves contract; and gains or losses
related to gas commodity derivative contracts.
We employ a number of strategies to mitigate the cost of
gas sold to utility customers. Our primary strategies for
managing gas commodity price risk include:
•
•
negotiating fixed prices directly with gas suppliers;
negotiating financial derivative contracts that: (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.
•
•
We also contract with an independent energy marketing
company to capture opportunities regarding our unused
storage and pipeline capacity when those assets are not
serving the needs of our core utility customers. Our asset
management activities provide cost savings that reduce our
utility customer's cost of gas and opportunities to generate
incremental revenues for NW Natural's shareholders from a
8
regulatory incentive-sharing mechanism, which are included
in our gas storage segment.
Transportation of Gas Supplies
Our local gas distribution system is reliant on a single, bi-
directional interstate transmission pipeline to bring gas
supplies into our distribution system. Although we are
dependent on a single pipeline, the pipeline’s gas flows into
the Portland metropolitan market from two directions: (1) the
north, which brings supplies from the British Columbia and
Alberta supply basins; and (2) the east, which brings
supplies from Alberta as well as the U.S. Rocky Mountain
supply basins.
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 and
ensure 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, NW Natural's 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 NW Natural's projected demand.
Though only one of these projects will likely be completed
with the pipeline location dependent on the location of the
successful project. NW Natural 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, formerly
known as Palomar or the cross-Cascades pipeline project.
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, "2015 Outlook".
Gas Distribution
The goals of our gas distribution operations are:
• Safety - Building and maintaining a safe pipeline
distribution system;
• Reliability - Ensuring gas resource portfolios are
sufficient to satisfy customer requirements under
extreme cold weather conditions;
•
•
Lowest Reasonable Cost - Acquiring gas supplies at
the lowest reasonable cost for utility customers;
Price Stability - Managing commodity price volatility by
making the best use of physical assets and financial
instruments; and
• Cost Recovery - Managing gas purchase costs
prudently to minimize risks associated with regulatory
reviews and cost recovery.
These goals are discussed more fully in the following
sections.
Safety
Safety and the protection of our employees, our customers
and the public at large are, and will remain, our top
priorities. We monitor and maintain our pipeline distribution
system and storage operations with the goal of ensuring
natural gas is stored and delivered safely, reliably and
efficiently. Since 2004, we have partnered with the OPUC
and WUTC on various efforts to improve the safety and
reliability of our distribution system. In Oregon, we have a
cost recovery program that integrated the Company’s
programs for bare steel replacement, transmission pipeline
integrity management, and distribution pipeline integrity
management into a single program. Currently, we are
seeking renewal of the System Integrity Program (SIP);
however, our bare steel replacement program continues in
2015. See Part II, Item 7, "Results of Operations—
Regulatory Matters—System Integrity Program".
Natural gas distribution businesses are likely to be subject
to even greater federal and state regulation in the future due
to recent pipeline incidents involving other companies. Most
recently, additional regulations from the U.S. Department of
Transportation’s Pipeline and Hazardous Materials Safety
Administration (PHMSA) were drafted in 2013 with final
regulations expected in 2015 and an effective date in
2016. We will continue to work diligently with industry
associations as well as federal and state regulators to
ensure the safety of our system and compliance with new
laws and regulations. We expect the costs associated with
compliance to federal, state, and local rules would be
recoverable in rates.
Reliability
The effectiveness of our gas distribution system ultimately
rests on whether we provide reliable service to our core
utility customers. To ensure our effectiveness, we develop a
composite design year, including a 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 approximately 9.3 million therms. Of this
total, we are currently capable of meeting over 50% of our
maximum design day requirements with gas from storage
located within or adjacent to our service territory, while the
remaining supply requirements would be met by gas
purchases under firm gas purchase contracts and recall
agreements.
On February 6, 2014, we experienced our current record
customer sendout of 9.0 million therms, which included 7.4
million firm therms. This record day was approximately 9
degrees Fahrenheit warmer than the design day
temperature.
To supplement near-term natural gas supplies, the
Company planned to segment transportation capacity
during the 2014-2015 heating season 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, the Company 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 integrated resource plan (IRP)
process.
The following table shows the sources of supply projected to
be used to satisfy the design day sendout for the 2014-2015
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(1)
Pipeline segmentation capacity
Recall agreements
Peak day citygate deliveries(2)
Therms
Percent
3.3
2.7
1.8
0.5
0.4
0.4
0.2
36%
29
20
5
4
4
2
9.3
Total
100%
(1) A portion of the related pipeline transportation service from this
facility is subject to curtailment and considered secondary firm
capacity. As a result, NW Natural is evaluating the reliability of the
capacity as part of the IRP process.
(2) These citygate deliveries are contracted from December 2014 to
February 2015 with this resource being evaluated for future heating
seasons after the current winter.
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
9
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
2014. We are currently awaiting notice from the WUTC.
Lowest Reasonable Cost
We apply cost management strategies, including fixed-price
contracts, financial derivative instruments, storage supplies,
acquisition of gas reserves, and asset management to
acquire gas supplies at the lowest reasonable cost for utility
customers. See "Gas Supply—Gas Cost Management
Strategy" above.
Price Stability
We use physical assets and financial instruments to
manage commodity price volatility. We purchase gas for our
storage facilities generally during the summer months when
demand and gas prices are typically lower. In addition, our
gas reserves provide long-term gas price stability for our
utility customers. We also mitigate year-to-year commodity
price volatility through financial hedge contracts such as
commodity price swaps and options.
Cost Recovery
Mechanisms for gas cost recovery are designed to be fair
and reasonable, with an appropriate balance between the
interests of our customers and shareholders. In general,
utility rates are designed to recover the costs, but not to
earn a return on, the gas commodity sold. We minimize
risks associated with gas cost recovery by resetting
customer rates annually through the PGA and aligning
customer and shareholder interests through the use of
sharing, weather normalization, and conservation
mechanisms in Oregon. See Part II, Item 7, "Results of
Operations—Regulatory Matters—Rate Mechanisms" and
"Results of Operations—Business Segments—Local Gas
Distribution Utility Operations—Cost of Gas."
GAS STORAGE
The gas storage segment includes the following:
•
the non-utility portion of the Mist gas storage facility
near Mist, Oregon;
our 75% share of the Gill Ranch gas storage facility
near Fresno, California; and
asset management services provided by an
independent energy marketing company.
•
•
In general, the supply of natural gas remains relatively
stable over the course of a year, while the demand for
natural gas typically fluctuates seasonally. Storage facilities
allow customers to purchase and inject natural gas supplies
during periods of low demand and withdraw these supplies
for use or resale during periods of higher demand. These
facilities allow us to capitalize on the imbalance of supply
and demand and price volatility for natural gas.
In recent years, as a result of the abundant supply of natural
gas in North America, we have seen lower, more stable
natural gas prices, which have created a challenging gas
10
storage environment particularly in California. The spot price
and front end of the forward curve for natural gas
temporarily increased in late 2013 and early 2014 due to
extreme cold weather. The effect during 2014 was a
significant decline in storage levels, which resulted in spring
and summer natural gas prices equal to projected gas
prices for the winter of 2014-15. Thus, the purchase of
spring and summer gas for injection into storage was less
desirable and storage values decreased. While we are
seeing some improvement in storage values coming out of
this year's warmer than normal winter, overall prices remain
lower than our long-term contracts that expired during the
2013-14 gas storage year. Despite current market
conditions, we continue to believe in the long-term need for
gas storage, particularly in California, due to various
regulations including renewable portfolio standards and
signs of economic recovery and industrial growth in the
region. Increased demand for natural gas and/or decreased
drilling activity could change the current supply/demand
imbalance and result in higher gas prices or increased
market volatility, which could position this segment for
growth.
See Note 4 for more information on gas storage assets and
results of operations and "Financial Condition—Liquidity
and Capital Resources".
Gas Storage Facilities
The following table provides information concerning the
Company’s non-utility gas storage facilities:
Maximum
Designed
Storage
Capacity
(Bcf)
Deliverability
(Therms in
millions/day)
(3)
Injection
(Therms in
millions/day)
(3)
Mist Storage(1)
6
2.4
Gill Ranch Storage(2)
(1) Approximately 6 Bcf of a total 16 Bcf at Mist is currently
4.9
15
1.0
2.4
available to our gas storage segment. The remaining 10 Bcf is
used to provide gas storage for our local distribution business
and its utility customers. All storage capacity and daily
deliverability currently developed for the gas storage segment
at Mist is available for recall by the utility. In May 2015, the
utility plans to recall approximately 0.3 million therms per day
of deliverability or 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 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 interstate storage services, firm
service agreements with customers are entered into with
terms typically ranging from 1 to 10 years. Currently, our
gas storage revenues from Mist are derived primarily from
firm service customers who provide energy related services,
including natural gas production or distribution, electric
generation, and energy marketing. Three storage customers
currently account for over 90% of our existing non-utility gas
storage capacity at Mist, with the largest customer
accounting for about half of the total capacity. These three
customers have contracts that expire at various dates
through 2018.
COMPETITIVE CONDITIONS. Our Mist gas storage facility
benefits from limited competition from other Pacific
Northwest storage facilities primarily because of its
geographic location. However, competition from other
storage providers in Washington and Canada, as well as
competition for interstate pipeline capacity, does exist. In the
future, we could face increased competition from new or
expanded gas storage facilities as well as from new natural
gas pipelines, marketers, and alternative energy sources.
SEASONALITY. Mist gas storage revenues generally do not
follow seasonal patterns similar to those experienced by the
utility because most of the storage capacity is contracted
with customers for firm service, which are primarily in the
form of fixed monthly reservation charges and are not
affected by customer usage. However, there is seasonal
variation with Mist storage capacity related to utility
customers' lower demand during the spring and summer
months. This surplus storage capacity and related
transportation capacity can be optimized under regulatory
sharing agreements with the OPUC and WUTC. See "Asset
Management" below.
REGULATION. Our Mist facility is subject to regulation by the
OPUC and WUTC. In addition, FERC has approved
maximum cost-based rates under our Mist interstate storage
certificate. We are required to file either a petition for rate
approval or a cost and revenue study with FERC at least
every five years to change or justify maintaining the existing
rates for the interstate storage service. See Part II, Item 7,
"Results of Operations—Regulatory Matters".
EXPANSION OPPORTUNITIES. The need for new, flexible
gas-fired generation has been identified in the Pacific
Northwest region to integrate intermittent wind resources
into the power system, thereby increasing the associated
need for gas storage. To address this need, we are planning
a potential expansion of our Mist storage facility. If
completed, this expansion would be supported by a 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.
11
The project would include a new reservoir providing up to
2.5 Bcf of available storage, an additional compressor
station with design capacity of 120,000 dekatherms of gas
per day, 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 potential in-
service date in 2018 or 2019, depending on the permitting
process and construction schedule.
In early 2015, we received authorization from PGE to begin
permitting and land acquisition work, and in October 2014 a
new rate schedule was approved 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 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
at historic lows for the past two years and a greater number
of competitors in the area compared to the Pacific
Northwest region. More recently, we have seen
improvement in pricing for the upcoming 2015-2016 gas
storage year, however prices are still lower than our long-
term contracts that expired during the 2013-2014 gas
storage year. We are committed to using a variety of
contracting tools to maximize the value of the Gill Ranch
facility. In the longer term, we anticipate a rebound in gas
storage values driven by a variety of factors including
changes in energy generation triggered by California's
renewable portfolio standards and carbon reduction targets,
recovery of the California economy, and other favorable
market conditions in and around California. We believe
these factors could increase demand for natural gas storage
and increase price volatility.
SERVICES. Gill Ranch provides intrastate, multi-cycle
storage services in California at market-based rates under a
CPUC-approved tariff that includes firm storage service,
interruptible storage service, and park and loan storage
services. 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 28 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 mostly ranging from
one to five years. For the 2014-15 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.
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.
Trail West Holdings, LLC (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, "2015
Outlook";
a minority interest in Kelso-Beaver Pipeline held by our
wholly-owned subsidiary NNG Financial Corporation
(NNG Financial); and
other operating and non-operating income and
expenses of the parent company that are not included
in utility or gas storage operations.
•
•
The pipelines referred to above are regulated by FERC.
Less than 1% of our consolidated assets and consolidated
net income are related to activities in other. See Note 4 for
summary information for these assets and results of
operations.
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. As storage markets recover, there could also be
expansions and proposed new construction of storage
capacity in northern California that may create increased
competition.
SEASONALITY. Although we expect much of the storage
revenue at Gill Ranch to be in the form of fixed monthly
demand charges, cash flows can fluctuate due to timing of
asset management and other revenues. In addition, a
significant portion of operating costs at Gill Ranch are
subject to seasonality based on periods when storage
customers elect to inject or withdraw.
REGULATION. Gill Ranch has a tariff on file with the CPUC
authorizing it to charge market-based rates for the storage
services offered. See Part II, Item 7, "Results of
Operations–Regulatory Matters".
EXPANSION OPPORTUNITIES. Subject to market demand,
project execution, available financing, receipt of future
permits, and other rights, the Gill Ranch storage facility can
be expanded beyond the current combined permitted
capacity of 20 Bcf without further expansion of the takeaway
pipeline system. Taking these considerations into account
and with certain infrastructure modifications, we currently
estimate 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.
12
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.
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; and
variations between the estimated and actual period of
time that must be dedicated to respond to an
environmentally-contaminated site.
•
•
•
•
•
We seek recovery of environmental costs through insurance
and customer rates, and we believe recovery of these costs
is probable. At December 31, 2014, we had an open
proceeding with the OPUC to address implementation
issues for the SRRM, which allows for regulatory cost
recovery of our environmental expenditures. In February
2015, the OPUC issued an order addressing outstanding
items related to the SRRM, including prudence of past
costs, an earnings test, and a regulatory disallowance of
$15 million pre-tax to be recorded in the first quarter of 2015
in accordance with accounting guidance and our regulatory
accounting policy. See "Results of Operations—Rate
Matters—Rate Mechanisms—Environmental Costs" below,
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.
13
EMPLOYEES
EXECUTIVE OFFICERS OF THE REGISTRANT
At December 31, 2014, the utility workforce consisted of 612
members of the Office and Professional Employees
International Union (OPEIU) Local No. 11, AFL-CIO, and
472 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, 2014, our subsidiaries had a combined
workforce of 19 non-union employees. Our subsidiaries
receive certain services from centralized operations at the
utility, and the utility is reimbursed for those services
pursuant to a Shared Services Agreement.
ADDITIONS TO INFRASTRUCTURE
We make capital expenditures in order to maintain and
enhance the safety and integrity of our pipelines, gate
stations, storage facilities and related assets, to expand the
reach or capacity of those assets, or improve the efficiency
of our operations. We expect to make a significant level of
capital expenditures for additions to utility and gas storage
infrastructure over the next five years, reflecting continued
investments in customer growth, technology, and
distribution system improvements. For the five-year period
ending in 2019, 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.
In 2015, utility capital expenditures are estimated to be
between $140 and $150 million, and non-utility capital
investments are estimated to be less than $10 million.
Additional spend for gas storage and other investments
during and after 2015 will depend largely on future decisions
about potential expansion opportunities in gas storage
projects.
For information concerning our executive officers, see Part
III, Item 10.
AVAILABLE INFORMATION
We file annual, quarterly and special reports and other
information with the Securities and Exchange Commission
(SEC). Reports, proxy statements and other information
filed by us can be read and requested through the SEC by
mail at U.S. Securities and Exchange Commission, Office of
FOIA/PA Operations, 100 F Street, N.E., Washington, D.C.
20549, by facsimile at (202) 772-9337, or online at its
website (http://www.sec.gov). You can obtain information
about access to the Public Reference Room and how to
access or request records by calling the SEC at (202)
551-8090. The SEC website contains reports, proxy and
information statements and other information 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.
14
ITEM 1A. RISK FACTORS
Our business and financial results are subject to a number
of risks and uncertainties, many of which are not within our
control. When considering any investment in our securities,
investors should carefully consider the following information,
as well as information contained in the caption "Forward-
Looking Statements", Item 7A, and other documents we file
with the SEC. This list is not exhaustive and the order of
presentation does not reflect management’s determination
of priority or likelihood. Additionally, our listing of risk factors
that primarily affects one of our business segments does not
indicate that such risk factor is inapplicable to our other
business segments.
Risks Related to our Business Generally
REGULATORY RISK. Regulation of our businesses, including
changes in the regulatory environment, failure of regulatory
authorities to approve rates which provide for timely
recovery of our costs and an adequate return on invested
capital, or an unfavorable outcome in regulatory
proceedings may adversely impact our financial condition
and results of operations.
The OPUC and WUTC have general regulatory authority
over our utility business in Oregon and Washington,
respectively, including the rates charged to customers,
authorized rates of return on rate base, including ROE, the
amounts and types of securities we may issue, services we
provide and the manner in which we provide them, the
nature of investments we make, actions investors may take
with respect to our company, and deferral and recovery of
various expenses, including, but not limited to, pipeline
replacement, environmental remediation costs, pension
expense, transactions with affiliated interests, and other
matters. Similarly, in our gas storage businesses FERC has
regulatory authority over interstate storage services, the
CPUC has regulatory authority over our Gill Ranch storage
operations, and the WUTC and OPUC have regulatory 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 the most recent OPUC
order issued to the Company regarding implementation of
our SRRM, the OPUC 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. Additionally, the rates allowed by
the FERC may be insufficient for recovery of costs incurred.
We expect to continue to make expenditures to expand,
improve and operate our utility distribution and gas storage
systems. Regulators can find such expansions or
improvements of expenditures were not prudently incurred,
and deny recovery. Additionally, while the OPUC and WUTC
have established an authorized rate of return for our utility
through the ratemaking process, the regulatory process
does not provide assurance that we will be able to achieve
the earnings level authorized.
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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.
In our latest general rate case with the OPUC, various items
were deferred for future resolution in separate proceedings,
including recovery of prepaid pension costs, and our
revenue-sharing arrangement on the utility's interstate
storage activities. The regulatory proceedings in which
these issues will be resolved typically involve multiple
parties, including governmental agencies, consumer
advocacy groups, and 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 asset which
would result in a charge to current year earnings. In
addition, in our most recent Oregon general rate case, the
OPUC approved the SRRM, which limits recovery of our
deferred amounts to those amounts which satisfy an annual
prudence review and 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. These
ongoing prudence reviews and the earnings test could
reduce the amounts we are allowed to recover, and could
adversely affect our financial condition, results of operations
and cash flows.
In addition, we may have disputes with regulators and other
parties as to the severity of particular environmental matters
and what remediation efforts are appropriate. We cannot
predict with certainty the amount or timing of future
expenditures related to environmental investigation,
remediation or other action, or disputes or litigation arising
in relation thereto. Our liability estimates are based on
current remediation technology, industry experience gained
at similar sites, an assessment of the probable level of
involvement, and financial condition of other potentially
responsible parties. However, it is difficult to estimate such
costs due to uncertainties surrounding the course of
environmental remediation, the preliminary nature of certain
of our site investigations, and the application of
environmental laws that impose joint and several liabilities
on all potentially responsible parties. These uncertainties
and disputes arising therefrom could lead to further
adversarial administrative proceedings or litigation, with
associated costs and uncertain outcomes, all of which could
adversely affect our financial condition, results of operations
and cash flows.
ENVIRONMENTAL REGULATION COMPLIANCE RISK. We are
subject to environmental regulations for our ongoing
operations, compliance with which could adversely affect
our operations or financial results.
We are subject to laws, regulations and other legal
requirements enacted or adopted by federal, state and local
governmental authorities relating to protection of the
environment, including those legal requirements that govern
discharges of substances into the air and water, the
management and disposal of hazardous substances and
waste, groundwater quality and availability, plant and wildlife
protection, and other aspects of environmental regulation.
Current and additional environmental regulations could
result in increased compliance costs or additional operating
restrictions and could have an adverse effect on our
financial condition and results of operations, particularly if
those costs are not fully recoverable from insurance or
through utility customer rates.
GLOBAL CLIMATE CHANGE RISK. Future legislation to
address global climate change may expose us to regulatory
and financial risk. Additionally, our business may be subject
to physical risks associated with climate change, all of which
could adversely affect our financial condition, results of
operations and cash flows.
There are a number of international, federal and state
legislative and regulatory initiatives being proposed and
adopted in an attempt to measure, control or limit the effects
of global warming and overall climate change, including
greenhouse gas emissions such as carbon dioxide and
methane. Such current or future legislation or regulation
could impose on us operational requirements, additional
charges to fund energy efficiency initiatives, or levy a tax
based on carbon content. Such initiatives could result in us
incurring additional costs to comply with the imposed
restrictions, provide a cost advantage to energy sources
other than natural gas, reduce demand for natural gas,
impose costs or restrictions on end users of natural gas,
impact the prices we charge our customers, impose
increased costs on us associated with the adoption of new
infrastructure and technology to respond to such
requirements, and may impact cultural perception of our
service or products negatively, diminishing the value of our
brand, all of which could adversely affect our business
practices, financial condition and results of operations.
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Climate change may cause physical risks, including an
increase in sea level, intensified storms, water scarcity and
changes in weather conditions, such as changes in
precipitation, average temperatures and extreme wind or
other climate conditions. A significant portion of the nation’s
gas infrastructure is located in areas susceptible to storm
damage that could be aggravated by wetland and barrier
island erosion, which could give rise to gas supply
interruptions and price spikes.
These and other physical changes could result in
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 law that could affect our ability to take, or timing of,
certain tax benefits that impact the financial outcome of this
transaction; inherent risks of gas production, including
disruption to operations or complete shut-in of the field; and
a participant in one of these business arrangements acting
contrary to our interests. In addition, while the cost of the
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, our amended gas reserves arrangement has not
been approved for inclusion in rates, and our regulators may
ultimately determine to not include all or a portion of that
transaction 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
hydrocarbons as a result of the malfunction of
equipment or facilities;
damages from third parties, including construction, farm
and utility equipment or other surface users;
operator errors;
negative performance by our storage reservoirs that
could cause us to fail to meet expected or forecasted
operational levels or contractual commitments to our
customers;
problems maintaining, or the malfunction of, pipelines,
wellbores and related equipment and facilities that form
a part of the infrastructure that is critical to the
operation of our gas distribution and storage facilities;
collapse of underground storage caverns;
•
•
•
•
•
•
•
• migration of natural gas through faults in the rock or to
some area of the reservoir where existing wells cannot
drain the gas effectively resulting in loss of the gas;
blowouts (uncontrolled escapes of gas from a pipeline
or well) or other accidents, fires and explosions; and
risks and hazards inherent in the drilling operations
associated with the development of the gas storage
facilities and/or wells.
•
These risks could result in personal injury or loss of human
life, damage to and destruction of property and equipment,
pollution or other environmental damage, breaches of our
contractual commitments, and may result in curtailment or
suspension of our operations, which in turn could lead to
significant costs and lost revenues. Further, because our
pipeline, storage and distribution facilities are in or near
populated areas, including residential areas, commercial
business centers, and industrial sites, any loss of human life
or adverse financial outcome resulting from such events
could be significant. Additionally, we may not be able to
obtain the level or types of insurance we desire, and the
insurance coverage we do obtain may contain large
deductibles or fail to cover certain hazards or cover all
potential losses. The occurrence of any operating risks not
covered by insurance could adversely affect our financial
condition, results of operations and cash flows.
BUSINESS CONTINUITY RISK. We may be adversely
impacted by local or national disasters, pandemic illness,
terrorist activities, including cyber attacks, and other
extreme events to which we may not able to promptly
respond.
Local or national disasters, pandemic illness, terrorist
activities, including cyber attacks, and other extreme events
are a threat to our assets and operations. Companies in our
industry may face a heightened risk due to exposure to acts
of terrorism, including physical and 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
could increase the risk that an event could adversely affect
our operations or financial results.
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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 required 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,
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
18
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 interpretation or
enforcement of applicable law by a federal, state or local
taxing authority, could result in substantial cost to us and
negatively affect our results of operations. Tax law and its
related regulations and case law are inherently complex and
dynamic. Disputes over interpretations of tax laws may be
settled with the taxing authority in examination, upon appeal
or through litigation. Our judgments may include reserves
for potential adverse outcomes regarding tax positions that
have been taken that may be subject to challenge by taxing
authorities. Changes in laws, regulations or adverse
judgments may negatively affect our financial condition and
results of operations.
SAFETY REGULATION RISK. We may experience increased
federal, state and local regulation of the safety of our
systems and operations, which could adversely affect our
operating costs and financial results.
The safety and protection of the public, our customers and
our employees is and will remain our top priority. We are
committed to consistently monitoring and maintaining our
distribution system and storage operations to ensure that
natural gas is acquired, stored and delivered safely, reliably
and efficiently. Given recent high-profile natural gas
explosions and accidents in other parts of the country, we
anticipate that the natural gas industry may be the subject of
even greater federal, state and local regulatory oversight.
We intend to work diligently with industry associations and
federal and state regulators to ensure compliance with the
new laws. We expect there to be increased costs
associated with compliance, 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
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
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investment grade. Further, based on current interpretations,
we are not considered a "swap dealer" or "major swap
participant" in 2014, 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. 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
conditions, technology, environmental impacts and public
perception.
Technological improvements in other energy sources such
as heat pumps could also erode our competitive advantage.
If natural gas prices rise relative to other energy sources, or
if the cost, environmental impact or public perception of
such other energy sources improves relative to natural gas,
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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.
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,
21
terrorism or other malicious acts could damage, destroy or
disrupt all of our business systems. Any failure of
information technology systems could result in a loss of
operating revenues, an increase in operating expenses and
costs to repair or replace damaged assets. As these
potential cyber security attacks become more common and
sophisticated, we could be required to incur costs to
strengthen our systems or obtain specific insurance
coverage against potential losses.
Risks Related Primarily to Our Gas Storage
Businesses
LONG-TERM LOW OR STABILIZATION OF GAS PRICE RISK.
Any significant stabilization of natural gas prices or long-
term low gas prices could have a negative impact on the
demand for our natural gas storage services, which could
adversely affect our financial results.
Storage businesses benefit from price volatility, which
impacts the level of demand for services and the rates that
can be charged for storage services. On a system-wide
basis, natural gas is typically injected into storage between
April and October when natural gas prices are generally
lower and withdrawn during the winter months of November
through March when natural gas prices are typically higher.
Largely due to the abundant supply of natural gas made
available by hydraulic fracturing techniques, natural gas
prices have dropped significantly to levels that are near
historic lows. If prices and volatility remain low or decline
further, then the demand for storage services, and the
prices that we will be able to charge for those services, may
decline or be depressed for a prolonged period of time.
Prices below the costs to operate the storage facility could
result in a decision to shut in all or a portion of the facility. A
sustained decline in these prices or a shut-in of all or a
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.
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
operation is not within our control. If the third-party pipeline
to which we are connected were to become unavailable for
current or future withdrawals or injections of natural gas due
to repairs, damage to the infrastructure, lack of capacity or
other reason, our ability to operate efficiently and satisfy our
customers’ needs could be compromised, thereby
potentially could have an adverse impact on our financial
condition, results of operations and cash flows.
OPERATIONS AT STORAGE FACILITY RISK. Operations at our
Mist and Gill Ranch storage facilities involve numerous
operational risks that may result in a failure to meet
expectations or contractual obligations, additional or
unexpected costs and other business risks that could
adversely impact our financial condition, results of
operations and cash flows.
Operations at a storage facility involve many risks. If we fail
to inject or withdraw natural gas at the levels we expect or
at contracted rates, or cannot deliver natural gas consistent
with our expectations or contractual specifications, or
otherwise operate as expected, or if operating costs are
substantially higher than we expect or if we fail to control
those costs, we may not be able to contract for storage at
the levels and on the terms we expect, and we could incur
higher than expected costs to satisfy our contractual
obligations under contracts we obtain, and this could
adversely impact our financial condition, results of
operations and cash flows.
ITEM 1B. UNRESOLVED STAFF COMMENTS
We have no unresolved comments.
ITEM 2. PROPERTIES
Utility Properties
Our natural gas pipeline system consists of approximately
14,000 miles of distribution and transmission mains located
in our service territory in Oregon and Washington. In
addition, the pipeline system includes service pipelines,
meters and regulators, and gas regulating and metering
stations. Pipeline mains are located in municipal streets or
alleys pursuant to franchise or occupation ordinances, in
county roads or state highways pursuant to agreements or
permits granted pursuant to statute, or on lands of others
pursuant to easements obtained from the owners of such
lands. We also hold permits for the crossing of numerous
navigable waterways and smaller tributaries throughout our
entire service territory.
We own service building facilities in Portland, as well as
various satellite service centers, garages, warehouses, and
other buildings necessary and useful in the conduct of our
business. We also lease office space in Portland for our
corporate headquarters, which expires on May 31, 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 expect to eliminate all remaining 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.
22
PART II
ITEM 5. MARKET FOR THE REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS
AND ISSUER PURCHASES OF EQUITY SECURITIES
Our common stock is listed and trades on the New York Stock Exchange under the symbol NWN.
The high and low trades for our common stock during the past two years were as follows:
Quarter Ended
March 31
June 30
September 30
December 31
2014
2013
High
Low
High
Low
$
44.09
$
40.05
$
46.55
$
47.32
47.50
52.57
43.06
41.81
42.29
45.89
45.15
44.35
43.40
41.17
39.96
40.75
The closing price for our common stock on December 31, 2014 and 2013 were $49.90 and $42.82, respectively.
As of February 20, 2015, there were 5,929 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
2014
2013
$
$
0.460
$
0.460
0.460
0.465
1.845
$
0.455
0.455
0.455
0.460
1.825
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, 2014:
Period
Balance forward
10/01/14-10/31/14
11/01/14-11/30/14
12/01/14-12/31/14
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
— $
4,233
211
—
46.22
47.32
—
—
—
—
—
—
Total
(1) During the quarter ended December 31, 2014, 4,444 shares of our common stock were purchased on the open market to meet the
2,124,528
46.28
4,444
$
$
16,732,648
requirements of our share-based programs. During the quarter ended December 31, 2014, 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, 2015 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, 2014, 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.
23
ITEM 6. SELECTED FINANCIAL DATA
In thousands, except share data
2014
2013
2012
2011
2010
Operating revenues
Net income
$
754,037
$
758,518
$
730,607
$
828,055
$
792,115
58,692
60,538
58,779
63,044
72,013
For the year ended December 31,
Earnings per share of common stock:
Basic
Diluted
Dividends paid per share of common stock
$
2.16
$
2.24
$
2.19
$
2.36
$
2.16
1.85
2.24
1.83
2.18
1.79
2.36
1.75
2.71
2.70
1.68
Total assets, end of period
$
3,064,945
$
2,970,911
$
2,813,120
$
2,742,718
$
2,614,172
Total equity
Long-term debt
767,321
621,700
751,872
681,700
729,627
691,700
712,158
641,700
691,625
591,700
24
EXECUTIVE SUMMARY
Our 2014 performance reflects the execution of our long-
term business strategy and advancement of our initiatives.
Highlights for the year include:
•
increased the annual customer growth rate in core
utility for the third year in a row from 0.8% to 1.4% at
December 31, 2014;
invested $120.1 million in our system and facilities
including $30.4 million on SIP, allowing us to approach
the completion of our bare steel replacement, and
announced a proposed gas storage expansion at Mist;
received proceeds from environmental insurance
settlements, bringing total insurance recoveries to $103
million in 2014 and over $150 million cumulatively;
launched a new online tool for customers and trade
allies that enables online ordering of services, tracking
progress of orders, and managing multiple projects;
ranked first in residential customer satisfaction for large
gas utilities in the West in the 2014 J.D. Power and
Associates Study, making 2014 the 13th consecutive
year of top three rankings; and
increased the dividend, marking the 59th consecutive
year of increases.
•
•
•
•
•
We manage our business and strategic initiatives with a
long-term view on providing natural gas service safely and
reliably to customers, working with regulators on key policy
initiatives, and remaining focused on growing our business.
See "2015 Outlook" below for more information.
Key financial highlights include:
In millions, except per
share data
Consolidated net income
Consolidated EPS
Utility margin
2014
2013
2012
$
58.7
$
60.5
$
2.16
366.1
2.24
353.9
58.8
2.18
344.5
Net income and EPS for 2014 reflected the following:
•
utility net income increased $3.7 million on utility margin
growth of $12.2 million primarily due to customer
growth and rate-base returns on gas reserves and
other investments; and
gas storage net income declined $5.9 million primarily
due to lower operating revenues from re-contracting
certain expiring capacity at lower prices for the 2014-15
gas storage year.
•
See "Consolidated Earnings and Dividends" below for
additional detail.
ITEM 7. MANAGEMENT'S DISCUSSION AND
ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
The following is management’s assessment of Northwest
Natural Gas Company’s (NW Natural or the Company)
financial condition, including the principal factors that affect
results of operations. The discussion refers to our
consolidated results for the years ended December 31,
2014, 2013, and 2012. References in this discussion to
"Notes" are the Notes to Consolidated Financial Statements
in Item 8 of this report.
The consolidated financial statements include NW Natural
and its direct and indirect wholly-owned subsidiaries
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 results of operations and earnings
amounts in total, certain financial measures are expressed
in cents per share, which are non-GAAP financial
measures. These amounts reflect factors that directly
impact earnings, including income taxes. All references in
this section to earnings per share (EPS) are on the basis of
diluted shares. We use such non-GAAP measures in
analyzing our financial performance because we believe
they provide useful information to our investors and
creditors in evaluating our financial condition and results of
operations.
25
2015 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 2015 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 2015, 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. In
addition, the removal of all bare steel pipe from our system
is set to be achieved by the end of 2015.
In 2014 we filed our IRP with the OPUC and WUTC,
identifying investments needed to ensure our system will
continue meeting customer demands. In February 2015, the
OPUC acknowledged the IRP. We will continue working on
key infrastructure investments for high-growth areas of our
service territory and plan for necessary maintenance of our
utility and storage facilities.
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. During 2015,
we will implement our new Site Remediation and Recovery
Mechanism (SRRM). This mechanism reflects the deep,
shared commitment of the Company and its customers to
the environment. In addition, we continue to work with
regulators on environmental sustainability projects such as
new carbon solution incentive rate mechanisms.
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.
Natural gas can play an important role in supporting the
integration of intermittent renewable resources into the
electric power system, and therefore, complements wind
and solar renewable energy options. In 2015, we will
continue to play an active role in shaping energy policies
and programs, which reflect the interests of our customers.
We will continue to work with state legislators to build a
strong energy plan for the region, and we will remain
committed to working with environmental agencies to make
significant progress towards remediation of our legacy
environmental sites.
UTILITY CUSTOMERS. Natural gas is a preferred energy
resource in our service territory as it is a low-cost, reliable,
and clean energy choice. We intend to capitalize on this
preference and on improvements in the residential housing
and commercial markets to grow our customer base.
KEY UTILITY INVESTMENTS. We believe investing in new
infrastructure, operating efficiencies, and marketing
opportunities positions our core business for growth now
and well into the future. During 2015, we will continue
working on a number of carbon solution programs with the
OPUC, such as residential oil conversions, commercial
combined heat and power, and other carbon emission
reduction programs.
Our recent IRP filing indicates an increase in the demand
for natural gas in our region and the need for additional
infrastructure investments. Our utility and gas storage
operations in Oregon and SW Washington currently depend
on a single bi-directional interstate transmission pipeline to
transport gas supplies to customers. We will continue to
work with regulators, customers, and utilities in the Pacific
Northwest to advance a new, integrated, regional cross-
Cascades pipeline to create supply diversity and reliability
for our system. The need for gas supply flexibility increases
as additional large electric generation and industrial projects
are sited in the region.
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 2015, we were authorized by
PGE to begin permitting and land acquisition work for this
project. Before construction can begin, the project is subject
to several conditions, including, but not limited to, PGE's
final approval of estimated costs and receipt of a notice to
proceed.
NON-UTILITY INITIATIVES. Energy policies in the Pacific
Northwest and California are likely to increase the value of
the Company's gas storage in the long-term. In the short-
term, we remain focused on maximizing the value of our
storage assets by managing costs, optimizing revenue
opportunities, and seeking new potential markets and
customers, while recognizing the unique challenges low,
stable natural gas prices bring to the storage market.
26
Issues and Challenges
ECONOMY. The local, national, and global economies
showed signs of improvement during 2014. We saw
increased utility customer growth and business demand for
natural gas. Our utility’s customer growth rate was 1.4% in
2014, compared to 1.3% in 2013 and 0.9% in 2012. NW
Natural ended 2014 with 704,644 customers. The local
Oregon and southwest Washington economies are showing
signs of recovery as unemployment rates in the Portland
and Vancouver area dropped from approximately 7% in
2013 to approximately 6% at the end of 2014. We believe
our utility is well positioned for continued customer additions
and increasing industrial demand because of low, stable
natural gas prices, our relatively low market penetration,
and our ongoing focus of converting homes and businesses
to natural gas. Additional growth may also come with
increased industrial load from new projects in the region and
proposed legislation that favors lower carbon emissions and
lower cost energy alternatives, such as natural gas. Our gas
storage business is also impacted by the employment
trends throughout the West Coast, as California, which was
among the hardest hit areas during the recession, is
reporting lower unemployment levels in 2014.
GAS PRICES AND SUPPLIES. Our gas acquisition strategy is
to secure sufficient supplies of natural gas to meet the
needs of our utility customers and to hedge gas prices so
we can effectively manage costs, reduce price volatility, and
maintain a competitive price advantage. With developments
in drilling technologies and the abundance of shale
development around the U.S. and in Canada, the current
outlook for North American natural gas supply is strong and
is projected to remain this way into the future. This
projection is dependent upon a combination of supply
outlook and demand factors as well as a regulatory
environment that continues to support hydraulic fracturing
and other drilling technologies.
Our utility's annual PGA mechanisms in Oregon and
Washington, combined with our gas price hedging
strategies, enable us to reduce earnings exposure for the
Company and secure lower gas costs for our customers.
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 2014-15 gas year (November 1,
2014 - October 31, 2015) hedged at 75% of our forecasted
sales volumes, including 41% in financial swap and option
contracts and 34% in physical gas supplies. For further
discussion see "Regulatory Matters—Rate Mechanisms—
Purchased Gas Adjustment" below.
In addition to the amount hedged for the current gas
contract year, we are also hedged in future years at
approximately 18% for the 2015-16 gas year as of
December 31, 2014 and between 1% and 9% for annual
requirements over the following five gas years. Our hedge
levels are subject to change based on actual load volumes,
which depend to a certain extent on weather, economic
conditions, and estimated gas reserve production. Also, our
storage inventory levels may increase or decrease based on
storage expansion, changes in storage contracts with third
parties, and/or storage recall by the utility.
While low and stable gas prices provide opportunities to
lower costs for our utility customers, they also present
challenges for our gas storage businesses by lowering the
price of, and reducing the demand for, storage services.
Earlier this year we re-contracted certain expiring storage
customer capacity at our Gill Ranch facility for the 2014-15
gas storage year at historically low prices due to the flat
natural gas price curve and generally weak market
conditions, which negatively impacted our financial results.
However, increases in demand for natural gas or decreases
in supplies can put upward pressure on gas prices and gas
price volatility, which could improve the market value for gas
storage. Similarly, decreases in demand and increases in
supplies can cause downward pressure on gas prices and
gas price volatility. We are seeing slightly higher contract
prices for the upcoming storage year, but overall prices are
lower than our long-term contracts that expired during the
2013-14 gas storage year. As such, we continue to expect
shorter contract lengths and prices reflecting current market
trends and remain focused on lowering operating costs,
finding opportunities in the market to increase revenues
through enhanced services for storage customers, and
capitalizing on market opportunities that fit our business-risk
profile.
ENVIRONMENTAL COSTS. We accrue all material
environmental loss contingencies related to environmental
sites for which we are responsible. Due to numerous
uncertainties surrounding the nature of environmental
investigations and the approval of proposed remediation
solutions by regulatory agencies, actual costs could vary
significantly from our loss estimates. As a regulated utility,
we have been allowed to defer certain costs pursuant to
regulatory orders. In our 2012 general rate case, the OPUC
approved our recovery of environmental costs from
investigation and site remediation subject to certain
conditions including a site remediation and recovery
mechanism. In February 2015, the OPUC issued an order
regarding the mechanism as noted in "Results of
Operations—Regulatory Matters—Rate Mechanisms" below
and Note 16.
We have received approximately $150 million cumulatively
from environmental insurance policy litigation settlements to
apply toward environmental costs, and will only seek
recovery from customers for amounts in excess of
insurance proceeds. Ultimate recovery of environmental
costs from regulated utility rates depends on our ability to
effectively manage these costs and demonstrate costs were
prudently incurred, and the application of an annual
earnings test in Oregon. Environmental cost recovery and
carrying charges on amounts charged to Washington
customers will be determined in a future proceeding. See
"Results of Operations—Regulatory Matters—Rate
Mechanisms" below and Note 16.
CLIMATE CHANGE. We recognize our business will likely be
impacted by future carbon constraints. To address these
possible constraints, we are seeking clean energy growth
opportunities that position us for long-term success in a
lower carbon energy economy and to advance our
customers’ interests in energy conservation, efficiency and
environmental stewardship. A variety of federal, state, local,
and international climate change initiatives, including new
regulations, are underway, but we cannot determine the
27
impact of these initiatives at this time. For example, an array
of Environmental Protection Agency (EPA) rules impacting
coal plants has driven some coal plants to shut down early
although the EPA is not mandating coal plant closures. Coal
plant shut downs could increase the demand for natural gas
as a lower carbon emission fuel and create opportunities for
us. Similarly, because natural gas has a relatively low
carbon content, it is also possible future carbon constraints
could create additional demand for natural gas for base load
electric generation, direct use in homes and businesses,
backing up intermittent renewable resources, and as a
transportation fuel to displace gasoline and diesel fuels.
As required under EPA greenhouse gas regulations, we
annually report our system throughput and unintended
greenhouse gas releases. While our carbon dioxide
equivalent emission levels are relatively small, the adoption
and implementation of any regulations imposing reporting
obligations, or limiting emissions of greenhouse gases
associated with our operations, could result in an increase
in the prices we charge our customers or a decline in the
demand for natural gas.
CONSOLIDATED EARNINGS AND DIVIDENDS
Consolidated Earnings
Consolidated highlights include:
In millions, except EPS
data
Net income
EPS
ROE
2014
2013
2012
$
58.7
2.16
$
60.5
2.24
$
58.8
2.18
7.7%
8.2%
8.2%
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 and expense,
net due to lower interest income on net deferred
regulatory balances.
•
•
•
2013 COMPARED TO 2012. The most significant factors
contributing to the $1.8 million increase in consolidated net
income were:
•
a $9.4 million increase in utility margin primarily due to
customer growth and the rate-base return on our gas
reserves and other investments; and
a $2.7 million after-tax charge taken in 2012 from an
Oregon general rate case disallowance.
•
Partially offsetting the above factors were:
•
a $7.1 million increase in operations and maintenance
expense primarily due to increased utility payroll and
system maintenance and safety program costs; and
a $2.9 million increase in depreciation and amortization
expenses primarily due to additional utility
expenditures.
•
Dividends
Dividend highlights include:
Per common share
Dividends paid
2014
2013
2012
$
1.85
$
1.83
$
1.79
The Board of Directors declared a quarterly dividend on our
common stock of $0.465 cents per share, payable on
February 13, 2015, to shareholders of record on January
30, 2015, reflecting an indicated annual dividend rate of
$1.86 per share.
28
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 2014, 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, but are
also affected by the local economies in Oregon and
Washington, the pace of customer growth in the residential,
commercial, and industrial markets, and our ability to remain
price competitive, control expenses, and obtain reasonable
and timely regulatory recovery of our utility-related costs,
including operating expenses and investment costs in utility
plant and other regulatory assets. See "Most Recent
General Rate Cases" below.
GAS STORAGE. Our gas storage 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 2014, approximately 69% of our
storage revenues were derived from FERC, Oregon, and
Washington regulated operations and approximately 31%
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.
Open Regulatory Proceedings
The following provides a list of our significant open
regulatory items:
•
Interstate Storage Sharing - A docket has been
opened to review the current revenue sharing
arrangement that allocates a portion of the net
revenues generated from non-utility Mist storage
services and third-party asset management services to
utility customers. We anticipate resolution of this docket
in 2015.
Prepaid Pension Asset - A schedule was established
to resolve this docket in 2015. See "Rate Mechanisms
—Pension Cost Deferral and Prepaid Pension Assets"
below.
•
•
• Gas Reserves - We filed with the OPUC in February
2015 seeking cost recovery on additional investments
in gas reserves. See "Rate Mechanisms—Gas
Reserves" below.
Integrated Resource Plan (IRP) - We filed our 2014
Oregon and Washington IRPs on August 29, 2014 and
received acknowledgment from the OPUC on February
24, 2015. We expect notice from the WUTC during
2015. The IRPs included analysis of different market
scenarios and corresponding resource acquisition
strategies. This analysis is needed to develop supply
and demand resource requirements, consider
uncertainties in the planning process, and to establish a
plan for providing reliable and low cost natural gas
service.
System Integrity Program (SIP) - We filed a request
to extend the SIP program in the fourth quarter of 2014.
See "Rate Mechanisms—System Integrity Program
(SIP)" below.
•
Completed Regulatory Activities
The following provides a list of our completed regulatory
activities in 2014:
•
Flexible Gas Storage - We received approval from the
OPUC in 2014 for two new rate schedules. One of
these schedules is intended to allow us to provide no-
notice gas storage service from Mist and specifically
supports services associated with the proposed Mist
gas storage facility expansion. The expansion would be
supported by a contract with PGE to serve their gas-
fired electric power generation facilities at Port
Westward, which is located approximately 15 miles
from Mist. In early 2015, we received authorization from
PGE to begin permitting and land acquisition work. This
project is subject to PGE's final approval of estimated
projected costs and a notice to proceed, as well as the
receipt of permits and certain land rights, among other
conditions.
Senate Bill (SB) 844 - Final rules for gas utilities in
Oregon governing the incentive rate-making
mechanisms aimed at reducing greenhouse gas
emissions were issued in 2014. We anticipate
submitting programs developed under these rules to
the OPUC in 2015. These programs include oil
conversions, commercial combined heat and power,
and other carbon emission reduction programs.
•
29
• GASCO Water Treatment Station - The OPUC
approved placing $19.0 million of capital costs
associated with a water treatment station at our Gasco
environmental site into rates effective November 1,
2013. During 2014, the OPUC deemed Gasco
construction costs prudent and approved the
application of $2.5 million of insurance proceeds plus
interest to reduce the capital costs included in rates
effective November 1, 2014.
• CNG Service Approved - In 2014, we received
approval from the OPUC to offer business customers a
new service to install, own, and maintain gas
compression equipment that enables them to fuel their
vehicle fleets with CNG. NW Natural filed the tariff in
June 2013 after receiving requests from businesses
interested in switching or increasing the number of their
fleet vehicles fueled by CNG. Costs associated with
providing this service will be directly paid by business
customers using the service. The OPUC will review the
tariff after two years to assess the market for CNG at
that time.
Rate Mechanisms
PURCHASED GAS ADJUSTMENT. Rate changes are
established for the utility each year under PGA mechanisms
in Oregon and Washington to reflect changes in the
expected cost of natural gas commodity purchases. This
includes gas prices under spot purchases as well as
contract supplies, gas prices hedged with financial
derivatives, gas prices from the withdrawal of storage
inventories, the production of gas reserves, interstate
pipeline demand costs, a permanent rate adjustment for our
SIP program, temporary rate adjustments, which amortize
balances of deferred regulatory accounts, and the removal
of temporary rate adjustments effective for the previous
year.
Under the current PGA mechanism in Oregon, there is an
incentive sharing provision whereby we are required to
select each year either an 80% deferral or a 90% deferral of
higher or lower actual gas costs compared to estimated
PGA prices, such that the impact on current earnings from
the incentive sharing is either 20% or 10% of the difference
between actual and estimated gas costs, respectively.
Under the Washington PGA mechanism, we defer 100% of
the higher or lower actual gas costs, and those gas cost
differences are normally passed on to customers through
the annual PGA rate adjustment.
We filed our PGA in September 2014 and received OPUC
and WUTC approval in October 2014. PGA rate changes
were effective November 1, 2014, with the rate changes
increasing the average monthly bills of residential
customers by 1.7% and 6.0% in Oregon and Washington,
respectively. The increase in Oregon reflected customers'
portion of adjustments for changes in natural gas
commodity costs, offset by credits related to the decoupling
mechanism and other annual adjustments previously
agreed to with the OPUC. Washington rates reflected the
full effect of changes in natural gas commodity costs and
some additional annual adjustments based on ongoing
agreements with the WUTC.
Commodity cost increases were primarily related to the
colder weather experienced by many parts of the United
States for an extended period in late 2013 and early 2014.
The extreme cold weather nationally resulted in a significant
withdrawal of gas from storage and higher gas prices
compared to the 2012-13 winter. In addition, our service
territory experienced a cold weather event in February
2014, increasing gas volumes purchased for that period.
These past and current price and volume increases resulted
in the rate changes for the 2014-15 PGA period.
EARNINGS TEST REVIEW. We are subject to an annual
earnings review in Oregon to determine if the utility is
earning above its authorized ROE threshold. If utility
earnings exceed a specific ROE level, then 33% of the
amount above that level is required to be deferred for refund
to customers. Under this provision, if we select the 80%
deferral 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 2012-13, 2013-14 and 2014-15 PGA years. The ROE
threshold is subject to adjustment annually based on
movements in long-term interest rates. For calendar years
2012, 2013, and 2014, the ROE threshold was 10.92%,
10.58%, and 10.66%, respectively. There were no refunds
required for 2012 and 2013. We do not expect a refund for
2014 based on our results and anticipate filing the 2014 test
in May 2015.
GAS RESERVES. In 2011 the OPUC approved the Encana
gas reserve transaction to provide long-term gas price
protection for our utility customers and determined the
Company's costs under the agreement will be recovered,
plus a rate base return on our investment, on an ongoing
basis through our annual PGA mechanism, including the
regulatory deferral and incentive sharing process for the
commodity cost of gas. Gas produced from our interests is
sold by Encana at then prevailing market prices with
revenues from such sales, net of associated operating and
production costs, credited to our cost of gas. Annually, a
forecast is established for the amounts related to revenues,
costs, and production volumes expected, and any variances
between forecasted and actual results are subject to our
PGA incentive sharing in Oregon.
On March 28, 2014, we amended the original gas reserve
agreement in order to facilitate Encana's proposed sale of
its interest in the Jonah field to Jonah Energy, LLC. Under
the amendment, we ended the drilling program with Encana,
but increased our assigned ownership interests in certain
sections of the Jonah field and retained the right to invest in
additional wells with the new owner.
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, LLC and may have
the opportunity to participate in more wells in the future. We
filed an application requesting regulatory deferral in Oregon
for these additional investments. We filed in February 2015
seeking cost recovery for the additional wells drilled in 2014
and expect a decision on the prudence of these wells in
2015.
30
DECOUPLING. Decoupling is intended to break the link
between utility earnings and the quantity of gas consumed
by customers, removing any financial incentive by the utility
to discourage customers’ efforts to conserve energy.
The Oregon decoupling mechanism was reauthorized in the
2012 Oregon general rate case with the baseline
determined in our 2012 general rate case being used in
base rates. 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. Baseline
consumption reflects forecasted customer consumption data
used in the Oregon general rate case. In Washington,
customer use is not covered by such a tariff. See "Business
Segments—Local Gas Distribution Utility Operations" below.
WEATHER NORMALIZATION TARIFF. In Oregon, we have an
approved weather normalization mechanism, which is
applied to residential and commercial customer bills. This
mechanism is designed to help stabilize the collection of
fixed costs by adjusting residential and commercial
customer billings based on temperature variances from
average weather, with rate decreases when the weather is
colder than average and rate increases when the weather is
warmer than average. The mechanism is applied to bills
from December through May of each heating season. The
mechanism adjusts the margin component of customers’
rates to reflect average weather, which uses the 25-year
average temperature for each day of the billing period. Daily
average temperatures and 25-year average temperatures
are based on a set point temperature of 59 degrees
Fahrenheit for residential customers and 58 degrees
Fahrenheit for commercial customers. This weather
normalization mechanism was reauthorized in the 2012
Oregon general rate case without an expiration date.
Residential and commercial customers in Oregon are
allowed to opt out of the weather normalization mechanism,
and as of December 31, 2014, 7% 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). Since 2002, various
laws requiring minimum standards for integrity management
programs and SIPs for natural gas transmission and
distribution pipelines have been enacted. In January 2012
the Pipeline Safety, Regulatory Certainty, and Job Creation
Act of 2011 was signed into law and requires increased civil
penalties for pipeline safety violations, improvements in
prevention programs for pipelines, and additional review
and analysis of various aspects of gas transmission lines.
We work diligently with industry associations and federal
and state regulators to ensure our compliance with the
provisions of new laws.
The OPUC approved specific accounting treatment and cost
recovery for our transmission pipeline integrity management
program, our SIP, and for related pipeline safety rules
adopted by the U.S. Department of Transportation’s
PHMSA. In addition, the OPUC provided a two-year
extension to November 2014 of our capital expenditure
tracking mechanism to recover capital costs related to SIP.
We recorded the costs related to the integrity management
program as either capital expenditures or regulatory assets,
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 rate base recovery after the first $4
million of capital costs. An annual cap for expenditures was
set at $12 million, but extraordinary costs above the cap
could have been approved with written consent of the
OPUC staff and other interested parties and approval of the
OPUC. During 2013, the Commission approved a temporary
increase to the annual cap, authorizing an additional $13.7
million of expenditures above the cap over the following two
years to be tracked into rates. With the increased cap, we
plan to complete our bare steel replacement by the end of
2015, and as a result of this stipulation we are precluded
from tracking additional bare steel replacement costs into
rates after 2015. We do not have any special accounting or
rate treatment for SIP costs incurred in the state of
Washington.
We filed a request to extend the SIP program in the fourth
quarter of 2014, with slightly modified program parameters.
Specifically, we are seeking to track $8 million of SIP capital
costs into rates annually, after having the first $1 million of
SIP capital spend subject to regulatory lag. We expect to
resolve this request during 2015.
ENVIRONMENTAL COST DEFERRAL AND SRRM. The OPUC
has authorized the deferral of environmental costs
associated with certain named sites and the accrual of
carrying costs on amounts deferred, subject to an annual
demonstration that we have maximized our insurance
recovery or made substantial progress in securing
insurance recovery for unrecovered environmental
expenses. Through a series of extensions, the OPUC has
authorized us to defer environmental costs and accrued
carrying costs through January 2015, and the Company has
filed a docket requesting authorization to defer costs
through January 2016.
On February 20, 2015, the OPUC issued an order regarding
the Site Remediation and Recovery Mechanism (SRRM) for
recovering prudently incurred environmental site
remediation costs through customer billings, subject to an
earnings test. The OPUC order addressed a number of key
issues including: (1) prudence of all but $33 thousand of
costs incurred through March 31, 2014; (2) insurance
settlement proceeds of approximately $150 million were
deemed prudent with one-third of the proceeds applied to
costs prior to December 31, 2012 and two-thirds to offset
future environmental expenses; (3) in the order, the OPUC
31
A prepaid pension asset docket was opened in 2013 to
evaluate pension cost recovery for all utilities in Oregon.
The utilities have requested recovery of the financing costs
incurred as a result of timing differences between cash
contributions made to their pension plans and the
recognition of expense. A schedule was established to
resolve this docket in 2015. As noted above, the Company
currently recovers a portion of pension expense in rates and
has requested continued recovery of these expenses in the
docket.
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 from gas storage and
asset management of pipeline capacity and gas storage at
Mist. Generally amounts are credited to Oregon customers
in June, while credits are given to customers in Washington
through reductions in rates in the annual PGA filing in
November. The following table presents the credits to
customers:
In millions
Oregon utility
customer credit
Washington utility
customer credit
2014
2013
2012
$
11.4
$
8.8
$
0.8
0.5
9.2
0.8
disallowed recovery of expenses totaling approximately $15
million for costs related to 2003 to 2012.
With respect to remediation expenses deferred after 2012,
an aggregate of two-thirds of the environmental insurance
receipts, plus interest will be applied ratably over 20 years
and the remainder will be collected through the SRRM, and
subject to an earnings test as follows: (1) The Company will
recover the first $5 million of annual expense through a tariff
rider from customers; (2) the Company will apply $5 million
of insurance (plus interest accrued on insurance proceeds)
to environmental expenses each year; and (3) any
expenditures above the $10 million (plus interest) described
above would be fully recoverable through the SRRM, to the
extent the Company earns at or below its authorized Return
on Equity (ROE). See Note 16 for additional detail regarding
the earnings test and additional conditions related to these
amounts.
The Company continues to evaluate the effects of the order
and is required to file a compliance report with the OPUC
within 30 days of the order demonstrating how it will be
implemented. See Note 15 and Note 16 for additional detail.
The WUTC also authorized the deferral of environmental
costs, if any, that are appropriately allocated to Washington
customers. This order was effective January 26, 2011 with
cost recovery and a carrying charge to be determined in a
future proceeding.
PENSION COST DEFERRAL AND PREPAID PENSION ASSETS.
Effective January 1, 2011, the OPUC approved our request
to defer annual pension expenses above the amount set in
rates, with recovery of these deferred amounts through the
implementation of a balancing account, which includes the
expectation of higher and lower pension expenses in future
years. Our recovery of these deferred balances includes
accrued interest on the account balance at the utility’s
authorized rate of return, which is currently 7.78%. Future
years’ deferrals will depend on changes in plan assets and
projected benefit liabilities based on a number of key
assumptions, and our pension contributions. Pension
expense deferrals were $4.6 million and $9.1 million in 2014
and 2013, respectively. See "Application of Critical
Accounting Policies and Estimates" below. As noted above,
the Company continues to seek rate treatment for amounts
invested in prepaid pension assets.
32
Business Segments - Local Gas Distribution Utility
Operations
Our utility margin results are largely affected by customer
growth and, to a certain extent, by changes in volume due
to weather and customers’ gas usage patterns. In Oregon,
we have a conservation tariff and a weather normalization
tariff; both mechanisms are designed to reduce the volatility
of our utility’s earnings and customer charges. See
"Regulatory Matters—Rate Mechanisms" above.
Utility segment highlights include:
Dollars and therms in
millions, except EPS data
2014
2013
2012
Utility net income
$
58.6
$
54.9
$
EPS - utility segment
2.15
2.03
54.0
2.01
Gas sold and delivered
(in therms)
Utility margin(1)
344.5
(1) See Utility Margin Table below for a reconciliation and additional
detail.
1,093
1,112
366.1
353.9
1,146
$
$
$
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
$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 $1.5 million decrease in operations and maintenance
expense; and
a $2.1 million decrease in other income and expense,
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.
2013 COMPARED TO 2012. The primary factors contributing
to the $0.9 million or $0.02 per share increase in net income
were as follows:
•
a $9.4 million net increase in utility margin primarily due
to:
a $10.8 million increase related to customer growth
and the rate-base return on our gas reserves and
other investments, such as our pipeline integrity
tracker; and
a $3.9 million increase related to the timing
impacts of changes in fixed monthly charges and
decoupling baselines in the 2012 Oregon general
rate case. As a result of changes to the decoupling
baseline for average use per customer included in
the 2012 rate case, the decoupling mechanism's
results in 2013 were not comparable to 2012,
although the overall impact on revenues was
generally the same on an annualized basis.
These increases in margin were partially offset by:
a $3.9 million decrease in gains from gas cost
incentive sharing due to actual gas prices that
were roughly equivalent to estimated PGA prices
for 2013 as compared to actual gas prices that
were lower than estimated PGA prices for 2012;
and
a $1.4 million decrease primarily related to the
lower Oregon Authorized ROE of 9.5% from the
2012 general rate case.
•
•
a $1.5 million increase in other income and expense,
net primarily due to interest on higher average
regulatory account balances; and
a $2.7 million tax charge taken in 2012 from an Oregon
general rate case disallowance. See "Application of
Critical Accounting Policies and Estimates—Regulatory
Accounting" below.
These factors were partially offset by:
•
a $7.4 million increase in operations and maintenance
expense primarily due to increased utility payroll and
system maintenance and safety program costs;
a $2.9 million increase in depreciation and amortization
expense primarily due to a higher level of investment in
utility property, plant, and equipment; and
a $2.4 million increase in interest expense primarily due
to increases in long-term debt outstanding.
•
•
Total utility volumes sold and delivered in 2013 increased
3% over 2012 primarily due to the impact of colder
weather on residential and commercial use.
33
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
2014
2013
2012
Favorable/(Unfavorable)
2014 vs.
2013
2013 vs.
2012
Utility volumes (therms):
Residential and commercial sales
Industrial sales and transportation
620,903
472,087
671,906
474,525
637,885
473,884
(51,003)
(2,438)
34,021
641
Total utility volumes sold and delivered
1,092,990
1,146,431
1,111,769
(53,441)
34,662
Utility operating revenues:
Residential and commercial sales
Industrial sales and transportation
Other revenues
Less: Revenue taxes
Total utility operating revenues
Less: Cost of gas
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
$ 672,440
$
673,250
$ 642,337
$
(810)
$ 30,913
73,992
3,983
18,837
731,578
365,490
$ 366,088
$ 334,247
$
$
29,982
4,329
(2,135)
(335)
68,880
4,054
19,002
727,182
373,298
70,020
5,935
18,430
699,862
355,335
5,112
(71)
(165)
4,396
(7,808)
(1,140)
(1,881)
572
27,320
17,963
353,884
$ 344,527
$ 12,204
$
9,357
321,608
$ 306,382
$ 12,639
$ 15,226
28,335
4,308
(41)
(326)
28,586
4,452
3,811
1,296
1,647
21
(2,094)
(9)
(251)
(144)
(3,852)
(1,622)
$ 366,088
$
353,884
$ 344,527
$ 12,204
$
9,357
4,240
3,792
4,240
4,379
4,279
4,152
—
(13)%
(39)
5%
(11)%
3%
(3)%
637,411
66,304
929
628,634
621,399
8,777
65,321
918
63,619
923
983
11
7,235
1,702
(5)
8,932
Total number of customers
704,644
694,873
685,941
9,771
(1) Amounts reported as margin for each category of customers are operating revenues, which are net of revenue taxes, less cost of gas.
(2) Average weather represents the 25-year average degree days, as determined in our Oregon general rate case. For 2014 and 2013,
average weather represents the 25-year average degree days as set in our 2012 Oregon general rate case. For 2012, average weather
represents degree days based on the 25-year average set in our 2003 Oregon general rate for the months of January through October, plus
the 25-year average set in the 2012 Oregon general rate case for the months of November and December.
34
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 83% 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:
2014
2013
2012
381.5
239.4
620.9
418.6
253.3
671.9
395.5
242.4
637.9
Residential sales
$
441.5
$
447.4
$
428.5
Commercial sales
230.9
225.9
213.8
Total operating
revenues
Utility margin:
Residential:
Sales
Weather normalization
Decoupling
Total residential utility
margin
Commercial:
Sales
Weather normalization
Decoupling
Total commercial utility
margin
$
672.4
$
673.3
$
642.3
$
223.6
$
234.1
$
211.6
5.1
4.0
(9.0)
2.6
(0.1)
8.6
232.7
227.7
220.1
91.6
2.2
7.7
92.1
(4.0)
5.8
101.5
93.9
84.0
0.2
2.1
86.3
Total utility margin
$
334.2
$
321.6
$
306.4
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
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.
•
•
2013 COMPARED TO 2012. The primary factors contributing
to changes in the residential and commercial markets were
as follows:
•
sales volumes increased 34.0 million therms, or 5%,
primarily reflecting 5% colder weather and customer
growth;
operating revenues increased $30.9 million, or 5%, due
to a 5% increase in sales volumes and $36.2 million of
credits from gas cost savings which were applied to
customer billings in 2012, partially offset by a 9%
decrease in average gas prices, which flowed through
the Company's PGA rates; and
utility margin increased $15.2 million, or 5%, primarily
reflecting the following:
•
•
a $10.8 million increase related to customer growth
and the rate-base return on our gas reserves and
other investments; and
a $3.9 million increase related to the timing
impacts of changes in fixed monthly charges and
decoupling baselines in the 2012 Oregon general
rate case.
Partially offsetting these increases was a $1.4
million decrease primarily related to the lower
Oregon Authorized ROE of 9.5% from the 2012
general rate case.
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,
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):
2014
2013
2012
Industrial - firm sales
34.0
34.3
34.9
Industrial - firm
transportation
Industrial - interruptible
sales
Industrial - interruptible
transportation
Total volumes
Utility margin:
Industrial - sales and
transportation
153.6
144.5
131.2
76.4
59.5
59.6
208.1
472.1
236.2
474.5
248.2
473.9
$
30.0
$
28.3
$
28.6
35
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.
•
2013 COMPARED TO 2012. The primary factors contributing
to changes in the industrial sales and transportation markets
were as follows:
•
sales volumes remained relatively flat for 2013
compared to 2012; and
utility margin decreased 1%, primarily due to lower
demand from customers in the pulp and paper
segment. These decreases were partially offset by
contributions from new customers and added load from
existing customers.
•
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 highlights include:
In millions
2014
2013
2012
Other revenues
$
4.0
$
4.1
$
5.9
2014 COMPARED TO 2013. Other revenues remained
relatively flat year over year.
2013 COMPARED TO 2012. The primary factors contributing
to changes in other revenues were as follows:
•
other revenues decreased $1.9 million primarily due to
a positive 2012 regulatory adjustment which did not
reoccur in 2013.
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 reserve 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 whereby we either increase or decrease
margin results based on a percentage of actual gas costs as
compared to embedded gas costs in the PGA. Under this
provision, our net income can be affected by differences
between actual and expected gas costs, which occur
36
primarily because of market fluctuations and volatility
affecting unhedged gas purchases in the PGA. In addition,
we have a regulatory agreement where we earn a rate-base
return on our investment in gas reserves, which is reflected
in utility margin. See "Regulatory Matters—Rate
Mechanisms—Purchased Gas Adjustment and Gas
Reserves" above.
We use natural gas commodity hedge contracts (derivative
instruments), primarily fixed-price commodity swaps,
consistent with our financial derivatives policies to help
manage gas price stability. Gains and losses from these
financial hedge contracts are generally included in our PGA
and normally do not impact net income because the hedged
prices are reflected in our annual PGA rates, subject to a
regulatory prudence review. However, hedge contracts
entered into after the annual PGA rates are set for Oregon
customers can impact net income because we would be
required to share in any gains or losses as compared to the
corresponding commodity prices built into rates in the PGA.
In Washington, 100% of the actual gas costs, including
hedge gains and losses allocated to Washington gas sales,
are passed through in customer rates. See "Application of
Critical Accounting Policies and Estimates—Accounting for
Derivative Instruments and Hedging Activities" below,
"Regulatory Matters—Rate Mechanisms—Purchased Gas
Adjustment" above, and Note 13.
Cost of gas highlights include:
Dollars and therms in
millions
2014
2013
2012
Cost of gas
$
365.5
$
373.3
$
355.3
Volumes sold (therms)
716
766
732
Average cost of gas
(cents per therm)
Gain (loss) from gas cost
incentive sharing
$
0.51
$
0.49
$
0.54
(2.1)
—
3.8
2014 COMPARED TO 2013. The primary factors contributing
to changes in cost of gas were as follows:
•
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.
2013 COMPARED TO 2012. The primary factors contributing
to changes in cost of gas were as follows:
•
cost of gas increased $18.0 million, or 5%, including the
$37.7 million of credits applied to customer billings in
2012 related to the refund of gas cost savings.
Excluding the customer credits, total cost of gas
decreased $19.7 million, or 5%, primarily due to a 5%
increase in volumes offset by a 9% decrease in
average cost of gas collected through rates, reflecting
lower market prices for natural gas.
During the first quarter of 2014, many parts of the United
States experienced record cold weather for an extended
period, while the Pacific Northwest temperatures were
closer to normal averages. The extreme cold weather in
early 2014 resulted in significant withdrawals of gas from
storage and higher gas prices compared to 2013. In early
February 2014, the Pacific Northwest had extreme cold
weather for a few days that resulted in a record sendout for
our utility. Consequently, higher volumes of gas purchases
and higher gas prices during this period resulted in a margin
loss of $2.1 million for 2014 under our gas cost incentive
sharing mechanism. The effect on net income from our gas
cost incentive sharing mechanism for 2013 was a pre-tax
gain in margin of less than $0.1 million, compared to a pre-
tax gain of $3.8 million for 2012. For a discussion of our gas
cost incentive sharing mechanism, see “Regulatory Matters
—Rate Mechanisms—Purchased Gas Adjustment” above.
Business Segments - Gas Storage
Our gas storage segment primarily consists of the non-utility
portion of our Mist underground storage facility in Oregon
and our 75% ownership interest in the Gill Ranch
underground storage facility in California.
At Mist, we provide gas storage services to customers in the
interstate and intrastate markets primarily using storage
capacity that has been developed in advance of core utility
customers’ requirements. We also contract with an
independent energy marketing company to provide asset
management services using our utility and non-utility
storage and transportation capacity, the results of which are
included in the gas storage businesses segment. Pre-tax
income from gas storage at Mist and asset management
services using our utility's storage and transportation
capacity 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.
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 Note 4.
Gas storage segment highlights include:
In millions, except EPS
data
2014
2013
2012
Gas storage net income
$
(0.4) $
5.6
$
4.5
EPS - gas storage
segment
Operating revenue
Operating expense
(0.01)
22.2
18.2
0.21
31.1
16.4
0.17
30.5
17.3
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. See additional information regarding these
expense trends below.
•
2013 COMPARED TO 2012. Our gas storage segment net
income increased $1.0 million primarily due to higher
revenues from asset management services and lower
operating costs.
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 this past 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 substantially lower market prices
than in previous years. These trends accounted for most of
the decline in gas storage operating revenues.
We incurred an additional $2.4 million of repair and power
costs at Gill Ranch during 2014 compared to 2013. The
increase in power costs is primarily due to higher injections
into storage during 2014 to replenish low storage levels
following higher withdrawals during the 2013-14 winter. The
additional repair costs were for maintenance work at the Gill
Ranch facility, which has now been in operation for three
annual cycles. We are continuing to evaluate potential
capital improvements that may be needed to enhance the
operations of the facility. See "Financial Condition—Liquidity
and Capital Resources" and "Financial Condition—Cash
Flows—Investing Activities" for more information below.
Our gas storage segment financial results have been
negatively impacted in the short term by the decline in
market conditions and higher than normal repair costs
incurred this year. Despite these conditions, we continue to
believe in the long-term need for gas storage in California
and have recently seen a slight increase in contracting
prices. In the future, we anticipate a rebound 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, 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 market conditions in and around
California. These factors would likely result in higher
summer/winter natural gas price spreads, gas price
volatility, and gas storage values. Refer to Note 2 for more
information regarding our accounting for impairment of long-
lived assets.
37
Other
Other primarily consists of NNG Financial's equity
investment in KB Pipeline, an equity investment in TWH,
which in turn has invested in the Trail West pipeline project,
and other miscellaneous non-utility investments and
business activities. See Note 4 and Note 12 for further
details on other activities and our investment in TWH.
Other highlights include:
In millions, except EPS
data
2014
2013
2012
Other net income
$
0.5
$
— $
EPS - other
0.02
—
0.2
—
2014 COMPARED TO 2013. Other net income increased $0.5
million primarily due to increased merchandise sales from
our natural gas appliance store.
2013 COMPARED TO 2012. Other net income remained
relatively flat, as anticipated.
Consolidated Operations
Operations and Maintenance
Operations and maintenance highlights include:
In millions
2014
2013
2012
Operations and maintenance
$ 137.0
$ 136.6
$ 129.5
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.
•
•
•
2013 COMPARED TO 2012. Operations and maintenance
expense increased $7.1 million, or 6%, primarily due to the
following factors:
•
a $5.9 million increase in utility payroll expense
primarily related to additional customer service
positions for new programs and higher incentive
compensation; and
a $2.7 million increase in utility expenses related to
system maintenance and safety program costs.
•
Partially offsetting the above factors were:
•
a $0.9 million decrease in utility bad debt expense. See
further discussion below.
Delinquent customer receivable balances have remained
low for several years despite challenging economic
conditions during the recession. This sustained, favorable
trend resulted in a decrease to our allowance for
uncollectible accounts in the first quarter of 2013, and bad
debt expense continues to remain at historically low levels
for the Company. The utility's bad debt expense as a
percent of revenues was 0.1% for 2014 and has remained
well below 0.5% of revenues every year since 2007.
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 year ended December 31, 2014 and 2013 we
deferred pension expenses totaling $4.6 million and $9.1
million, respectively. As a result, increased pension costs
had a minimal effect on operations and maintenance
expense in 2014 and 2013, 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
2014
2013
2012
Depreciation and amortization
$
79.2
$
75.9
$
73.0
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.
2013 COMPARED TO 2012. Depreciation and amortization
expense for 2013 increased by $2.9 million compared to
2012 due to an increase in utility depreciation expense on
investments in utility plant for system improvements and
training facilities.
Other Income and Expense, Net
Other income and expense, net highlights include:
In millions
2014
2013
2012
Gains from company-
owned life insurance
$
Interest income
Loss on sale of
investments
Loss from equity
investments
Net interest on deferred
regulatory accounts
Other non-operating
Total other income and
expense, net
$
2.0
0.1
—
(0.2)
2.4
(2.4)
$
2.5
0.1
—
(0.1)
4.5
(2.3)
2.3
0.2
(0.2)
—
3.0
(2.1)
$
1.9
$
4.7
$
3.2
2014 COMPARED TO 2013. Other income and expense, 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,
38
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.
2013 COMPARED TO 2012. Other income and expense, net
increased $1.5 million primarily due to interest on higher
average regulatory account balances.
Interest Expense, Net
Interest expense, net highlights include:
In millions
2014
2013
2012
Interest expense, net
$
44.6
$
45.2
$
43.2
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.
2013 COMPARED TO 2012. Interest expense, net of amounts
capitalized, increased $2.0 million primarily due to an
increase of $2.3 million at the utility from the issuance of
long-term debt. The utility issued $50 million of debt with a
coupon rate of 3.542% in August 2013 and $50 million of
debt with a coupon rate of 4.00% in October 2012. This
increase was partially offset by a $0.7 million reduction in
2013 interest expense at the utility from the retirement of
$40 million of long-term debt with a coupon rate of 7.13% in
2012. See Note 7 for further detail.
Income Tax Expense
Income tax expense highlights include:
In millions
2014
2013
2012
Income tax expense
$ 41.6
$ 41.7
$ 43.4
Effective tax rate
41.5%
40.8%
42.5%
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.
2013 COMPARED TO 2012. The decrease in income tax
expense of $1.7 million or 4% was primarily due to a $2.7
million tax charge taken in 2012 from an Oregon general
rate case disallowance.
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
39
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,
2014
2013
46.1%
44.7%
37.4
16.5
40.5
14.8
100.0%
100.0%
Liquidity and Capital Resources
At both December 31, 2014 and 2013 we had $9.5 million of
cash and cash equivalents. We also had $3.0 million and
$4.0 million in restricted cash at Gill Ranch as of December
31, 2014 and 2013, respectively. This restricted cash is
being held as collateral for the long-term debt outstanding.
In order to maintain sufficient liquidity during periods when
capital markets are volatile, we may elect to maintain higher
cash balances and add short-term borrowing capacity. In
addition, we may also pre-fund utility capital expenditures
when long-term fixed rate environments are attractive. As a
regulated entity, our issuance of equity securities and most
forms of debt securities are subject to approval by the
OPUC and WUTC. Our use of retained earnings is not
subject to those same restrictions.
For the utility segment, the short-term borrowing
requirements typically peak during colder 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, 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
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, 2014, we have Board authorization to issue
up to $325 million of additional FMB's. 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, 2014. However, if the credit risk-related
contingent features underlying these contracts were
triggered on December 31, 2014, assuming our long-term
debt ratings dropped to non-investment grade levels, we
could have been required to post $27.1 million of collateral
to our counterparties. See "Credit Ratings" below and
Note 13.
Other recent developments that may have a significant
impact on our liquidity and capital resources include pension
contribution requirements, income tax benefits from bonus
depreciation, environmental expenditures and insurance
recoveries.
With respect to pensions, we expect to make significant
contributions to our company-sponsored defined benefit
plan, which is closed to new employees, over the next
several years until we are fully funded under the Pension
Protection Act rules, including the new rules issued under
the Moving Ahead for Progress in the 21st Century Act
(MAP-21) and the Highway and Transportation Funding Act
of 2014 (HATFA). See "Application of Critical Accounting
Policies—Accounting for Pensions and Postretirement
Benefits" below.
Regarding income tax, 50 percent bonus depreciation was
available for a large portion of our capital expenditures in
2012, 2013, and 2014 for both federal and Oregon. This
generated income tax net operating losses (NOLs) in 2012
and 2013, and reduced taxable income in 2014. This
provided cash flow benefits and is expected to provide cash
flow benefits in subsequent years while NOLs from these
periods are utilized. The Company estimates that it has
income tax NOL carryforwards of $28.8 million for federal
and $49.4 million for Oregon at December 31, 2014.
Concerning environmental expenditures, we expect to
continue using cash resources to fund our environmental
liabilities. In 2014, we received insurance settlements in
excess of amounts spent and will begin recovering amounts
through utility rates under the SRRM in 2015. These
expenditures are uncertain as to the amount and timing.
See Note 15, Note 16, and "Results of Operations—
Regulatory Matters—Environmental Costs".
Short-term liquidity for the gas storage segment is
supported by cash balances, internal cash flow from
operations, external financing, and funds from its parent
company. The abundant supply of natural gas, low volatility
of natural gas prices, and available gas storage capacity,
particularly in California, have recently resulted in lower
storage market prices than we have seen in previous years.
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 contracted
for the 2014-15 gas year at lower prices than the prior year
and have realized higher repairs and power costs in 2014.
Both factors contributed to negative cash flows from
operations for 2014. We expect continuing challenges for
Gill Ranch in 2015, however, we have seen improvement in
pricing for the upcoming 2015-16 gas storage year. Though
prices are still lower than our long-term contracts that
expired during the 2013-14 gas storage year. 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
secured 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 is subject to certain
covenants and restrictions. We amended the original
agreement in April 2014 to retire the $20 million variable-
rate outstanding debt during the second quarter of 2014 and
suspend the EBITDA covenant requirement through March
31, 2015 with lower EBITDA hurdles thereafter. The
amendment fixed the debt service reserve at $3 million. Gill
Ranch retired $20 million of debt on June 6, 2014 using
available cash and cash flows from operations, including
cash from intercompany receivables. The remaining $20
million of outstanding debt is secured by all of the
membership interests in Gill Ranch and is nonrecourse to
NW Natural and other entities of the consolidated group. We
do not anticipate meeting the adjusted covenant
requirements in 2015 and are working with our lender to
negotiate an extension of the covenants or early redemption
of the debt.
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
the Company's liquidity is sufficient to meet anticipated
near-term cash requirements, including all contractual
obligations, investing, and financing activities discussed
below.
Dividend Policy
We have paid quarterly dividends on our common stock
each year since stock was first issued to the public in 1951.
Annual common stock dividend payments per share,
adjusted for stock splits, have increased each year since
1956. The declarations and amount of future dividends will
depend upon our earnings, cash flows, financial condition
and other factors. The amount and timing of dividends
payable on our common stock is at the sole discretion of our
Board of Directors.
Off-Balance Sheet Arrangements
Except for certain lease and purchase commitments, we
have no material off-balance sheet financing arrangements.
See "Contractual Obligations" below.
40
Contractual Obligations
The following table shows our contractual obligations at December 31, 2014 by maturity and type of obligation:
In millions
Commercial paper
Long-term debt maturities
Interest on long-term debt
Postretirement benefit payments(1)
Capital leases
Operating leases
Gas purchases(2)
Gas pipeline capacity commitments
Other purchase commitments(3)
Other long-term liabilities(4)
Payments Due in Years Ending December 31,
2015
2016
2017
2018
2019
Thereafter
Total
$
234.7
$
— $
— $
— $
— $
— $
40.0
36.9
22.7
0.7
5.5
132.4
84.3
0.1
16.2
45.0
35.7
23.5
0.6
5.5
—
79.2
—
—
40.0
32.1
24.3
0.1
5.4
—
58.8
—
—
22.0
29.2
25.4
—
5.3
—
50.8
—
—
30.0
28.6
26.8
—
5.2
—
26.7
—
—
484.7
201.9
156.4
—
29.8
—
205.3
13.6
—
234.7
661.7
364.4
279.1
1.4
56.7
132.4
505.1
13.7
16.2
Total
2,265.4
$
(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
the Company withdrawing from the plan in December 2013. See Note 8.
1,091.7
573.5
117.3
189.5
160.7
132.7
$
$
$
$
$
$
(2) Gas purchases include contracts which use price formulas tied to monthly index prices, plus hedged derivative liabilities. Commitment
amounts are based on futures prices as of December 31, 2014. For a summary of derivatives, see Note 13. 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, 2014, 612 of our utility employees were
members of the Office and Professional Employees
International Union (OPEIU) Local No. 11. On May 22,
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
internal cash flows and the sale of commercial paper. In
addition to issuing commercial paper to meet working
capital requirements, including seasonal requirements to
finance gas purchases and accounts receivable, short-term
debt may also be used to temporarily fund utility capital
requirements. Commercial paper is periodically refinanced
through the sale of long-term debt or equity securities. Our
outstanding commercial paper, which is sold through two
commercial banks under an issuing and paying agency
agreement, is supported by one or more unsecured
revolving credit facilities. See “Credit Agreements” below. At
December 31, 2014 and 2013, our utility had commercial
paper outstanding of $234.7 million and $188.2 million,
respectively. The effective interest rate on the utility’s
commercial paper outstanding at December 31, 2014 and
2013 was 0.4% and 0.3%, respectively.
Credit Agreements
On December 20, 2012, NW Natural entered into a five-year
$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 credit
agreement also permits an extension of the commitments
for two additional one-year periods, subject to lender
approval. The Company exercised the first of these
extensions in December 2013, and the second in December
2014 with a final maturity date of December 20, 2019.
41
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
7.13% Series B due 2012
3.95% Series B due 2014
8.26% Series B due 2014
Subsidiary Debt
Variable-rate
Years Ended December 31,
2014
2013
2012
$
— $
— $
50
10
60
20
80
$
—
—
—
—
$
— $
40
—
—
40
—
40
All lenders under the new agreement are major financial
institutions with committed balances and investment grade
credit ratings as of December 31, 2014 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, the Company does not believe this risk to be
imminent due to the lenders' strong investment-grade credit
ratings.
In December 2014, the Company amended the credit
agreement to reduce the permitted letter of credit amount
from $200 million 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, 2014 or 2013. 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, 2014 and
2013, with consolidated indebtedness to total capitalization
ratios of 53.9% and 55.3%, 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.
42
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
2014
2013
2012
Cash provided by operating
activities
$ 215.7
$ 176.4
$ 168.8
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.
•
•
•
•
•
2013 COMPARED TO 2012. The significant factors
contributing to the $7.6 million increase in operating cash
flows were as follows:
• an increase of $15.8 million in other, net primarily due to
inflows from changes in net regulatory balances offset by
a decrease in pension liabilities;
• an increase of $12.4 million from net changes in gas cost
balances, which primarily reflects $39 million in credits
refunded to customers in 2012;
• an increase of $11.8 million due to lower cash
contributions to qualified defined benefit pension plans as
a result of new IRS funding rules, commonly referred to
as MAP-21;
• an increase of $8.0 million from changes in accounts
payable balances; and
• an increase of $4.7 million due to changes in the
amortization of gas reserves balance.
Partially offsetting these increases was:
• a decrease of $48.3 million from changes in the accounts
receivable balance, primarily due to customer growth and
29% colder weather in December 2013.
During the year ended December 31, 2014, we contributed
$10.5 million to our utility's qualified defined benefit pension
plan, compared to $11.7 million for 2013. We expect
contribution amounts in the near-term will be less than
previously anticipated due to the federal funding
requirements under MAP-21 and HATFA.
43
The amounts and timing of future contributions will depend
on market interest rates and investment returns on the
plans’ assets. See Note 8.
Bonus depreciation of 50 percent has been available for
federal and Oregon purposes in 2012, 2013, and 2014. This
generated income tax NOLs in 2012 and 2013, and reduced
taxable income in 2014. This provided cash flow benefits in
2012 and 2013 and is expected to provide cash flow
benefits in subsequent years while NOL carryforwards from
these periods are utilized. Bonus depreciation for 2014 was
not enacted until December of 2014, when it was extended
retroactively back to January 1, 2014. As a result, estimated
income tax payments were made throughout 2014 without
the benefit of bonus depreciation for the year. This reduced
the cash flow benefit of bonus depreciation in 2014 and
contributed to the prepaid income tax balance of $6.7 million
and income tax receivable balance of $1.0 million, as of
December 31, 2014.
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
2014
2013
2012
Total cash used in (provided
by) investing activities
$ 144.3
$ 182.1
$ 184.7
Capital expenditures
120.1
138.9
132.0
Proceeds from sale of
assets
Utility gas reserves
(0.2)
26.8
(8.6)
54.1
—
54.1
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.
2013 COMPARED TO 2012. The $2.5 million decrease in cash
used in investing activities was due to proceeds received
from the sale of assets. This decrease was partially offset
by higher capital expenditures, reflecting increased
investments for new customer acquisitions, completion of
our Gasco Source Control water treatment station, and
additional expenditures for system integrity and bare steel
pipe removal.
Over the five-year period 2015 through 2019, 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. The
estimated level of utility capital expenditures over the next
five years reflects assumptions for continued customer
growth, technology, distribution system improvements, and
gas storage facilities. Most of the required funds are
expected to be internally generated over the five-year
period, and any remaining funding will be obtained through
a combination of long-term debt and equity security
issuances, with short-term debt providing liquidity and
bridge financing.
In 2015, utility capital expenditures are estimated to be
between $140 and $150 million, and non-utility capital
investments are estimated to be less than $10 million. Gas
storage segment capital expenditures in 2015 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
2014
2013
2012
Total cash provided by (used
in) financing activities
$
(71.3) $
6.3
$
Change in short-term debt
Change in long-term debt
46.5
(80.0)
(2.1)
50.0
18.9
48.7
10.0
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.
2013 COMPARED TO 2012. The $12.6 million decrease in
cash provided by financing activities was primarily due to
changes in our short-term debt balances, which decreased
$2.1 million in 2013 compared to an increase of $48.7
million in 2012. This decrease was partially offset by
changes in our long-term debt balances due to $40 million
of long-term debt retired in 2012. We continue to use long-
term debt proceeds to finance capital expenditures,
refinance maturing short-term or long-term debt maturities,
and to fund other general corporate purposes.
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 $14.2 million in 2014, a decrease of $7.3
million from 2013. The fair market value of pension assets in
this plan increased to $279.2 million at December 31, 2014
from $267.1 million at December 31, 2013. The increase
was due to a return on plan assets of $20.0 million plus
$10.5 million in employer contributions, partially offset by
benefit payments of $18.4 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 $172.0 million at
December 31, 2014. We plan to make contributions during
2015 of $15 million. See Note 8 for further pension
disclosures.
Ratios of Earnings to Fixed Charges
For the years ended December 31, 2014, 2013, and 2012,
our ratios of earnings to fixed charges, computed using the
Securities and Exchange Commission (SEC) method,
were 3.13, 3.16, and 3.26, 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, 2014, we had a net regulatory asset of $58.9
million for deferred environmental costs, which included
$95.5 million for additional costs expected to be paid in the
future and $19.7 million of accrued interest. Additionally, in
2014, a settlement was reached in our environmental
insurance recovery litigation, and NW Natural received $103
million in recoveries for a cumulative total of approximately
$150 million. The regulatory asset for deferred
environmental costs is calculated net of insurance
reimbursements. In February 2015, the OPUC issued an
order regarding the Site Remediation and Recovery
Mechanism (SRRM) for recovering prudently incurred
environmental site remediation costs through customer
billings, subject to an earnings test. The order applied an
earnings test to a historical period 2003 through 2012 that
resulted in a regulatory disallowance of $15 million pre-tax
to be recorded in the first quarter of 2015. 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.
44
APPLICATION OF CRITICAL ACCOUNTING POLICIES
AND ESTIMATES
In preparing our financial statements using GAAP,
management exercises judgment in the selection and
application of accounting principles, including making
estimates and assumptions that affect reported amounts of
assets, liabilities, revenues, expenses and related
disclosures in the financial statements. Management
considers our critical accounting policies to be those which
are most important to the representation of our financial
condition and results of operations and which require
management’s most difficult and subjective or complex
judgments, including accounting estimates that could result
in materially different amounts if we reported under different
conditions or used different assumptions. Our most critical
estimates and judgments include accounting for:
• regulatory accounting;
• revenue recognition;
• derivative instruments and hedging activities;
• pensions and postretirement benefits;
• income taxes; and
• environmental contingencies.
Management has discussed its current estimates and
judgments used in the application of critical accounting
policies with the Audit Committee of the Board. Within the
context of our critical accounting policies and estimates,
Management is not aware of any reasonably likely events or
circumstances that would result in materially different
amounts being reported. For a description of recent
accounting pronouncements that could have an impact on
our financial condition, results of operations or cash flows,
see Note 2.
Regulatory Accounting
Our utility is regulated by the OPUC and WUTC, which
establish the rates and rules governing utility services
provided to customers, and, to a certain extent, set forth
special accounting treatment for certain regulatory
transactions. In general, we use the same accounting
principles as non-regulated companies reporting under
GAAP. However, authoritative guidance for regulated
operations (regulatory accounting) requires different
accounting treatment for regulated companies to show the
effects of such regulation. For example, we account for the
cost of gas using a PGA deferral and cost recovery
mechanism, which is submitted for approval annually to the
OPUC and WUTC. See "Results of Operations—Regulatory
Matters—Rate Mechanisms—Purchased Gas Adjustment"
above. There are other expenses and revenues that the
OPUC or WUTC may require us to defer for recovery or
refund in future periods. Regulatory accounting requires us
to account for these types of deferred expenses (or deferred
revenues) as regulatory assets (or regulatory liabilities) on
the balance sheet. When we are allowed to recover these
regulatory assets from, or are required to refund regulatory
liabilities to, customers, we recognize the expense or
revenue on the income statement at the same time we
realize the adjustment to amounts included in utility rates
charged to customers.
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, 2014
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, 2014 and 2013
was $101.2 million and $60.4 million, respectively. See Note
2 "Industry Regulation". See Note 16 for information
regarding the resolution of the environmental Site
Remediation and Recovery Mechanism (SRRM) in February
2015 and a $15 million pre-tax regulatory disallowance to be
recognized in the first quarter of 2015.
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.
2014
Up 1%
Down 1%
$
0.6
$
(0.6)
—
—
—
—
Derivative Instruments and Hedging Activities
Our gas acquisition and hedging policies set forth guidelines
for using financial derivative instruments to support prudent
risk management strategies. These policies specifically
prohibit the use of derivatives for trading or speculative
purposes. The accounting rules for determining whether a
45
contract meets the definition of a derivative instrument or
qualifies for hedge accounting treatment are complex. The
contracts that meet the definition of a derivative instrument
are recorded on our balance sheet at fair value. If certain
regulatory conditions are met, then the derivative instrument
fair value is recorded together with an offsetting entry to a
regulatory asset or liability account pursuant to regulatory
accounting (see Note 2, "Industry Regulation"), and no
unrealized gain or loss is recognized in current income. The
gain or loss from the fair value of a derivative instrument
subject to regulatory deferral is included in the recovery
from, or refund to, utility customers in future periods (see
"Regulatory Accounting", above). If a derivative contract is
not subject to regulatory deferral, then the accounting
treatment for unrealized gains and losses is recorded in
accordance with accounting standards for derivatives and
hedging (see Note 2, "Derivatives” and "Industry
Regulation") which is either in current income or in
accumulated other comprehensive income (AOCI) under
common stock equity on the balance sheet. Our derivative
contracts outstanding at December 31, 2014 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
2014
2013
2012
Net utility gain (loss) on:
Commodity
Swaps
Options
Total net gain (loss)
realized
$
$
10.5
$
(11.0) $
(69.5)
—
—
(0.7)
10.5
$
(11.0) $
(70.2)
Realized losses from commodity hedges shown above were
recorded as increases to cost of gas and were included in
our annual PGA rates.
Pensions and Postretirement Benefits
We maintain a qualified non-contributory defined benefit
pension plan, 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
employees of NW Natural subsidiaries are provided an
46
enhanced Retirement K Savings Plan benefit. The
postretirement Welfare Benefit Plan for non-union
employees was also closed to new participants several
years ago.
Net periodic pension and postretirement benefit costs
(retirement benefit costs) and projected benefit obligations
(benefit obligations) are determined using a number of key
assumptions including discount rates, rate of compensation
increases, retirement ages, mortality rates and an expected
long-term return on plan assets. See Note 8. These key
assumptions have a significant impact on the pension
amounts recorded and disclosed. Retirement benefit costs
consist of service costs, interest costs, the amortization of
actuarial gains, losses and prior service costs, the expected
returns on plan assets and, in part, on a market-related
valuation of assets, if applicable. The market-related asset
valuation reflects differences between expected returns and
actual investment returns, which we recognize over a three-
year period or less from the year in which they occur,
thereby reducing year-to-year volatility in retirement benefit
costs.
Accounting standards also require balance sheet
recognition of the overfunded or underfunded status of
pension and postretirement benefit plans in AOCI or AOCL,
net of tax, based on the fair value of plan assets compared
to the actuarial value of future benefit obligations. However,
the retirement benefit costs related to our qualified defined
benefit pension and postretirement benefit plans are
generally recovered in utility rates, which are set based on
accounting standards for pensions and postretirement
benefit expenses. As such, we received approval from the
OPUC to recognize the overfunded or underfunded status
as a regulatory asset or regulatory liability based on
expected rate recovery, rather than including it as AOCI or
AOCL under common equity. See "Regulatory Accounting"
above and Note 2, "Industry Regulation".
In 2011, we received regulatory approval from the OPUC
and began deferring a portion of our pension expense
above or below the amount set in rates to a regulatory
balancing account on the balance sheet. At December 31,
2014, the cumulative amount deferred for future pension
cost recovery was $32.5 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, 2014 measurement date, we
reviewed and updated:
•
our weighted-average discount rate assumptions for
pensions went from 4.73% for 2013 to 3.85% for 2014,
and our weighted-average discount rate assumptions
for other postretirement benefits went from 4.45% for
2013 to 3.74% for 2014. The new rate assumptions
were determined for each plan based on a matching of
benchmark interest rates to the estimated cash flows,
which reflect the timing and amount of future benefit
payments. Benchmark interest rates are drawn from the
Citigroup Above Median Curve, which consists of high
quality bonds rated AA- or higher by S&P or Aa3 or
higher by Moody’s;
our expected annual rate of future compensation
increases, which remained unchanged at a range of
3.25% to 5.0%;
our expected long-term return on qualified defined
benefit plan assets, which remained unchanged at a
rate of 7.50%;
our mortality rate assumptions were updated to the new
RP 2014 combined tables for the pension and
postretirement benefit plans. This assumption is used
to calculate life expectancies for participants in the
plan. The new RP 2014 tables assume greater life
expectancy which increased the projected benefit
obligations of the plans; and
other key assumptions, which were based on actual
plan experience and actuarial recommendations.
•
•
•
•
At December 31, 2014, our net pension liability (benefit
obligations less market value of plan assets) for the
qualified defined benefit plan increased $76.7 million
compared to 2013. The increase in our net pension liability
is primarily due to the $88.8 million increase in our pension
benefit obligation and an increase of $12.1 million in plan
assets. The liability for non-qualified plans increased $7.4
million, and the liability for other postretirement benefits
increased $3.3 million in 2014.
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,
2014, the actual annualized returns on plan assets, net of
management fees, for the past one-year, five-years, and 10-
years were 7.9%, 8.0%, and 5.1%, 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
2014
Retirement
Benefit
Costs
Impact on
Retirement
Benefit
Obligations
at Dec. 31,
2014
$
1.4
$
—
0.1
16.3
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
47
increases, which reduces the level of minimum required
contributions in the near-term but generally increases
contributions in the long-run as well as increasing the
operational costs of running a pension plan. Prior to the
MAP-21 Act, we were using interest rates based on a 24-
month average yield of investment grade corporate bonds
(also referred to as "segment rate") to calculate minimum
contribution requirements. MAP-21 Act established a new
minimum and maximum corridor for segment rates based
on a 25-year average of bond yields, which is to be used in
calculating contribution requirements. In 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 assets
currently recorded represent income tax net operating loss
carryforwards and 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, 2014. 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
Program (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 2012, 2013, or
2014. 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. As part of the 2012 Oregon
general rate case, the OPUC ruled that we cannot recover
deferred amounts that represent the increase in deferred
income taxes caused by the 2009 Oregon tax rate change.
As a result, we recognized an after-tax charge of $2.7
million in 2012 to write off the regulatory asset related to this
rate change. At December 31, 2014 and 2013, we have
regulatory income tax assets of $51.8 million and $56.2
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.
monthly re-pricing, a strategy that is intended to
substantially mitigate credit exposure to our physical gas
counterparties.
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 are
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 2015. 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 Tax Increase Prevention Act of 2014, signed
into law on December 19, 2014, retroactively extended for
one year various temporary income tax deductions, credits,
and incentives that expired at the end of 2013, including 50
percent bonus depreciation for certain qualifying property
placed in service through 2014. 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 see Note 2. For a
discussion of our current environmental sites and liabilities
see 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.
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 gas
purchase contracts are primarily index-based and subject to
48
Commodity Price and Storage Value Risk
Natural gas commodity prices and storage values are
subject to market fluctuations due to unpredictable factors
including weather, pipeline transportation congestion, drilling
technologies, potential market speculation, and other factors
that affect supply and demand. We also manage commodity
price risk with 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.
Interest Rate Risk
We are exposed to interest rate risk primarily associated
with new debt financing needed to fund capital
requirements, including future contractual obligations and
maturities of long-term and short-term debt. Interest rate risk
is primarily managed through the issuance of fixed-rate debt
with varying maturities. We may also enter into financial
derivative instruments, including interest rate swaps, options
and other hedging instruments, to manage and mitigate
interest rate exposure.
Foreign Currency Risk
The costs of certain natural gas commodity supplies and
certain pipeline 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
and commodity-related demand and reservation charges
paid in Canadian dollars. If all of the foreign currency
forward contracts had been settled on December 31, 2014,
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 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, 2014, 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, 2014, 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 millions
AAA/Aaa
AA/Aa
A/A
BBB/Baa
Total
Financial Derivative Position by Credit Rating
Unrealized Fair Value Gain (Loss)
2014
2013
$
$
— $
(27.2)
(3.4)
—
(30.6) $
—
4.5
0.9
—
5.4
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 are exposed to weather risk primarily from our regulated
utility business. A large percentage of our utility margin is
volume driven, and current rates are based on an
assumption of average weather. We have a weather
normalization mechanism in Oregon 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,
2014, approximately 7% 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 less than
20% of all residential and commercial customers. See
"Results of Operations—Regulatory Matters—Rate
Mechanism—Weather Normalization Tariff" above.
49
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, 2014, 2013, and 2012
Consolidated Balance Sheets at December 31, 2014 and 2013
Consolidated Statements of Shareholders’ Equity for the Years Ended December 31, 2014, 2013, and 2012
Consolidated Statements of Cash Flows for the Years Ended December 31, 2014, 2013, and 2012
Notes to Consolidated Financial Statements
Quarterly Financial Information (Unaudited)
Supplementary Data for the Years Ended December 31, 2014, 2013, and 2012:
Financial Statement Schedule
Schedule II – Valuation and Qualifying Accounts and Reserves
Supplemental Schedules Omitted
Page
51
52
53
54
56
57
58
86
86
All other schedules are omitted because of the absence of the conditions under which they are required or because the required
information is included elsewhere in the financial statements.
50
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, 2014. 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, 2014.
The effectiveness of internal control over financial reporting as of December 31, 2014 has been audited by
PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears in this
annual report.
/s/ Gregg S. Kantor
Gregg S. Kantor
President and Chief Executive Officer
/s/ Stephen P. Feltz
Stephen P. Feltz
Senior Vice President and Chief Financial Officer
February 27, 2015
51
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders of
Northwest Natural Gas Company:
In our opinion, the consolidated financial statements listed in the accompanying table of contents present fairly, in all material
respects, the financial position of Northwest Natural Gas Company and its subsidiaries at December 31, 2014 and 2013, and the
results of their operations and their cash flows for each of the three years in the period ended December 31, 2014 in conformity
with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement
schedule listed in the accompanying table of contents presents fairly, in all material respects, the information set forth therein
when read in conjunction with the related consolidated financial statements. Also in our opinion, the Company maintained, in all
material respects, effective internal control over financial reporting as of December 31, 2014, 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 and financial statement
schedule, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal
control over financial reporting, included in the accompanying Management's Report on Internal Control over Financial
Reporting. Our responsibility is to express opinions on these financial statements, on the financial statement schedule, and on
the Company's internal control over financial reporting based on our integrated audits. We conducted our audits in accordance
with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan
and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement
and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial
statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements,
assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial
statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal
control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and
operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other
procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our
opinions.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the
reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally
accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that
(i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions
of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit
preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and
expenditures of the company are being made only in accordance with authorizations of management and directors of the
company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or
disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also,
projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate
because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ PricewaterhouseCoopers LLP
Portland, Oregon
February 27, 2015
52
NORTHWEST NATURAL GAS COMPANY
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
In thousands, except per share data
Operating revenues
Operating expenses:
Cost of gas
Operations and maintenance
General taxes
Depreciation and amortization
Total operating expenses
Income from operations
Other income and expense, net
Interest expense, net
Income before income taxes
Income tax expense
Net income
Other comprehensive income:
Change in employee benefit plan liability, net of taxes of $2,857 for 2014,
($1,304) for 2013, and $1,339 for 2012
Amortization of non-qualified employee benefit plan liability, net of taxes of ($438)
for 2014, ($608) for 2013, and ($434) for 2012
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,
2014
2013
2012
$ 754,037
$ 758,518
$ 730,607
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
355,335
129,477
30,598
73,017
588,427
142,180
3,159
43,157
100,335
102,243
102,182
41,643
58,692
41,705
60,538
43,403
58,779
(4,364)
1,998
(2,156)
646
935
665
$
54,974
$
63,471
$
57,288
27,164
27,223
26,974
27,027
26,831
26,907
$
$
2.16
2.16
1.85
$
2.24
2.24
1.83
2.19
2.18
1.79
See Notes to Consolidated Financial Statements
53
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,
2014
2013
$
9,534
$
69,818
57,963
(969)
68,562
243
77,832
20,020
1,000
23,785
34,772
9,471
81,889
61,527
(1,656)
22,635
5,311
60,669
20,646
3,534
45,241
21,181
362,560
330,448
2,992,560
2,918,739
870,967
855,865
2,121,593
2,062,874
129,280
368,908
—
68,238
3,000
11,366
121,998
369,603
1,880
67,851
4,000
12,257
2,702,385
2,640,463
$
3,064,945
$
2,970,911
See Notes to Consolidated Financial Statements
54
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 27,284
and 27,075 at December 31, 2014 and 2013, respectively
Retained earnings
Accumulated other comprehensive loss
Total equity
Total liabilities and equity
See Notes to Consolidated Financial Statements
As of December 31,
2014
2013
$
234,700
$
188,200
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
60,000
96,126
10,856
7,103
28,335
1,891
40,280
432,791
681,700
532,036
303,485
149,354
615
119,058
1,206,514
1,104,548
—
—
375,117
402,280
(10,076)
767,321
364,549
393,681
(6,358)
751,872
$
3,064,945
$
2,970,911
55
NORTHWEST NATURAL GAS COMPANY
CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY
In thousands
Balance at December 31, 2011
Comprehensive income (loss)
Dividends paid on common stock
Tax expense from employee stock option plan
Stock-based compensation
Issuance of common stock
Balance at December 31, 2012
Comprehensive income
Dividends paid on common stock
Tax expense from employee stock option plan
Stock-based compensation
Issuance of common stock
Balance at December 31, 2013
Comprehensive income (loss)
Dividends paid on common stock
Tax expense from stock-based compensation plans
Stock-based compensation
Issuance of common stock
Balance at December 31, 2014
Common
Stock
Retained
Earnings
Accumulated
Other
Comprehensive
Income (Loss)
Total
Equity
$
348,383
$
371,575
$
(7,800) $
712,158
—
—
(149)
1,291
7,046
356,571
—
—
(242)
2,169
6,051
364,549
—
—
(117)
1,646
9,039
58,779
(48,007)
—
—
—
382,347
60,538
(49,204)
—
—
—
393,681
58,692
(50,093)
—
—
—
(1,491)
—
—
—
—
(9,291)
2,933
—
—
—
—
(6,358)
(3,718)
—
—
—
—
57,288
(48,007)
(149)
1,291
7,046
729,627
63,471
(49,204)
(242)
2,169
6,051
751,872
54,974
(50,093)
(117)
1,646
9,039
$
375,117
$
402,280
$
(10,076) $
767,321
See Notes to Consolidated Financial Statements
56
NORTHWEST NATURAL GAS COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
In thousands
Operating activities:
Net income
Adjustments to reconcile net income to cash provided by operations:
Depreciation and amortization
Regulatory amortization of gas reserves
Deferred tax liabilities, net
Non-cash expenses related to qualified defined benefit pension plans
Contributions to qualified defined benefit pension plans
Deferred environmental recoveries, net of (expenditures)
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
Increase in cash and cash equivalents
Cash and cash equivalents, beginning of period
Cash and cash equivalents, end of period
Supplemental disclosure of cash flow information:
Interest paid
Income taxes paid
See Notes to Consolidated Financial Statements
57
Year Ended December 31,
2014
2013
2012
$ 58,692
$ 60,538
$ 58,779
79,193
19,335
24,772
4,984
75,905
11,089
46,483
5,666
73,017
6,340
42,079
5,448
(10,500)
(11,700)
(23,500)
88,849
(16,679)
(12,503)
1,853
(2,580)
(2,350)
14,948
(26,094)
22,170
(17,163)
1,709
(2,020)
(1,024)
(23,114)
(24,857)
6,933
286
7,422
1,150
6,761
3,334
(602)
96
(5,245)
(17,644)
23,216
7,413
215,657
176,390
168,838
(120,092)
(138,924)
(132,029)
(26,798)
(54,077)
(54,085)
175
1,000
1,392
8,638
—
2,231
—
—
1,437
(144,323)
(182,132)
(184,677)
8,986
—
5,964
50,000
6,758
50,000
(80,000)
—
(40,000)
46,500
(2,050)
48,650
(50,093)
(49,204)
(48,007)
3,336
(71,271)
63
9,471
1,580
6,290
548
8,923
$
9,534
$
9,471
$
1,528
18,929
3,090
5,833
8,923
$ 42,602
$ 44,022
$ 43,061
19,445
870
2,979
NORTHWEST NATURAL GAS
COMPANY
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS
1. ORGANIZATION AND PRINCIPLES OF
CONSOLIDATION
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 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.
The accompanying consolidated financial statements
represent the consolidated results of Northwest Natural Gas
Company (NW Natural or the Company) and all companies
that we directly or indirectly control, either through majority
ownership or otherwise. We have two core businesses: our
regulated local gas distribution business, referred to as the
utility segment, which serves residential, commercial, and
industrial customers in Oregon and southwest Washington;
and our gas storage businesses, referred to as the gas
storage segment, which provides storage services for
utilities, gas marketers, electric generators, and large
industrial users from storage facilities located in Oregon and
California. In addition, we have investments and other non-
utility activities 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 Pipeline, LLC (TWP) 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
affect on our prior year’s consolidated results of operations,
financial condition, or cash flows.
58
At December 31, the amounts deferred as regulatory assets
and liabilities were as follows:
In thousands
Current:
Regulatory Assets
2014
2013
Unrealized loss on derivatives(1)
$ 29,889
$
Gas costs
Other(2)
Total current
Non-current:
Unrealized loss on derivatives(1)
Pension balancing(3)
Income taxes
Pension and other postretirement
benefit liabilities(3)
Environmental costs(4)
Gas costs
Other(2)
21,794
16,879
1,891
4,286
16,458
$ 68,562
$ 22,635
$
3,515
$
615
32,541
47,427
25,713
51,814
201,845
125,855
58,859
148,389
5,971
18,750
1,840
15,377
Total non-current
$ 368,908
$ 369,603
In thousands
Current:
Gas costs
Unrealized gain on derivatives(1)
Other(2)
Total current
Non-current:
Gas costs
Unrealized gain on derivatives(1)
Accrued asset removal costs(5)
Other(2)
Regulatory Liabilities
2014
2013
$
5,700
$
7,510
240
13,165
5,290
15,535
$ 19,105
$ 28,335
$
2,507
$
2,172
—
1,880
311,238
296,294
3,460
3,139
$ 317,205
Total non-current
$ 303,485
(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.
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.
(2)
(3) Certain utility pension costs are approved for regulatory
deferral, including amounts recorded to the pension balancing
account, to mitigate the effects of higher and lower pension
expenses. Deferred pension costs include an interest
component when recognized in net periodic benefit costs. See
Note 8.
(4) Environmental costs relate to specific sites approved for
regulatory deferral by the OPUC and WUTC. In Oregon, we
earn a carrying charge on 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. See Note 15.
(5) Estimated costs of removal on certain regulated properties are
collected through rates. See "Accounting Policies—Plant,
Property, and Accrued Asset Removal Costs" below.
59
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,
2014 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. See Note 16 for information regarding the resolution
of the environmental Site Remediation and Recovery
Mechanism (SRRM) in February 2015. In accordance with
accounting guidance and the Company's policy, a $15 million
pre-tax regulatory disallowance will be recognized in the first
quarter of 2015 related to the Order.
New Accounting Standards
Recently Issued Accounting Pronouncements
REVENUE RECOGNITION. On May 28, 2014, the Financial
Accounting Standards Board (FASB) issued Accounting
Standards Update (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 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 are effective beginning
January 1, 2017, and either a full retrospective or simplified
transition adoption method is allowed; early adoption is not
permitted. NW Natural is currently assessing the impact of
this standard on its 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 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.
The gain or loss is recorded in other income and expense,
net in the consolidated statements of comprehensive
income.
Our provision for depreciation of utility property, plant, and
equipment is recorded under the group method on a straight-
line basis with rates computed in accordance with
depreciation studies approved by regulatory authorities. The
weighted-average depreciation rate for utility assets in
service was approximately 2.8% for 2014, 2013, and 2012,
reflecting the approximate weighted-average economic life of
the property. This includes 2014 weighted-average
depreciation rates for the following asset categories: 2.7%
for transmission and distribution plant, 2.2% for gas storage
facilities, 4.7% for general plant, and 2.9% 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
0.3% in 2014, 2013, and 2012.
IMPAIRMENT OF LONG-LIVED ASSETS. We review the
carrying value of long-lived assets whenever events or
changes in circumstances indicate that the carrying amount
of the assets might not be recoverable. Factors that would
necessitate an impairment assessment of long-lived assets
include a significant adverse change in the extent or manner
in which the asset is used, a significant adverse change in
60
legal factors or business climate that could affect the value of
the asset, or a significant decline in the observable market
value or expected future cash flows of the asset, among
others.
If such factors indicate a potential impairment, we assess the
recoverability by determining if the carrying value of the
asset exceeds the sum of the projected future cash flows
over the remaining economic life of the asset. An asset is
determined to be impaired when the carrying value is not
recoverable through undiscounted future cash flows, and in
those cases, we would estimate the fair value of the asset
using appropriate valuation methodologies, which may
include an estimate of discounted cash flows. Any
impairment would be measured as the difference between
the asset’s carrying amount and its estimated fair value.
We have determined there were no events or circumstances
that suggested an impairment of long-lived assets during the
year ended December 31, 2014. In reaching this conclusion,
we reviewed all long-lived assets for circumstances,
including those noted above, that may indicate the carrying
amount of the asset might not be recoverable and
determined no such events have occurred. If our gas storage
facilities experience sustained decreases in future cash
flows due to a prolonged, slow recovery of the gas storage
market, this may lead to events that indicate the carrying
amount of the assets might not be recoverable, requiring an
impairment assessment that could result in a future
impairment.
Cash and Cash Equivalents
For purposes of reporting cash flows, cash and cash
equivalents include cash on hand plus highly liquid
investment accounts with original maturity dates of three
months or less. At December 31, 2014 and 2013,
outstanding checks of approximately $5.5 million and $2.8
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, 2014 and 2013 was $58.0
million and $61.5 million, respectively.
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 primarily from an independent energy marketing
company that optimizes commodity and pipeline capacity
release transactions. Under this agreement, guaranteed
asset management revenue is recognized using a straight-
line, pro-rata methodology over the term of each contract.
Revenues earned above the guaranteed amount are
recognized as they are earned. See Note 4.
Revenue Taxes
Revenue-based taxes are primarily franchise taxes, which
are collected from customers and remitted to taxing
authorities. Revenue taxes are included in operating
revenues in the statement of comprehensive income.
Revenue taxes were $18.8 million, $19.0 million, and $18.4
million for 2014, 2013, and 2012, 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. With
respect to these trade receivables, including accrued
unbilled revenue, we establish an allowance for uncollectible
accounts (allowance) based on the aging of receivables,
collection experience of past due account balances including
payment plans, and historical trends of write-offs as a
percent of revenues. With respect to large individual
customer receivables, a specific allowance is established
and recorded when amounts are identified as unlikely to be
partially or fully recovered. Inactive accounts are written-off
against the allowance after they are 120 days past due or
when deemed 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. Each quarter the allowance for uncollectible accounts
is adjusted, as necessary, based on information currently
available.
Inventories
Utility gas inventories, which consist of natural gas in storage
for the utility, are stated at the lower of average cost or net
realizable value. The regulatory treatment of utility gas
inventories provides for cost recovery in customer rates.
Utility gas inventories 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 and 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 $68.0 million
and $51.4 million at December 31, 2014 and 2013,
respectively. At December 31, 2014 and 2013, our materials
61
and supplies inventories totaled $9.8 million and $9.3 million,
respectively.
Gas Reserves
Our gas reserves are stated at cost, adjusted for regulatory
amortization, with the associated deferred tax benefits
recorded as liabilities on the balance sheet. Transactional
costs to enter into the agreements and payments by NW
Natural to acquire gas reserves are recognized as gas
reserves on the balance sheet. The current portion is
calculated based on expected gas deliveries within the next
fiscal year. We recognize regulatory amortization of this
asset on a volumetric basis calculated using the estimated
gas reserves and the estimated therms extracted and sold
each month. The amortization of gas reserves is recorded to
cost of gas along with gas production revenues and
production costs. See Note 11.
Derivatives
In accordance with accounting for derivatives and hedges,
we measure derivatives at fair value and recognize them as
either assets or liabilities on the balance sheet. Accounting
for derivatives requires that changes in the fair value be
recognized currently in earnings unless specific hedge
accounting criteria are met. Accounting for derivatives and
hedges provides an exception for contracts intended for
normal purchases and normal sales for which physical
delivery is probable. In addition, certain derivative contracts
are approved by regulatory authorities for recovery or refund
through customer rates. Accordingly, the changes in fair
value of these approved contracts are deferred as regulatory
assets or liabilities pursuant to regulatory accounting
principles. Our financial derivatives generally qualify for
deferral under regulatory accounting. The Company’s index-
priced physical derivative contracts also qualify for regulatory
deferral accounting treatment.
Derivative contracts entered into for utility requirements after
the annual PGA rate has been set and 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 years in Oregon beginning
November 1, 2014, 2013, and 2012, 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.
$56.2 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.
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 period that includes the
enactment date 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, 2014 and
2013, regulatory income tax assets of $51.8 million and
62
3. EARNINGS PER SHARE
Basic earnings per share are computed using net income and the weighted average number of common shares outstanding for
each period presented. Diluted earnings per share are computed in the same manner, except it uses the weighted average
number of common shares outstanding plus the effects of the assumed exercise of stock options and the payment of estimated
stock awards from other stock-based compensation plans that are outstanding at the end of each period presented. Diluted
earnings per share are calculated as follows:
In thousands, except per share data
Net income
Average common shares outstanding - basic
Additional shares for stock-based compensation plans (See Note 6)
Average common shares outstanding - diluted
Earnings per share of common stock - basic
Earnings per share of common stock - diluted
Additional information:
2014
2013
2012
$
58,692
$
60,538
$
27,164
59
27,223
26,974
53
27,027
$
$
2.16
2.16
$
$
2.24
2.24
$
$
58,779
26,831
76
26,907
2.19
2.18
Antidilutive shares not included in net income per diluted common share calculation
18
26
1
4. SEGMENT INFORMATION
We primarily operate in two primary reportable business
segments, local gas distribution and gas storage. We also
have other investments and business activities not
specifically related to one of these two reporting segments,
which we aggregate and report as other. We refer to our
local gas distribution business as the utility, and our gas
storage segment and other as non-utility. Our utility
segment also includes NWN Gas Reserves, which is a
wholly-owned subsidiary of Energy Corp and the utility
portion of Mist. Our gas storage segment includes NWN
Gas Storage, which is a wholly-owned subsidiary of NWN
Energy, Gill Ranch, which is a wholly-owned subsidiary of
NWN Gas Storage, the non-utility portion of Mist, and all
third-party asset management services. Other includes
NNG Financial and NWN Energy's equity investment in
TWH, which is pursuing development of a cross-Cascades
transmission pipeline project. See Other, below.
Local Gas Distribution
Our local gas distribution segment is a regulated utility
principally engaged in the purchase, sale, and delivery of
natural gas and related services to customers in Oregon
and southwest Washington. As a regulated utility, we are
responsible for building and maintaining a safe and reliable
pipeline distribution system, purchasing sufficient gas
supplies from producers and marketers, contracting for firm
and interruptible transportation of gas over interstate
pipelines to bring gas from the supply basins into our
service territory, and re-selling the gas to customers subject
to rates, terms, and conditions approved by the OPUC or
WUTC. Gas distribution also includes taking customer-
owned gas and transporting it from interstate pipeline
connections, or city gates, to the customers’ end-use
facilities for a fee, which is approved by the OPUC or
WUTC. Approximately 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
services, gains or losses from an incentive gas cost sharing
mechanism, and other service fees.
63
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. For the years
ended December 31, 2014, 2013, and 2012, this business
segment derived a majority of its revenues from firm and
interruptible gas storage contracts and from asset
management services.
Mist Gas Storage Facility
Earnings from non-utility assets at our Mist facility in
Oregon are primarily related to firm storage capacity
revenues. Earnings for the Mist facility also includes
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
Trail West Holdings (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 operating and non-operating revenues and expenses
of the parent company that cannot be allocated to utility
operations.
NNG Financial holds certain non-utility financial
investments, but its assets primarily consist of an active,
wholly-owned subsidiary which owns a 10% interest in an
18-mile interstate natural gas pipeline. NNG Financial’s
total assets were $0.8 million and $1.2 million at December
31, 2014 and 2013, respectively.
Segment Information Summary
Inter-segment transactions are insignificant. The following table presents summary financial information concerning the
reportable segments:
In thousands
2014
Utility
Gas Storage
Other
Total
Operating revenues
$
731,578
$
22,235
$
224
$
Depreciation and amortization
Income from operations
Net income
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
$
16,447
2,970,911
—
11
49
—
—
100
209
337
758,518
75,905
142,746
60,538
138,924
730,607
73,017
142,180
58,779
132,029
15,897
2,813,120
Operating revenues
$
699,862
$
30,520
$
225
$
Depreciation and amortization
Income from operations
Net income
Capital expenditures
Total assets at December 31, 2013
2012
69,420
128,066
54,920
137,466
2,644,367
6,485
14,669
5,569
1,458
310,097
Depreciation and amortization
Income from operations
Net income
Capital expenditures
Total assets at December 31, 2012
66,545
128,854
54,049
130,151
2,505,655
6,472
13,226
4,521
1,541
291,568
64
Utility Margin
Utility margin is a financial measure consisting of utility operating revenues, which are reduced by revenue taxes and the
associated cost of gas. The cost of gas purchased for utility customers is generally a pass-through cost in the amount of
revenues billed to regulated utility customers. By subtracting costs of gas from utility operating revenues, utility margin provides
a key metric used by our chief operating decision maker in assessing the performance of the utility segment. The gas storage
and other segments emphasize growth in operating revenues and net income as opposed to margin because these segments
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
Less: Utility cost of gas
Utility margin
5. COMMON STOCK
Common Stock
As of December 31, 2014 and 2013, we had 100 million
shares of common stock authorized. As of December 31,
2014, we had reserved 97,921 shares for issuance of
common stock under the Employee Stock Purchase Plan
(ESPP) and 394,903 shares under our Dividend
Reinvestment and Direct Stock Purchase Plan (DRPP). 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 416,088 options outstanding at
December 31, 2014, 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 2015 to repurchase up to
an aggregate of 2.8 million shares, but not to exceed $100
million. No shares of common stock were repurchased
pursuant to this program during the year ended December
31, 2014. 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.
2014
2013
2012
$
$
731,578
$
727,182
$
365,490
373,298
366,088
$
353,884
$
699,862
355,335
344,527
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, 2011
Sales to employees under ESPP
Stock-based compensation
Sales to shareholders under DRPP
Balance, December 31, 2012
Sales to employees under ESPP
Stock-based compensation
Sales to shareholders under DRPP
Balance, December 31, 2013
Sales to employees under ESPP
Stock-based compensation
Sales to shareholders under DRPP
Balance, December 31, 2014
Shares
26,756
18
47
96
26,917
16
42
100
27,075
24
83
102
27,284
65
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. A
variety of equity programs may be granted under the
LTIP. The Restated SOP was terminated in 2012 with
respect to new grants; however, options granted before the
Restated SOP was terminated will remain outstanding until
the earlier of their expiration, forfeiture, or exercise. Any new
grants of stock options would be made under the LTIP. No
stock options were granted under the LTIP during the year
ended December 31, 2014.
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, 2014. 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, 2014, there were 225,669 shares
available for issuance under any type of award and 250,000
shares available for option grants. This assumes that
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, 2014 or 2013. 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 millions
Estimated award:
2012-2014 grant(2)
Actual award:
2011-2013 grant
2010-2012 grant
Shares(1)
Expense
During Award
Year(3)
Total
Expense
for Award
8,408
$
0.6
$
1.8
9,819
9,924
0.4
0.5
1.0
1.2
(1)
In addition to common stock shares, a participant also
receives a dividend equivalent cash payment equal to the
number of shares of common stock received on the award
payout multiplied by the aggregate cash dividends paid per
share during the performance period.
(2) This represents the estimated number of shares to be
awarded as of December 31, 2014 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 2015.
(3) Amount represents the expense recognized in the third year of
the vesting period noted above.
The aggregate number of performance shares granted and outstanding at the target and maximum levels were as follows:
Dollars in thousands
Performance Period
Performance Share Awards Outstanding
Target
Maximum
2014
Expense
Cumulative Expense
December 31, 2014
2012-14
2013-15
2014-16
Total
35,340
37,300
43,625
116,265
70,680
$
583
$
74,600
87,250
232,530
$
442
618
1,643
1,821
928
618
For the 2012-2014 and 2013-2015 performance periods,
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 award also included
weighting for EPS and Return on Invested Capital (ROIC)
factors. Compensation expense is recognized in accordance
with the accounting standard for stock-based compensation
and calculated based on performance levels achieved and
an estimated fair value using the Monte-Carlo method. The
weighted-average grant date fair value of unvested shares
at December 31, 2014 and 2013 was $42.06 and $43.39 per
share, respectively. The weighted-average grant date fair
value of shares vested during the year was $43.67 per
share and for shares granted during the year was $42.43
per share. As of December 31, 2014, there was $1.7 million
of unrecognized compensation expense related to the
unvested portion of performance awards expected to be
recognized through 2016.
66
Restricted Stock Units
In 2012, the Company began granting RSUs under the LTIP
instead of stock options under the Restated SOP. The fair
value of an RSU is equal to the closing market price of the
Company's common stock on the grant date. During 2014,
total RSU expense was $0.9 million compared to $0.6
million in 2013. As of December 31, 2014, there was $2.2
million of unrecognized compensation cost from grants of
RSUs, which is expected to be recognized over a period
extending through 2019. Generally, RSUs awarded include
a performance-based threshold and a vesting period of four
years from the grant date. An RSU obligates the Company
upon vesting to issue the RSU holder one share of common
stock plus a cash payment equal to the total amount of
dividends paid per share between the grant date and
vesting date of that portion of the RSU.
Information regarding the RSU activity is summarized as
follows:
Number
of
RSUs
Weighted -
Average
Price Per
RSU
Nonvested, December 31, 2011
— $
Granted
Vested
Forfeited
25,224
—
(360)
Nonvested, December 31, 2012
24,864
$
Granted
Vested
Forfeited
Nonvested, December 31, 2013
Granted
Vested
Forfeited
Nonvested, December 31, 2014
25,748
(5,455)
(590)
44,567
38,765
(12,060)
(478)
70,794
—
47.58
—
48.00
47.57
45.38
48.01
46.58
46.27
42.19
46.52
45.47
44.00
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.
At December 31, 2014, a total of 416,088 shares of
common stock remained reserved for issuance under the
Restated SOP. As the plan is closed, there are no additional
shares available for grant. Options under the Restated SOP
were granted 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
six 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, 2011
579,225
$
42.09
$
Exercised
Forfeited
Balance outstanding,
December 31, 2012
Exercised
Forfeited
Balance outstanding,
December 31, 2013
Exercised
Forfeited
Balance outstanding,
December 31, 2014
Exercisable,
December 31, 2014
(46,825)
(2,475)
529,925
(33,800)
(3,975)
492,150
(69,662)
(6,400)
40.62
43.78
42.22
32.16
43.72
42.89
39.82
43.59
416,088
43.40
388,965
43.23
3.4
0.4
n/a
1.3
0.3
n/a
0.6
0.5
n/a
2.7
2.6
During 2014, cash of $2.8 million was received for option
shares exercised and $0.1 million related tax benefit was
realized. During 2014, 2013, and 2012, the total fair value of
options that vested was $0.4 million, $0.5 million and $0.6
million, respectively. The weighted average remaining life of
options exercisable and outstanding at December 31, 2014
was 4.2 years and 4.3 years, respectively.
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 $21,239 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
2014
2013
2012
Operations and maintenance
expense, for stock-based
compensation
$ 2,309 $ 1,876 $ 1,668
Income tax benefit
(861)
(765)
(707)
Net stock-based compensation
effect on net income
$ 1,448 $ 1,111 $
961
Amounts capitalized for stock-based
compensation
$
597 $
331 $
294
67
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. At December 31, 2014 and 2013, the amounts of
commercial paper debt outstanding were $234.7 million and
$188.2 million, respectively, and the average interest rate at
December 31, 2014 and 2013 was 0.4% and 0.3%,
respectively. 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, 2014, our
commercial paper had a maximum maturity of 209 days and
an average maturity of 98 days.
On December 20, 2012, NW Natural entered into a five-year
$300 million credit agreement, with a feature that allows the
Company to request increases in the total commitment
amount up to a maximum amount of $450 million. The credit
agreement also permitted NW Natural to extend
commitments for two additional one-year periods, subject to
lender approval. The Company exercised the first of these
extensions in December 2013, and the second in December
2014 with a final maturity date of December 20, 2019. Also
in December 2014, NW Natural amended the credit
agreement to reduce the permitted letter of credit from $200
million to $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, 2014 and
2013.
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,
2014 and 2013.
Long-Term Debt
The issuance of first mortgage bonds (FMBs), which
includes our medium-term notes, under the Mortgage and
Deed of Trust (Mortgage) is limited by eligible property,
adjusted net earnings and other provisions of the Mortgage.
The Mortgage constitutes a first mortgage lien on
substantially all of our utility property. In addition, our Gill
Ranch subsidiary senior secured debt is secured by all of
the membership interests in Gill Ranch as well as Gill
Ranch’s debt service reserve account, which is recorded as
restricted cash on the balance sheet.
Maturities and Outstanding Long-Term Debt
Retirement of long-term debt for each of the 12-month
periods through December 31, 2019 and thereafter are as
follows:
In thousands
Year
2015
2016
2017
2018
2019
Thereafter
$
40,000
45,000
40,000
22,000
30,000
484,700
The following table presents our debt outstanding as of
December 31:
In thousands
First Mortgage Bonds
8.26 % Series B due 2014
3.95 % Series B due 2014
4.70 % Series B due 2015
5.15 % Series B due 2016
7.00 % Series B due 2017
6.60 % Series B due 2018
8.31 % Series B due 2019
7.63 % Series B due 2019
5.37 % Series B due 2020
9.05 % Series A due 2021
3.176 % Series B due 2021
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
$
2014
2013
— $
—
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
10,000
50,000
40,000
25,000
40,000
22,000
10,000
20,000
75,000
10,000
50,000
50,000
40,000
20,000
10,000
20,000
20,000
19,700
10,000
20,000
10,000
30,000
40,000
10,000
50,000
701,700
Subsidiary Senior Secured Debt
Gill Ranch debt due 2016
Less: Current maturities
Total long-term debt
20,000
661,700
40,000
$ 621,700
40,000
741,700
60,000
$ 681,700
68
First Mortgage Bonds
NW Natural issued $50 million of FMBs on August 19, 2013
with a coupon rate of 3.542% and a 10-year maturity.
with a coupon rate of 8.26%. In June 2014, under the
amended agreement Gill Ranch retired $20 million of
variable interest rate debt with a coupon rate of 7.00%.
Subsidiary Senior Secured Debt
Gill Ranch has $20 million of fixed-rate senior secured debt
outstanding, which was issued in 2011 with a maturity date
of November 30, 2016 and an interest rate of 7.75%.
Under the debt agreements, Gill Ranch is subject to certain
covenants and restrictions including, but not limited to, a
financial covenant that requires Gill Ranch to maintain
minimum adjusted earnings before interest, taxes,
depreciation, and amortization (EBITDA) at various levels
over the term of the debt. As part of an amended
agreement, the EBITDA covenant requirement is suspended
through March 31, 2015 with lower EBITDA hurdles
thereafter. The debt service reserve requirement was fixed
at $3 million.
Retirements of Long-Term Debt
The utility redeemed $50 million of FMBs with a coupon rate
of 3.95% in July 2014 and $10 million in September 2014
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,
2014
2013
Carrying amount
$
661,700
$
Estimated fair value
756,808
741,700
806,359
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
Net actuarial (gain) loss
Benefits paid
Obligation at December 31
Reconciliation of change in plan assets:
Fair value of plan assets at January 1
Actual return on plan assets
Employer contributions
Benefits paid
Fair value of plan assets at December 31
Funded status at December 31
Postretirement Benefit Plans
Pension Benefits
Other Benefits
2014
2013
2014
2013
$
391,089
$
435,889
$
28,754
$
33,119
7,213
18,198
90,710
(19,932)
8,698
16,400
(51,043)
(18,855)
483
1,252
3,454
(1,871)
656
1,157
(4,283)
(1,895)
$
487,278
$
391,089
$
32,072
$
28,754
$
267,062
$
249,603
$
19,957
12,077
22,872
13,442
(19,932)
(18,855)
— $
—
1,871
(1,871)
279,164
$
267,062
$
— $
—
—
1,895
(1,895)
—
(208,114) $
(124,027) $
(32,072) $
(28,754)
$
$
Our qualified defined benefit pension plan has an aggregate benefit obligation of $451.2 million and $362.4 million at December
31, 2014 and 2013, respectively, and fair values of plan assets of $279.2 million and $267.1 million, respectively.
69
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
2014
2013
2012
2014
2013
2012
2014
2013
2012
Net actuarial loss (gain)
$ 83,027
$ (51,892) $ 26,504
$ 3,454
$ (4,283) $
3,182
$
7,221
$
(3,302) $
3,511
Amortization of:
Transition obligation
Prior service cost
Actuarial loss
—
(230)
—
(230)
—
(230)
(9,823)
(16,744)
(14,482)
—
(197)
(221)
—
(197)
(733)
(411)
(197)
(435)
—
7
—
7
—
35
(1,091)
(1,550)
(1,150)
Total
$ 72,974
$ (68,866) $ 11,792
$ 3,036
$ (5,213) $
2,139
$
6,137
$
(4,845) $
2,396
The following table presents amounts recognized in regulatory assets and accumulated other comprehensive loss (AOCL) at
December 31:
In thousands
Prior service cost
Net actuarial loss
Total
Regulatory Assets
AOCL
Pension Benefits
Other Postretirement Benefits
Pension Benefits
2014
2013
2014
2013
2014
2013
$
$
637
$
867
$
488
$
685
$
2
$
(5)
192,846
119,638
7,898
4,665
16,604
193,483
$
120,505
$
8,386
$
5,350
$
16,606
$
10,475
10,470
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
Year Ended December 31,
2014
2013
$
$
(6,358) $
(7,221)
(7)
1,091
(6,137)
2,419
(3,718)
(10,076) $
(9,291)
3,302
(7)
1,550
4,845
(1,912)
2,933
(6,358)
In 2015, an estimated $17.0 million will be amortized from
regulatory assets to net periodic benefit costs, consisting of
$16.6 million of actuarial losses, and $0.4 million of prior
service costs. A total of $2.2 million will be amortized from
AOCL to earnings related to actuarial losses.
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 the Company's plans to reflect the timing and
amount of expected future benefit payments for these plans.
Our assumed expected long-term rate of return on plan
assets 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
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
70
needed, or when significant cash flows occur, in order to
maintain the allocation of assets within the stated target
ranges. Our expected long-term rate of return is based upon
historical index returns by asset class, adjusted by a factor
based on our historical return experience, diversified asset
allocation and active portfolio management by professional
investment managers. The retirement trust fund is not
currently invested in NW Natural securities.
The following table presents the pension plan asset target
allocation at December 31, 2014:
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 $36.1 million and $28.7 million at
December 31, 2014 and 2013, 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 portion of our
obligations with company- and trust-owned life insurance
and other assets.
Our other postretirement benefit plans are unfunded plans
but are subject to regulatory deferral. The actuarial gains
and losses, prior service costs, and transition assets or
obligations for these plans are recognized as a regulatory
asset.
Net periodic benefit costs consist of service costs, interest
costs, 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 transition obligations
Amortization of prior service costs
Amortization of net actuarial loss
Net periodic benefit cost
Amount allocated to construction
Amount deferred to regulatory balancing account(1)
Pension Benefits
Other Postretirement Benefits
2014
2013
2012
2014
2013
2012
$
7,213
$
8,698
$
8,047
$
483
$
656
$
18,198
(19,496)
—
223
10,914
17,052
(4,625)
(4,578)
16,400
17,295
1,252
1,157
(18,721)
(19,082)
—
223
18,294
24,894
(6,712)
(9,115)
—
195
15,631
22,086
(5,820)
(7,876)
—
—
197
221
2,153
(702)
—
—
—
197
734
2,744
(856)
—
592
1,267
—
411
197
435
2,902
(882)
—
Net amount charged to expense
$
7,849
$
9,067
$
8,390
$
1,451
$
1,888
$
2,020
(1) 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
the interest being deferred until amounts are collected in rates. See Note 2.
71
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
2014
2013
2012
2014
2013
2012
Assumptions for net periodic benefit cost:
Weighted-average discount rate
4.71%
3.84%
4.51%
4.45%
3.56%
4.33%
Rate of increase in compensation
3.25-5.0%
3.25-5.0%
3.25-5.0%
Expected long-term rate of return
7.50%
7.50%
8.00%
n/a
n/a
n/a
n/a
n/a
n/a
Assumptions for year-end funded status:
Weighted-average discount rate
3.85%
4.73%
3.85%
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
The assumed annual increase in health care cost trend
rates used in measuring other postretirement benefits as of
December 31, 2014 was 8.00% for pre-65 and 11.75% for
post-65 populations. These trend rates apply to both
medical and prescription drugs. Medical costs and
prescription drugs are assumed to decrease gradually each
year to a rate of 4.75% by 2022.
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
$
62
$
(55)
Estimated Future Benefit Payments:
Employer Contributions:
2013
2014
2015 (estimated)
Benefit Payments:
2012
2013
2014
2015
2016
2017
2018
2019
$
13,907
$
12,077
16,567
18,195
18,855
19,932
20,315
20,993
21,784
22,799
24,162
1,895
1,871
1,848
1,971
1,895
1,871
1,848
1,918
1,955
2,007
2,075
2020-2024
137,839
10,412
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
1,260
(965)
The Company adopted a new set of mortality tables for its
plans beginning with 2014. The tables were released in
October 2014 by the Society of Actuaries' Retirement Plans
Experience Committee and project a mortality improvement,
thereby increasing benefit plan liabilities.
72
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
(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 $172.0 million at December 31, 2014.
Including the impacts of MAP-21 and HATFA, we made
cash contributions totaling $10.5 million to our qualified
defined benefit pension plan for 2014. During 2015, we
expect to make contributions of approximately $15 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 $0.4 million for 2014 and as of
December 31, 2014 the liability balance was $8.1 million.
For 2013 and 2012, contributions to the plan were $0.5
million and $0.4 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 $3.4 million for 2014
and $2.2 million for both 2013 and 2012. The Retirement K
Savings Plan includes an Employee Stock Ownership Plan.
Deferred Compensation Plans
The supplemental deferred compensation plans for eligible
officers and senior managers are non-qualified plans. These
plans are designed to enhance the retirement savings of
employees and to assist them in strengthening their
financial security by providing an incentive to save and
invest regularly.
Fair Value
Following is a description of the valuation methodologies
used for assets measured at fair value. In cases where the
pension plan is invested through a collective trust fund or
mutual fund, our custodian uses the fund's market value.
The custodian also provides the market values for
investments directly owned.
U.S. LARGE CAP EQUITY and U.S. SMALL/MID CAP
EQUITY. These are level 1 and 2 assets. The level 1 assets
consist of directly held stocks and mutual funds with a
readily determinable fair value, including a published net
asset value (NAV). The level 2 assets consist of mutual
funds where NAV is not published but the investment can be
readily disposed of at NAV or market value. Directly held
stocks are valued at the closing price reported in the active
market on which the individual security is traded, and
mutual funds are valued at NAV. This asset class includes
investments primarily in U.S. common stocks.
NON-U.S. EQUITY. These are level 1 and 2 assets. The level
1 assets consist of directly held stocks, and the level 2
assets consist of an open-end mutual fund and a
commingled trust where the NAV/unit price is not published
but the investment can be readily disposed of at the NAV/
unit price. Directly held stocks are valued at the closing
price reported in the active market on which the individual
security is traded, and the mutual fund is valued at NAV,
while the commingled trust is valued at the unit price of the
trust. This asset class includes investments primarily in
foreign equity common stocks.
EMERGING MARKETS EQUITY. 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 NAV. This asset
class includes investments primarily in investment grade
debt and fixed income securities.
LONG GOVERNMENT/CREDIT. These are level 1 and 2
assets. The level 1 assets consist of a fixed-income mutual
fund with readily determinable fair value, including a
published NAV. The level 2 assets consist of directly held
fixed-income securities whose values are determined by
closing prices if available and by matrix prices for illiquid
securities. This asset class includes long duration fixed
income investments primarily in U.S. treasuries, U.S.
government agencies, municipal securities, mortgage-
backed securities, asset-backed securities, as well as U.S.
and international investment-grade corporate bonds.
73
HIGH YIELD BONDS. These are level 2 assets consisting of a
limited partnership where valuation is not published but the
investment can be readily disposed of at market value. This
asset class includes investments primarily in high yield
bonds.
REAL RETURN STRATEGY. These are level 1 assets
representing a mutual fund with a readily determinable fair
value, including a published NAV. This asset class includes
an investment in a broad range of assets primarily including
fixed income, high-yield bonds, and emerging market debt.
EMERGING MARKET DEBT. These are level 1 assets
consisting of a mutual fund with a readily determinable fair
value, including a published NAV. This asset class includes
investments primarily in emerging market debt.
REAL ESTATE FUNDS. These are level 1 assets consisting of
a mutual fund with a readily determinable fair value,
including a published NAV. This asset class includes
investments primarily in real estate investment trust (REIT)
equity securities globally.
ABSOLUTE RETURN STRATEGY. These are level 2 assets
consisting of a hedge fund of funds where valuations are 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.
CASH AND CASH EQUIVALENTS. These are level 2 assets
representing mutual funds without published NAV's but the
investment can be readily disposed of at NAV. The mutual
funds are valued at the NAV of the shares held by the plan
at the valuation date. This asset class primarily includes
money market mutual funds.
The preceding valuation methods may produce a fair value
calculation that is not indicative of net realizable value or
reflective of future fair values. Although we believe these
valuation methods are appropriate and consistent with other
market participants, the use of different methodologies or
assumptions to determine the fair value of certain financial
instruments could result in a different fair value
measurement at the reporting date.
Investment securities are exposed to various financial risks
including interest rate, market, and credit risks. Due to the
level of risk associated with certain investment securities, it
is reasonably possible that changes in the values of our
investment securities will occur in the near term and such
changes could materially affect our investment account
balances and the amounts reported as plan assets available
for benefit payments.
74
The following table presents the fair value of plan assets, including outstanding receivables and liabilities, of the retirement trust
fund:
In thousands
Investments
U.S. large cap equity
U.S. small/mid cap equity
Non-U.S. equity
Emerging markets equity
Fixed income
Long government/credit
High yield bonds
Emerging market debt
Real estate funds
Absolute return strategy
Real return strategy
Cash and cash equivalents
Total investments
Investments
U.S. large cap equity
U.S. small/mid cap equity
Non-U.S. equity
Emerging markets equity
Fixed income
Long government/credit
High yield bonds
Emerging market debt
Real estate funds
Absolute return strategy
Real return strategy
Cash and cash equivalents
Total investments
Receivables
Accrued interest and dividend income
Due from broker for securities sold
Total receivables
Liabilities
Due to broker for securities purchased
Total investment in retirement trust
December 31, 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, 2013
Level 1
Level 2
Level 3
Total
$
39,124
$
30,465
16,782
7,405
—
33,152
—
9,987
16,559
—
13,031
—
$
79
55
17,202
—
367
32,763
12,890
—
—
35,339
—
1,418
— $
—
—
—
—
—
—
—
—
—
—
—
39,203
30,520
33,984
7,405
367
65,915
12,890
9,987
16,559
35,339
13,031
1,418
$
166,505
$
100,113
$
— $
266,618
December 31,
2014
2013
$
510
$
1,694
$
2,204
$
468
1,154
1,622
$
$
179
279,164
$
$
1,178
267,062
75
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
2014
2013
2012
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
Regulatory asset
impairment
Other, net
$ 35,117
$ 35,785
$ 35,764
4,666
4,674
4,773
(201)
(271)
(350)
2,357
2,357
1,718
(689)
(864)
(800)
—
393
—
24
2,700
(402)
Total provision for income
taxes
$ 41,643
$ 41,705
$ 43,403
Effective tax rate
41.5%
40.8%
42.5%
The increase in the effective income tax rate for 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 decrease in the effective income tax rate
for 2013 compared to 2012 was primarily the result of an
after-tax charge of $2.7 million in 2012 related to the
OPUC's rate case order that the Company could not
recover from customers the increase in deferred tax
liabilities resulting from the 2009 Oregon income tax rate
increase.
The provision (benefit) for current and deferred income
taxes consists of the following at December 31:
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
2014
2013
2012
$ 24,317
$
(73) $
1,909
19,518
38,073
39,163
(201)
(271)
(350)
43,634
37,729
40,722
(9,470)
7,479
(1,991)
—
3,976
3,976
(117)
2,798
2,681
Total provision for income
taxes
$ 41,643
$ 41,705
$ 43,403
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
2014
2013
$ 386,732
$ 362,160
51,805
55,776
48,683
56,183
71,971
47,516
$ 542,996
$ 537,830
$
6,537
$
4,112
16,788
12,657
35,982
1,939
45,351
51,402
In thousands
Current
Federal
State
Deferred
Federal
State
2014
2013
2012
Deferred income tax liabilities, net
507,014
486,428
$ 14,823
$
(62) $
1,693
24
14,847
(11)
(73)
99
1,792
18,635
35,109
8,161
6,669
26,796
41,778
31,187
10,424
41,611
Deferred investment tax credits
166
367
Deferred income taxes and investment
tax credits
$ 507,180
$ 486,795
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, 2014.
Total provision for
income taxes
$ 41,643
$ 41,705
$ 43,403
Total income taxes paid
$ 19,445
$
870
$
2,979
76
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
2014
2013
Utility plant in service
$2,661,097
$2,585,901
Utility construction work in progress
24,886
28,855
Less: Accumulated depreciation
836,510
827,380
Utility plant, net
Non-utility plant in service
Non-utility construction work in
progress
Less: Accumulated depreciation
1,849,473
1,787,376
297,295
297,330
9,282
34,457
6,653
28,485
Non-utility plant, net
272,120
275,498
Total property, plant, and equipment
$2,121,593
$2,062,874
Capital expenditures in accrued
liabilities
$
8,757
$
10,691
The weighted average depreciation rate was 2.8% for utility
assets and 2.2% for non-utility assets in 2014, 2013, and
2012.
Accumulated depreciation does not include the accumulated
provision for asset removal costs of $311.2 million and
$296.3 million at December 31, 2014 and 2013,
respectively. These accrued asset removal costs are
reflected on the balance sheets as regulatory liabilities. See
Note 2. In addition, we acquired equipment under capital
leases of $1.3 million and $0.2 million in 2014 and 2013,
respectively.
The Company estimates it has net operating loss (NOL)
carryforwards of $28.8 million for federal taxes and $49.4
million for Oregon taxes at December 31, 2014. We
anticipate fully utilizing these NOL carryforward balances
before they begin to expire in 2033 for federal and 2027 for
Oregon. Alternative minimum tax (AMT) credits of $16.8
million, general business credits of $0.2 million, and
charitable contribution carryforwards of $4.6 million are also
available. The AMT credits do not expire, and we anticipate
fully utilizing the general business credits and charitable
contribution carryforwards before they begin to expire in
2033 and 2015, 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 will be decreased by
approximately $0.9 million if and when the deferred
depletion from 2013 and 2014 is realized.
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, 2014,
2013, or 2012.
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 2013 and 2014 tax years are currently in
examination under the IRS Compliance Assurance Process
(CAP). The Company’s 2015 tax year 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, 2014, tax year 2012 remains open for federal
examination.
In 2012 the Company settled the Oregon Department of
Revenue examination of tax years 2006 through 2009. This
settlement resulted in an additional $0.2 million state tax
expense, including interest, but was offset by a
corresponding refund claim with the state of California. As of
December 31, 2014, tax years 2011 through 2014 are open
for Oregon examination.
77
11. GAS RESERVES
Our gas reserves are stated at cost, net of regulatory
amortization, with the associated deferred tax benefits
recorded as liabilities on the balance sheet.
We entered into agreements with Encana Oil & Gas (USA)
Inc. (Encana) in 2011 to develop and produce physical gas
reserves and provide long-term gas price protection for
utility customers. Encana began drilling in 2011 under these
agreements. Gas produced from working interests in these
gas fields is sold at prevailing market prices, with revenues
from such sales, less associated production costs, credited
to the utility's cost of gas. The cost of gas, including a
carrying cost for the rate base investment, is part of NW
Natural's annual Oregon PGA filing, which allows us to
recover our 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.
On March 28, 2014, we amended the original gas reserve
agreement in order to facilitate Encana's proposed sale of
its interest in the Jonah field to Jonah Energy LLC. Under
the amendment, we ended the drilling program with
Encana, but increased our assigned ownership interests in
certain sections of the Jonah field and retained the right to
invest in additional wells with the new owner.
Since the amendment, we have been notified by Jonah
Energy LLC of investment opportunities in the sections of
the Jonah field where we have ownership interests. The
amended agreement allows us to invest in additional wells
on a well-by-well basis with drilling costs and resulting gas
volumes shared at our amended proportionate ownership
interest for each well in which we invest. We elected to
participate in some of the additional wells drilled in 2014,
and we may have the opportunity to participate in more
wells in the future. We filed an application requesting
regulatory deferral in Oregon for these additional
investments. We have also signed a memorandum of
understanding with all parties agreeing that individual wells
drilled in any year will be reviewed for prudence annually
going forward. Subsequently, we filed in 2015 seeking cost
recovery for the additional wells drilled in 2014. A decision
on the prudence of the wells drilled in 2014 will occur when
the parties and Commission review our filing seeking cost
recovery. Our cumulative investment of approximately $10
million in these additional wells has been accounted for as
a utility investment. If regulatory approval is not received,
our investment in these additional wells would follow oil and
gas accounting.
Gas reserves acted to hedge the cost of gas
for approximately 10% and 6% of our utility's gas supplies
for the years ended December 31, 2014 and 2013,
respectively.
The following table outlines our net gas reserves
investment at December 31:
In thousands
2014
2013
Gas reserves, current
$
20,020
$
20,646
Gas reserves, non-current
167,190
140,573
Less: Accumulated amortization
37,910
18,575
Total gas reserves(1)
149,300
142,644
18,551
42,117
Less: Deferred taxes on gas reserves
Net investment in gas reserves(1)
$ 100,527
(1) Total gas reserves includes our investment in additional wells,
$ 130,749
subject to regulatory deferral approvals, with total gas
reserves of $9.2 million and net investment of $8.4 million at
December 31, 2014 and no net investment or total gas
reserves from additional wells in 2013.
Variable Interest Entity (VIE) Analysis
We concluded that the arrangement with Encana qualifies
as a variable interest (VI) as our interest represents a minor
portion of total extraction activities. Our investment is
included on our balance sheet under gas reserves with our
maximum loss exposure limited to our current investment
balance.
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
2014
2013
Investments in life insurance policies
$ 52,366
$ 51,791
Investments in gas pipeline
Other
13,962
14,048
1,910
2,012
Total other investments
$ 68,238
$ 67,851
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
Trail West Pipeline, LLC (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.
78
VIE Analysis
TWH is a development stage VIE, with our investment in
TWP reported under equity method accounting. We have
determined we are not the primary beneficiary of TWH’s
activities, in accordance with the authoritative guidance
related to consolidations, as we only have a 50% share of
the entity and there are no stipulations that allow us a
disproportionate influence over it. Our investment in TWH
and TWP are included in other investments on our balance
sheet. Should this investment not be developed, 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, 2014 and 2013.
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 that a
loss in value is other than temporary, a charge is recognized
for the difference between the investment’s carrying value
and its estimated fair value. Fair value is based on quoted
market prices when available or on the present value of
expected future cash flows. Differing assumptions could
affect the timing and amount of a charge recorded in any
period.
In 2011, 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,
2014 as the fair value of expected cash flows from planned
development exceeded our remaining equity investment of
$13.4 million at December 31, 2014. 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 $13.3 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.
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,
2014
2013
287,475
389,225
420,980
552,500
$ 12,230
$ 15,002
PGA
As of November 1, 2014, we reached our target hedge
percentage for the 2014-15 gas year, and these hedge
prices were included in the PGA filing and qualified for
regulatory deferral.
79
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
Benefit (expense) to cost of gas
Less:
Amounts deferred to regulatory accounts on balance sheet
Total gain (loss) in pre-tax earnings
$
$
December 31, 2014
December 31, 2013
Natural gas
commodity
Foreign
exchange
Natural gas
commodity
Foreign
exchange
(32,784) $
(382) $
4,985
$
(300)
32,782
(2) $
382
— $
(4,964)
21
$
300
—
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.
We realized net gains of $10.5 million and net losses of $11.0 million for the years ended December 31, 2014 and 2013,
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, 2014 or 2013. We attempt to minimize the
potential exposure to collateral calls by counterparties
to manage our liquidity risk. Counterparties generally allow a
certain credit limit threshold before requiring us to post
collateral against loss positions. Given our counterparty
credit limits and portfolio diversification, we have not been
subject to collateral calls in 2014 or 2013. Our collateral call
exposure is set forth under credit support agreements,
which generally contain credit limits. We could also be
subject to collateral call exposure where we have agreed to
provide adequate assurance, which is not specific as to the
amount of credit limit allowed, but could potentially require
additional collateral in the event of a material adverse
change.
Based upon current financial swap and option contracts
outstanding, which reflect unrealized losses of $30.6 million
at December 31, 2014, 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
$2,504
$ 27,150
—
—
—
—
19,646
In thousands
With
Adequate
Assurance
Calls
Without
Adequate
Assurance
Calls
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
80
circumstances. Such circumstances may include a
defaulting party, a credit change due to a merger affecting
either party, or any other termination event.
If netted by counterparty, our derivative position would result
in an asset of $0.2 million and a liability of $33.4 million as
of December 31, 2014. As of December 31, 2013, our
derivative position would have resulted in an asset of $7.2
million and a liability of $2.5 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
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, 2014 extends to March 2017.
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, 2014. As of December 31, 2014 and 2013,
the net fair value was a liability of $33.2 million and an asset
of $4.7 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, 2014 and 2013. See Note 2.
14. COMMITMENTS AND CONTINGENCIES
Leases
We lease land, buildings, and equipment under agreements
that expire in various years, including a 99-year land lease
that extends through 2108. Rental expense under operating
leases was $5.9 million, $5.1 million, and $4.8 million for the
years ended December 31, 2014, 2013, and 2012,
respectively. The following table reflects the future minimum
lease payments due under non-cancelable leases at
December 31, 2014. These commitments relate principally
to the lease of our office headquarters, underground gas
storage facilities, and computer equipment.
Gas Purchase and Pipeline Capacity Purchase and
Release Commitments
We have signed agreements providing for the reservation of
firm pipeline capacity under which we are required to make
fixed monthly payments for contracted capacity. The pricing
component of the monthly payment is established, subject
to change, by U.S. or Canadian regulatory bodies. In
addition, we have entered into long-term sale agreements to
release firm pipeline capacity. We also enter into short-term
and long-term gas purchase agreements.
The aggregate amounts of these agreements were as
follows at December 31, 2014:
In thousands
2015
2016
2017
2018
2019
Thereafter
Total
Less: Amount
representing
interest
Total at present
value
Gas
Purchase
Agreements
Pipeline
Capacity
Purchase
Agreements
Pipeline
Capacity
Release
Agreements
$
132,382
$
80,925
$
3,379
—
—
—
—
—
132,382
79,211
58,827
50,792
26,686
205,313
501,754
—
—
—
—
—
3,379
93
76,748
4
$
132,289
$
425,006
$
3,375
Our total payments for fixed charges under capacity
purchase agreements were $94.3 million for 2014, $98.2
million for 2013, and $94.3 million for 2012. Included in the
amounts were reductions for capacity release sales of $4.8
million for 2014, $4.5 million for 2013, and $4.2 million for
2012. In addition, per-unit charges are required to be paid
based on the actual quantities shipped under the
agreements. In certain take-or-pay purchase commitments,
annual deficiencies may be offset by prepayments subject
to recovery over a longer term if future purchases exceed
the minimum annual requirements.
Environmental Matters
See Note 15 for a discussion of environmental commitments
and contingencies.
In thousands
Operating
leases
Capital
leases
2015
2016
2017
2018
2019
Thereafter
Total
$
5,487
$
680
$
5,457
5,426
5,301
5,209
29,802
564
157
3
—
—
Minimum
lease
payments
6,167
6,021
5,583
5,304
5,209
29,802
$
56,682
$
1,404
$
58,086
81
15. ENVIRONMENTAL MATTERS
We own, or previously owned, properties that may require
environmental remediation or action. We estimate the range
of loss for environmental liabilities based on current
remediation technology, enacted laws and regulations,
industry experience gained at similar sites and an
assessment of the probable level of involvement and
financial condition of other potentially responsible parties.
Due to the numerous uncertainties surrounding the course
of environmental remediation and the preliminary nature of
several site investigations, in some cases, we may not be
able to reasonably estimate the high end of the range of
possible loss. In those cases, we have disclosed the nature
of the possible loss and the fact that the high end of the
range cannot be reasonably estimated. Unless there is an
estimate within a range of possible losses that is more likely
than other cost estimates within that range, we record the
liability at the low end of this range. It is likely that changes
in these estimates and ranges will occur throughout the
remediation process for each of these sites due to our
continued evaluation and clarification concerning our
responsibility, the complexity of environmental laws and
regulations and the determination by regulators of
remediation alternatives.
In the 2012 Oregon general rate case, the SRRM
mechanism was approved to recover the Company's
deferred environmental costs. The Commission ordered a
separate docket to determine the prudence of deferred
costs, the allocation of insurance proceeds, and an earnings
test that would be applied to past and future deferred costs.
This separate docket was resolved in February 2015. See
Note 16 for information regarding the resolution of this
matter.
In Washington, the Company is authorized to defer
environmental costs, if any, that are appropriately allocated
to Washington customers. The 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, the Company
reviews 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 determination
is made.
In December 2010, NW Natural commenced litigation
against certain of its historical liability insurers in Multnomah
County Circuit Court, State of Oregon. In February 2014, we
settled with remaining defendant insurance companies and
received additional payments of approximately $103 million.
The Court dismissed the case on July 29, 2014. The
Company has received total proceeds of approximately
$150 million as a result of this litigation. The proceeds are
recognized in regulatory accounts with the treatment
determined under the SRRM. See Note 16.
Environmental Sites
The following table summarizes information regarding liabilities related to environmental sites, which are recorded in other
current liabilities and other noncurrent liabilities on the balance sheet at December 31:
In thousands
Portland Harbor site:
Gasco/Siltronic Sediments
Other Portland Harbor
Gasco Upland site
Siltronic Upland site
Central Service Center site
Front Street site
Oregon Steel Mills
Total
Current Liabilities
Non-Current Liabilities
2014
2013
2014
2013
$
1,767
$
1,278
$
38,019
$
37,954
1,934
9,535
957
171
1,020
—
1,766
11,010
763
85
1,274
—
4,338
37,117
3,478
39,508
348
—
122
179
406
248
122
179
$
15,384
$
16,176
$
80,123
$
81,895
82
The following table presents information regarding the total
amount of cash paid for environmental sites and the total
regulatory asset deferred as of December 31:
In thousands
Cash paid(1)
2014
2013
$ 113,740
$
98,817
58,859
148,389
Total regulatory asset deferral(2)
(1)
Includes $20.4 million reclassified to utility plant on November
1, 2013 associated with the water treatment station of which a
portion was paid during 2012 through 2014.
Includes cash paid, remaining liability, and interest, net of
insurance reimbursement and amounts reclassified to utility
plant for the water treatment station.
(2)
PORTLAND HARBOR SITE. The Portland Harbor is an
Environmental Protection Agency (EPA) listed Superfund
site that is approximately 10 miles long on the Willamette
River and is adjacent to NW Natural's Gasco uplands and
Siltronic uplands sites. We have been notified that we are a
potentially responsible party to the Superfund site and we
have joined with some of the other potentially responsible
parties (the Lower Willamette Group or LWG) to develop a
Portland Harbor Remedial Investigation/Feasibility Study
(RI/FS). The LWG submitted a draft Feasibility Study (FS) to
the EPA in March 2012 providing a range of remedial costs
for the entire Portland Harbor Superfund Site, which
includes the Gasco/Siltronic Sediment site, discussed
below. The range of costs estimated for various remedial
alternatives for the entire Portland Harbor, as provided in the
draft FS, is $169 million to $1.8 billion. NW Natural's
potential liability is a portion of the costs of the remedy the
EPA will select for the entire Portland Harbor Superfund
site. The cost of that remedy is expected to be allocated
among more than 100 potentially responsible parties. NW
Natural is participating in a non-binding allocation process in
an effort to settle this potential liability. We manage our
liability related to the Superfund site as two distinct
remediation projects, the Gasco/Siltronic Sediments and
Other Portland Harbor projects.
Gasco/Siltronic Sediments. In 2009, NW Natural and Siltronic
Corporation entered into a separate Administrative Order on
Consent with the EPA to evaluate and design specific
remedies for sediments adjacent to the Gasco uplands and
Siltronic uplands sites. NW Natural submitted a draft
Engineering Evaluation/Cost Analysis (EE/CA) to the EPA in
May 2012 to provide the estimated cost of potential remedial
alternatives for this site. At this time, the estimated costs for
the various sediment remedy alternatives in the draft EE/CA
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 $39.8 million
to $350 million. We have recorded a liability of $39.8 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 which is performing the RI/FS for
the EPA. NW Natural also incurs costs related to natural
resource damages from these sites. The Company and
other parties have signed a cooperative agreement with the
Portland Harbor Natural Resource Trustee council to
83
participate in a phased natural resource damage
assessment to estimate liabilities to support an early
restoration-based settlement of natural resource damage
claims. Natural resource damage claims may arise only
after a remedy for clean-up has been settled. We have
accrued a liability for these claims which is at the low end of
the range of the potential liability; 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 and noted above.
GASCO UPLANDS SITE. NW Natural owns a former gas
manufacturing plant that was closed in 1958 (Gasco site)
and is adjacent to the Portland Harbor site described above.
The Gasco site has been under investigation by us for
environmental contamination under the ODEQ Voluntary
Clean-Up Program. It is not included in the range of
remedial costs for the Portland Harbor site noted above. We
manage the Gasco site in two parts, the uplands portion and
the groundwater source control action.
In May 2007, we completed a revised Remedial
Investigation Report for the uplands portion and submitted it
to ODEQ for review. We have recognized a liability for the
remediation of the uplands portion of the site which is at the
low end of the range of potential liability; 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 liabilities, 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 as of December
31, 2014.
SILTRONIC UPLAND. A portion of the Siltronic property
was formerly owned by NW Natural as part of the adjacent
Gasco site. We are currently conducting an investigation of
manufactured gas plant wastes on the uplands at this site
for the ODEQ.
Central Service Center site. We are currently performing an
environmental investigation of the property under the
ODEQ's Independent Cleanup Pathway. This site is on
ODEQ's list of sites with confirmed releases of hazardous
substances, and cleanup is necessary.
Front Street site. The Front Street site was the former
location of a gas manufacturing plant we operated. NW
Natural is currently developing a feasibility study to support
ODEQ's evaluation of potential clean-up alternatives.
Oregon Steel Mills site. See “Legal Proceedings,” below.
Legal Proceedings
NW Natural is subject to claims and litigation arising in the
ordinary course of business. Although the final outcome of
any of these legal proceedings cannot be predicted with
certainty, including the matter described below, NW Natural
does not expect that the ultimate disposition of any of these
matters will have a material effect on our financial condition,
results of operations or cash flows. See also Part I, Item 3,
“Legal Proceedings.”
OREGON STEEL MILLS SITE. In 2004, NW Natural was
served with a third-party complaint by the Port of Portland
(the Port) in a Multnomah County Circuit Court case,
Oregon Steel Mills, Inc. v. The Port of Portland. The Port
alleges that in the 1940s and 1950s petroleum wastes
generated by our predecessor, Portland Gas & Coke
Company, and 10 other third-party defendants, were
disposed of in a waste oil disposal facility operated by the
United States or Shaver Transportation Company on
property then owned by the Port and now owned by Oregon
Steel Mills. The complaint seeks contribution for unspecified
past remedial action costs incurred by the Port regarding the
former waste oil disposal facility as well as a declaratory
judgment allocating liability for future remedial action
costs. No date has been set for trial. Although the final
outcome of this proceeding cannot be predicted with
certainty, we do not expect the ultimate disposition of this
matter will have a material effect on our financial condition,
results of operations or cash flows.
84
• Any amounts in excess of the annual $10 million (plus
interest from insurance) described above would be fully
recoverable through the SRRM, to the extent the utility
earns at or below 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 (plus
interest from insurance) with those earnings that exceed
its authorized ROE.
• For purposes of this earnings test, all earnings derived
from utility assets, including gains and losses associated
with NW Natural’s weighted average cost of gas incentive
mechanism, plus 50% of the Company’s earnings derived
from the Company’s portion of its asset management
agreement with our independent energy marketing
company for asset management services associated with
utility assets will be included.
• In any year that environmental expenses are less than
$10 million (plus the interest on insurance), any unused
tariff rider amount will offset deferred amounts otherwise
collected through the SRRM and any unused insurance
proceeds (plus interest on insurance) will roll forward to
offset the next year’s expenses.
• Any remaining funds will be used to offset environmental
remediation costs at the end of the project.
The Company is evaluating the results of the Order,
including those noted above as well as the state allocations.
At this time, the Company does not anticipate a
disallowance for 2013 or 2014 based on the earnings test
outlined above.
In accordance with accounting guidance and the Company's
policy, the Company expects to recognize net deferred
interest income of approximately $4 million pre-tax on the
associated regulatory account balances in the first quarter of
2015.
Under the Order, the OPUC will revisit the deferral and
amortization of future remediation expenses, as well as the
treatment of remaining insurance proceeds in three years,
or earlier if the Company gains greater certainty about its
future remediation costs.
The Company continues to evaluate the effects of the Order
and is required to file a compliance report with the OPUC
within 30 days of the Order demonstrating how it will be
implemented. The compliance filing is subject to review and
approval by the OPUC and, as a consequence thereof,
additional or different implementation procedures could be
required, which may, among other things, result in additional
impacts on earnings. The Company anticipates filing the
compliance report as required by the Order in March 2015.
16. SUBSEQUENT EVENT
As previously disclosed, in NW Natural’s 2012 Oregon
general rate case, the OPUC adopted a Site Remediation
and Recovery Mechanism (SRRM), through which NW
Natural would track and recover past deferred and future
environmental remediation costs. The OPUC ordered a
separate docket to determine the following items:
• whether and how an earnings test should affect the
recovery of already deferred environmental expenses,
• how an earnings test should apply to the recovery of
future environmental expenditures through the SRRM,
• how to apply insurance proceeds received to offset past
and/or future environmental expenses, and
• the prudence of environmental expenses and insurance
recoveries.
On February 20, 2015, the OPUC issued an Order
addressing these outstanding items. In the Order, the OPUC
determined that NW Natural’s environmental remediation
expenses and associated carrying costs through March 31,
2014 were prudently incurred, and the Company’s
settlement with insurance carriers resulting in insurance
proceeds received was prudent.
The Order also approves the allocation of environmental
costs between states based on historical manufactured gas
usage with approximately 97% allocated to Oregon and 3%
to Washington customers.
Under the Order, NW Natural will be required to forego
collection of $15 million out of the approximate $95 million of
environmental expenses and associated carrying costs that
it 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 factors the OPUC
deemed relevant. The disallowance is currently estimated to
result in a net after-tax charge of $9.1 million taken through
operating income in the first quarter of 2015.
The OPUC applied one-third of the Company’s
approximately $150 million of environmental insurance
recoveries to amounts deferred through 2012, and will allow
full recovery of the remainder of the amounts deferred
through 2012, other than the disallowed amount discussed
above and approximately $33 thousand, which the OPUC
found was not specifically substantiated by company
records. The remaining insurance recoveries will be applied
against post-2012 environmental costs with the funds to be
held in an account accruing interest with the interest also
applied to future expenses as outlined below.
The Order establishes all environmental remediation
expenses deferred after 2012, an aggregate of two-thirds of
the environmental insurance receipts, plus interest, will be
applied ratably over 20 years and the remainder will be
collected through the SRRM, and subject to an earnings test
as follows:
• The Company will recover the first $5 million of annual
expense through an amount that will be collected from
customers through a tariff rider.
• The Company will apply $5 million of insurance (plus
interest) to the next portion of environmental expenses
each year.
85
NORTHWEST NATURAL GAS COMPANY
QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
Quarter ended
In thousands, except share data
March 31
June 30
September 30
December 31
2014
Operating revenues
Net income (loss)
Basic earnings (loss) per share(1)
Diluted earnings (loss) per share(1)
2013
Operating revenues
Net income (loss)
Basic earnings (loss) per share(1)
$
293,386
$
133,169
$
87,199
$
37,884
1.40
1.40
1,071
0.04
0.04
(8,733)
(0.32)
(0.32)
$
277,861
$
131,714
$
88,195
$
37,639
1.40
2,126
0.08
(8,233)
(0.31)
240,283
28,470
1.05
1.04
260,748
29,006
1.07
Diluted earnings (loss) per share(1)
1.07
(1) Quarterly earnings (loss) per share are based upon the average number of common shares outstanding during each quarter. Variations in
(0.31)
1.40
0.08
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)
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
2012
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
1,656
$
599
$
— $
1,286
$
969
2,518
$
199
$
— $
1,061
$
1,656
2,895
$
1,130
$
— $
1,507
$
2,518
86
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, 2014 that have materially affected, or are
reasonably likely to materially affect, our internal control
over financial reporting. The statements contained in Exhibit
31.1 and Exhibit 31.2 should be considered in light of, and
read together with, the information set forth in this Item 9(a).
ITEM 9B. OTHER INFORMATION
None.
87
PART III
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
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 28, 2015 Annual Meeting of
Shareholders is hereby incorporated by reference.
Name
Gregg S. Kantor
David H. Anderson
Stephen P. Feltz
Margaret D. Kirkpatrick
Lea Anne Doolittle
MardiLyn Saathoff
David R. Williams
Grant M. Yoshihara
C. Alex Miller
Shawn M. Filippi
Kimberly A. Heiting
Brody J. Wilson
David A. Weber
Age at
Dec. 31,
2014
57
53
59
60
59
58
61
59
57
42
45
35
55
Positions held during last five years
President and Chief Executive Officer (2009- ); President and Chief
Operating Officer (2007-2008); Executive Vice President (2006-2007);
Senior Vice President, Public and Regulatory Affairs (2003-2006).
Executive Vice President and Chief Operating Officer (2014- );
Executive Vice President Operations and Regulation (2013-2014);
Senior Vice President and Chief Financial Officer (2004-2013).
Senior Vice President and Chief Financial Officer (2013- ); Assistant
Secretary (2007- ); Treasurer and Controller (1999-2013).
Senior Vice President, Environmental Policy and Affairs (2015- );
Senior Vice President and General Counsel (2013-2014); Vice
President and General Counsel (2005-2013).
Senior Vice President and Chief Administrative Officer (2013- ); Senior
Vice President (2008- ); Vice President, Human Resources
(2000-2007).
Senior Vice President and General Counsel (2015- ); 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- ); Vice President,
Finance and Regulation (2009-2013); Assistant Treasurer (2008-2013);
General Manager of Rates and Regulatory Affairs (2002-2009).
Vice President and Corporate Secretary (2015- ); 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).
Controller (2013- ); Acting Controller (2013); Accounting Director
(2012-2013); Senior Manager, PriceWaterhouseCoopers LLP
(2009-2012); Manager, PriceWaterhouseCoopers LLP (2007-2009).
President and Chief Executive Officer, NW Natural Gas Storage, LLC
and Gill Ranch Storage, LLC (2012- ); Interim President and Chief
Executive Officer, NW Natural Gas Storage LLC, and Gill Ranch
Storage, LLC (2011-2012); Chief Operating Officer NW Natural Gas
Storage, LLC and Gill Ranch Storage LLC (November 2010 - January
2011); Managing Director of Information Services and Chief
Information Officer (2005 - 2011); Director of Information Services and
Chief Information Officer (2001-2005).
Each executive officer serves successive annual terms; present terms end on May 28, 2015. There are no family relationships
among our executive officers, directors or any person chosen to become one of our officers or directors.
NW Natural has adopted a Code of Ethics (Code) applicable to all employees and officers that is available on our website at
www.nwnatural.com. We intend to disclose on our website at www.nwnatural.com any amendments to the Code or waivers of
the Code for executive officers.
88
ITEM 11. EXECUTIVE COMPENSATION
The information concerning "Executive Compensation", "Report of the Organization and Executive Compensation Committee",
and "Compensation Committee Interlocks and Insider Participation" contained in our definitive Proxy Statement for the May 28,
2015 Annual Meeting of Shareholders is hereby incorporated by reference. Information related to Executive Officers as of
December 31, 2014 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, 2014 (see Note 6 to the Consolidated Financial Statements):
Plan Category
Equity compensation plans approved by security holders:
LTIP Performance Share Awards (Target Award)(1)(2)
LTIP Restricted Stock Units (Target Award)(1)(2)
LTIP Stock Options(2)
Restated Stock Option Plan
Employee Stock Purchase Plan
Equity compensation plans not approved by security holders:
Executive Deferred Compensation Plan (EDCP)(3)
Directors Deferred Compensation Plan (DDCP)(3)
Deferred Compensation Plan for Directors and Executives (DCP)(4)
(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))
116,265
70,794
—
416,088
$
22,646
1,292
51,559
134,283
n/a
n/a
—
43.40
38.90
n/a
n/a
n/a
412,728
412,728
250,000
—
75,275
n/a
n/a
n/a
738,003
Total
(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, 2014, the number of shares shown in column (a) would increase by 116,265 shares and the number of shares shown in
column (c) would decrease by the same amount of shares.
The aggregate 412,728 shares are available for future issuance under the LTIP as Restricted Stock Units, or Performance Share Awards.
An additional 250,000 shares are available for LTIP Stock Option Issuance at December 31, 2014, but those additional shares are not
available for issuance of LTIP Restricted Stock Units or Performance Share Awards.
812,927
(2)
(3) Prior to January 1, 2005, deferred amounts were credited, at the participant’s election, to either a “cash account” or a “stock account.” If
deferred amounts were credited to stock accounts, such accounts were credited with a number of shares of NW Natural common stock
based on the purchase price of the common stock on the next purchase date under our Dividend Reinvestment and Direct Stock Purchase
Plan, and such accounts were credited with additional shares based on the deemed reinvestment of dividends. Cash accounts are credited
quarterly with interest at a rate equal to Moody’s Average Corporate Bond Yield plus two percentage points, subject to a 6% minimum rate.
At the election of the participant, deferred balances in the stock accounts are payable after termination of Board service or employment in a
lump sum, in installments over a period not to exceed 10 years in the case of the DDCP, or 15 years in the case of the EDCP, or in a
combination of lump sum and installments. Amounts credited to stock accounts are payable solely in shares of common stock and cash for
fractional shares, and amounts in the above table represent the aggregate number of shares credited to participant's stock accounts. We
have contributed common stock to the trustee of the Umbrella Trusts such that the Umbrella Trusts hold approximately the number of
shares of common stock equal to the number of shares credited to all participants’ stock accounts.
(4) Effective January 1, 2005, the EDCP and DDCP were closed to new participants and replaced with the DCP. The DCP continues the basic
provisions of the EDCP and DDCP under which deferred amounts are credited to either a “cash account” or a “stock account.” Stock
accounts represent a right to receive shares of NW Natural common stock on a deferred basis, and such accounts are credited with
additional shares based on the deemed reinvestment of dividends. Effective January 1, 2007, cash accounts are credited quarterly with
interest at a rate equal to Moody’s Average Corporate Bond Yield. Our obligation to pay deferred compensation in accordance with the
terms of the DCP will generally become due on retirement, death, or other termination of service, and will be paid in a lump sum or in
installments of five, 10, or 15 years as elected by the participant in accordance with the terms of the DCP. Amounts credited to stock
accounts are payable solely in shares of common stock and cash for fractional shares, and amounts in the above table represent the
aggregate number of shares credited to participant's stock accounts. We have contributed common stock to the trustee of the Supplemental
Trust such that this trust holds approximately the number of common shares equal to the number of shares credited to all participants' stock
accounts. The right of each participant in the DCP is that of a general, unsecured creditor of the Company.
The information captioned “Beneficial Ownership of Common Stock by Directors and Executive Officers” and "Security
Ownership of Common Stock of Certain Beneficial Owners" contained in our definitive Proxy Statement for the May 28, 2015
Annual Meeting of Shareholders is incorporated herein by reference.
89
ITEM 13. CERTAIN RELATIONSHIPS AND
RELATED TRANSACTIONS, AND DIRECTOR
INDEPENDENCE
The information captioned "Transactions with Related
Persons" and "Corporate Governance" in the Company’s
definitive Proxy Statement for the May 28, 2015 Annual
Meeting of Shareholders is hereby incorporated by
reference.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND
SERVICES
The information captioned "2014 and 2013 Audit Firm Fees"
in the Company’s definitive Proxy Statement for the May 28,
2015 Annual Meeting of Shareholders is hereby
incorporated by reference.
90
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
(a) The following documents are filed as part of this report:
PART IV
1. A list of all Financial Statements and Supplemental Schedules is incorporated by reference to Item 8.
2. List of Exhibits filed:
Reference is made to the Exhibit Index commencing on page 93.
91
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the
Securities Exchange Act of 1934, the registrant has duly
caused this report to be signed on its behalf by the
undersigned, thereunto duly authorized.
NORTHWEST NATURAL GAS COMPANY
By: /s/ Gregg S. Kantor
Gregg S. Kantor
President and Chief Executive Officer
Date: February 27, 2015
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons
on behalf of the registrant and in the capacities and on the date indicated.
Signature
/s/ Gregg S. Kantor
Gregg S. Kantor
President and Chief Executive Officer
/s/ Stephen P. Feltz
Stephen P. Feltz
Senior Vice President and Chief Financial Officer
/s/ Brody J. Wilson
Brody J. Wilson
Controller
/s/ Timothy P. Boyle
Timothy P. Boyle
/s/ Martha L. Byorum
Martha L. Byorum
/s/ John D. Carter
John D. Carter
/s/ Mark S. Dodson
Mark S. Dodson
/s/ C. Scott Gibson
C. Scott Gibson
/s/ Tod R. Hamachek
Tod R. Hamachek
/s/ Jane L. Peverett
Jane L. Peverett
/s/ Kenneth Thrasher
Kenneth Thrasher
/s/ Malia H. Wasson
Malia H. Wasson
Title
Date
Principal Executive Officer and Director
February 27, 2015
Principal Financial Officer
February 27, 2015
Principal Accounting Officer
February 27, 2015
)
)
)
)
)
)
)
)
)
)
)
February 27, 2015
)
)
)
)
)
)
)
)
)
)
)
)
)
)
Director
Director
Director
Director
Director
Director
Director
Director
Director
92
NORTHWEST NATURAL GAS COMPANY
Exhibit Index to Annual Report on Form 10-K
For the Fiscal Year Ended December 31, 2014
Exhibit Number Document
*3a.
*3b.
*4a.
*4b.
*4c.
*4d.
*4e.
*4f.
*4g.
*4h.
*4i.
*4j.
Restated Articles of Incorporation, as filed and effective May 31, 2006 and amended June 3, 2008 (incorporated
herein by reference to Exhibit 3.1 to Form 10-Q for the period ending June 30, 2008, File No. 1-15973).
Bylaws as amended May 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. 0-994).
Form of Secured Medium-Term Notes, Series B (incorporated herein by reference to Exhibit 4.1 to Form 8-K dated
October 4, 2004, File No. 1-15973).
Form of Unsecured Medium-Term Notes, Series B (incorporated herein by reference to Exhibit 4.2 to Form 8-K dated
October 4, 2004, File No. 1-15973).
Gill Ranch Note Purchase Agreement, dated November 30, 2011, among Gill Ranch Storage, LLC and the parties
listed thereto (incorporated herein by reference to Exhibit 4m. to Form 10-K for 2011, File No. 1-15973).
Twenty-First Supplemental Indenture, providing, among other things, for First Mortgage Bonds, 4.00% Series Due
2042, dated as of October 15, 2012, by and between Northwest Natural Gas Company, Deutsche Bank Trust
Company Americas (formerly known as Bankers Trust Company), and Stanley Burg (Successor to R.G. Page and
J.C. Kennedy) (incorporated herein by reference to Exhibit 4.1 to Form 8-K dated October 26, 2012, File No.1-15973).
Form of Credit Agreement among Northwest Natural Gas Company and the parties thereto, with JPMorgan Chase
Bank, N.A. as administrative agent and U.S. Bank, N.A. and Wells Fargo Bank, N.A. as co-syndication agents, dated
as of December 20, 2012 (incorporated herein by reference to Exhibit 4.1 to Form 8-K dated December 20, 2012, File
No.1-15973).
93
*4k.
*4l.
4m.
4n.
Form of Letter Agreement, between each of JPMorgan Chase Bank, N.A., Bank of America, N.A., Canadian Imperial
Bank of Commerce, Royal Bank of Canada, TD Bank, N.A., Union Bank, N.A., US Bank, N.A., and Wells Fargo Bank,
N.A., with JPMorgan Chase Bank, N.A. as Administrative Agent, extending the Credit Agreement between Northwest
Natural Gas Company and each financial institution, effective as of December 20, 2013. (incorporated herein by
reference to Exhibit 4k to Form 10-K for 2013, File No. 1-15973).
Amendment No. 1 to Note Purchase Agreement, dated April 29, 2014, among Gill Ranch Storage, LLC. and the
parties listed thereto (incorporated herein by reference to Exhibit 4 to Form 10-Q for the quarter ended March 31,
2014, 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 Credit Agreement between Northwest
Natural Gas Company and each financial institution, effective as of December 20, 2014.
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.
*10a
Carry and Earning Agreement (incorporated herein by reference to Exhibit 10.1 to Form 10-Q for the quarter ended
March 31, 2011, File No. 1-15973).
*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, effective September 1, 2004 restated 2011 (incorporated herein by
reference to Exhibit 10.1 to Form 10-Q for the quarter ended September 30, 2011, File No. 1-15973).
*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).
94
*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).
*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 January 1, 2012
(incorporated herein by reference to Exhibit 10k. to Form 10-K for 2011, File No. 1-15973).
*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 (incorporated herein by reference to Exhibit 10n. to
Form 10-K for 2011, File No. 1-15973).
*10q.
Form of Agreement to Recoupment Provisions of Executive Annual Incentive Plan, effective as of January 1, 2010
(incorporated herein by reference to Exhibit 10o. to Form 10-K for 2009, File No. 1-15973).
*10r.
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).
*10s.
Northwest Natural Gas Company Long-Term Incentive Plan, as amended and restated effective May 24, 2012
(incorporated herein by reference to Exhibit 10r to Form 10-K for 2013, File No. 1-15973)
*10t.
Form of Long-Term Incentive Award Agreement under the Long-Term Incentive Plan (2012-2014) (incorporated herein
by reference to Exhibit 10v. to Form 10-K for 2011, File No. 1-15973).
*10u.
Form of Long-Term Incentive Award Agreement under the Long-Term Incentive Plan (2013-2015) (incorporated herein
by reference to Exhibit 10v. to Form 10K for 2012, File No. 1-15973).
*10v.
Form of Long-Term Incentive Award Agreement under the Long-Term Incentive Plan (2014-2016). (incorporated
herein by reference to Exhibit 10v. to Form 10-K for 2013, File No. 1-15973).
10w.
Form of Long-Term Incentive Award Agreement under the Long-Term Incentive Plan (2015-2017).
*10x.
Form of Consent dated December 14, 2006 entered into by each executive officer (incorporated herein by reference
to Exhibit 10.1 to Form 8-K dated December 19, 2006, File No. 1-15973).
*10y.
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).
95
*10z.
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).
*10aa. Form of Restricted Stock Unit Award Agreement under the Long-Term Incentive Plan (2012) (incorporated herein by
reference to Exhibit 10.1 to Form 8-K dated December 14, 2011, File No. 1-15973).
*10bb. 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)
*10cc. Form of Special Restricted Stock Unit Award Agreement under the Long-Term Incentive Plan between the Company
and an executive officer. (incorporated herein by reference to Form 10-Q for the quarter ended March 31, 2014, File
No. 1-15973).
*10dd. Annual Incentive Plan for NW Natural Gas Storage, LLC, as amended February 2, 2012 (incorporated herein by
reference to Exhibit 10cc. to Form 10-K for 2012, File No. 1-15973).
*10ee. Long Term Incentive Plan for NW Natural Gas Storage, LLC (incorporated herein by reference to Exhibit 10dd. to
Form 10-K for 2012, File No. 1-15973).
101.
The following materials from Northwest Natural Gas Company Annual Report on Form 10-K for the fiscal year ended
December 31, 2014, formatted in Extensible Business Reporting Language (XBRL):
(i) Consolidated Statements of Income;
(ii) Consolidated Balance Sheets;
(iii) Consolidated Statements of Cash Flows; and
(iv) Related notes.
*Incorporated herein by reference as indicated
96
NORTHWEST NATURAL GAS COMPANY
Ratios of Earnings to Fixed Charges
(Unaudited)
EXHIBIT 12
In thousands, except share data
Fixed Charges, as defined:
Interest on Long-Term Debt
Other Interest
Amortization of Debt Discount and Expense
Interest Portion of Rentals
Total Fixed Charges, as defined
Earnings, as defined:
Net Income
Taxes on Income
Fixed Charges, as above
Total Earnings, as defined
Ratios of Earnings to Fixed Charges
Year Ended December 31,
2014
2013
2012
2011
2010
$
$
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
39,198
1,587
1,766
2,130
44,681
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
72,013
49,033
44,681
$ 165,727
3.71
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 27, 2015 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 27, 2015
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 27, 2015
/s/ Gregg S. Kantor
Gregg S. Kantor
President and Chief Executive Officer
CERTIFICATION
I, Stephen P. Feltz, certify that:
EXHIBIT 31.2
1. I have reviewed this annual report on Form 10-K for Northwest Natural Gas Company;
2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material
fact necessary to make the statements made, in light of the circumstances under which such statements were made, not
misleading with respect to the period covered by this report;
3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present
in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods
presented in this report;
4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and
procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined
in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under
our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made
known to us by others within those entities, particularly during the period in which this report is being prepared;
(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed
under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of
financial statements for external purposes in accordance with generally accepted accounting principles;
(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our
conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report
based on such evaluation; and
(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the
registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially
affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over
financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons
performing the equivalent functions):
(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting
which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial
information; and
(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the
registrant’s internal control over financial reporting.
Date: February 27, 2015
/s/ Stephen P. Feltz
Stephen P. Feltz
Senior Vice President and Chief Financial Officer
corporate information
investor and shareholder information
robert hess
director, investor relations
(800) 422-4012, ext. 2388
rsh@nwnatural.com
chu lee
Manager, shareholder services
(800) 422-4012, ext. 2402
c4l@nwnatural.com
stock transfer agent and registrar
community & sustainability report
For common stock:
learn more about nW natural’s community involvement and
american stock transfer & trust company
philanthropic contributions, environmental stewardship,
6201 15th avenue
Brooklyn, nY 11219
(888) 777-0321
web: amstock.com
email: info@amstock.com
trustee and bond paying agent
For bond issues:
deutsche Bank trust company americas
60 Wall street
new York, nY 10005
(800) 735-7777
employee safety efforts and other company initiatives.
View the community & sustainability annual report at
nwnatural.com/aboutnwnatural/community.
low-income 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 program. 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 assistance 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/
saveenergyandmoney/energyefficiencyassistance.
energy-efficiency programs
nW natural partners with energy trust of oregon to offer our
oregon and Washington customers energy-efficiency programs
and services. learn more about the results of these programs
and the benefits to our customers.
View the energy trust of oregon annual report at
nwnatural.com/aboutnwnatural/environmentalstewardship.
220 nw second avenue
portland, oregon 97209
nwnatural.com
nyse: nwn
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