NWN 10-K 12/31/2008
Section 1: 10-K (FORM 10-K)
Table of Contents
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, 2008
OR
[ ]
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from
to
Commission file number 1-15973
NORTHWEST NATURAL GAS COMPANY
(Exact name of registrant as specified in its charter)
Oregon
(State or other jurisdiction of
incorporation or organization)
93-0256722
(I.R.S. Employer
Identification No.)
220 N.W. Second Avenue, Portland, Oregon 97209
(Address of principal executive offices) (Zip Code)
Registrant’s telephone number, including area code: (503) 226-4211
Securities registered pursuant to Section 12(b) of the Act:
Title of each class
Common Stock
Name of each exchange on which registered
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 [
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. [
]
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 if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K 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 definitions of “accelerated filer,” “large accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check
one):
Large Accelerated Filer [ X ]
Non-accelerated filer [ ]
Accelerated Filer [ ]
Smaller Reporting Company [ ]
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes [ ] No [ X ]
As of June 30, 2008, the registrant had 26,435,373 shares of its Common Stock outstanding. The aggregate market value of these shares of
Common Stock (based upon the closing price of these shares on the New York Stock Exchange on that date) held by non-affiliates was
$1,211,499,354.
At February 23, 2009, 26,501,188 shares of the registrant’s Common Stock (the only class of Common Stock) were outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Proxy Statement of the registrant’s, to be filed in connection with the 2009 Annual Meeting of Shareholders, are incorporated by
reference in Part III.
Table of Contents
NORTHWEST NATURAL GAS COMPANY
Annual Report to Securities and Exchange Commission
on Form 10-K
For the Fiscal Year Ended December 31, 2008
Table of Contents
PART I
Page
1
2
4
4
4
4
5
12
14
15
16
16
17
17
18
18
27
27
27
27
Item 1A.
Item 1B.
Item 2.
Item 3.
Item 4.
Glossary of Terms
Forward-Looking Statements
Business
General
Business Segments
Local Gas Distribution
Utility Gas Supply, Storage and Transportation Capacity
Competition and Marketing
Gas Storage
Other
Regulation and Rates
Environmental Issues
Employees
Additions to Infrastructure
Available Information
Risk Factors
Unresolved Staff Comments
Properties
Legal Proceedings
Submission of Matters to a Vote of Security Holders
PART II
Item 5.
Item 6.
Item 7.
Item 7A.
Item 8.
Item 9.
Item 9A.
Item 9B.
Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Selected Financial Data
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Quantitative and Qualitative Disclosures About Market Risk
Financial Statements and Supplementary Data
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
Controls and Procedures
Other Information
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30
32
66
69
116
116
116
PART III
Item 10.
Item 11.
Item 12.
Item 13.
Item 14.
Directors, Executive Officers and Corporate Governance
Executive Compensation
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Certain Relationships and Related Transactions and Director Independence
Principal Accountant Fees and Services
117
118
118
119
119
Item 1.
PART IV
Item 15.
Exhibits and Financial Statement Schedules
SIGNATURES
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GLOSSARY OF TERMS
Average weather: equal to the 25-year average degree
days based on temperatures established in our 2003 Oregon
general rate case.
Interruptible service: natural gas service offered to
customers (usually large commercial or industrial users) under
contracts or rate schedules that allow for temporary
interruptions to meet the needs of firm service customers.
Bcf: one billion cubic feet, a volumetric measure of natural
gas, roughly equal to 10 million therms.
Liquefied natural gas (LNG): the cryogenic liquid form of
natural gas. To reach a liquid form at atmospheric pressure,
natural gas must be cooled to approximately -260 degrees
Fahrenheit.
Btu: British thermal unit, a basic unit of thermal energy
measurement. One Btu equals the energy required to raise
one pound of water one degree Fahrenheit at atmospheric
pressure and 60 degrees Fahrenheit. One hundred thousand
Btu’s equal one therm.
Purchased Gas Adjustment (PGA): a regulatory
mechanism for adjusting customer rates due to changes in the
cost to acquire commodity supplies.
Core utility customers: residential, commercial and
industrial customers on firm service from the utility.
Return on equity (ROE): a measure of corporate
profitability, calculated as net income divided by average
common stock equity. Authorized ROE refers to the equity
rate approved by a regulatory agency for utility investments
funded by common stock equity.
Decoupling: a rate mechanism, also referred to as our
conservation tariff, which is designed to break the link
between earnings and the quantity of natural gas consumed
by customers. The design is intended to allow the utility to
encourage customers to conserve energy while not adversely
affecting its earnings due to losses in sales volumes.
Sales service: service provided to a customer that receives
both natural gas supply and transportation of that gas from
the regulated utility.
Degree days: units of measure that reflect temperaturesensitive consumption of natural gas, calculated by
subtracting the average of a day’s high and low temperatures
from 65 degrees Fahrenheit.
Therm: the basic unit of natural gas measurement, equal to
100,000 Btu’s. An average residential customer in our
service area uses about 700 therms in an average weather
year.
Demand charge: a component in all core utility customer
rates that covers the cost of securing firm pipeline capacity to
meet peak demand, whether that capacity is used or not.
Transportation service: service provided to a customer
that secures its own natural gas supply and pays the regulated
utility only for use of the distribution system to transport it.
Firm service: natural gas service offered to customers under
contracts or rate schedules that will not be disrupted to meet
the needs of other customers, particularly during cold
weather.
Utility margin: utility gross revenues less the associated cost
of gas and applicable revenue taxes. Also referred to as utility
net operating revenues.
General rate case: a periodic filing with state or federal
regulators to establish equitable rates and balance the
interests of all classes of customers and our shareholders.
Weather normalization: a rate mechanism that allows the
utility to adjust customers’ bills during the winter heating
season to reduce variations in margin recovery due to
fluctuations from average temperatures.
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Forward-Looking Statements
Statements and information included in this report that are not purely historical are forward-looking statements within the
“safe harbor” provisions and meaning of Section 21E of the Securities Exchange Act of 1934, as amended (Exchange Act).
Forward-looking statements include, but are not limited to, statements concerning plans, objectives, goals, strategies, future events
or performance, trends, cyclicality, growth, development of projects, exploration of new gas supplies, estimated expenditures,
costs of compliance, potential efficiencies, impacts of new laws and regulations, projected obligations under retirement plans,
adequacy of and shift in mix of gas supplies, and adequacy of regulatory deferrals. Such statements are expressed in good faith and
we believe have a reasonable basis; however, each forward-looking statement involves uncertainties and is qualified in its entirety
by reference to the following important factors, among others, that could cause our actual results to differ materially from those
projected, including:
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prevailing state and federal governmental policies and regulatory actions with respect to allowed rates of return,
industry and rate structure, timely and adequate purchased gas cost and investment recovery, acquisitions and
dispositions of assets and facilities, operation and construction of plant facilities, present or prospective wholesale and
retail competition, changes in laws and regulations including but not limited to tax laws and policies, changes in and
compliance with environmental and safety laws, regulations, policies and orders, and laws, regulations and orders with
respect to the maintenance of pipeline integrity, including regulatory allowance or disallowance of costs based on
regulatory prudency reviews;
economic factors that could cause a severe downturn in the national economy, in particular the economies of Oregon
and Washington, thus affecting demand for natural gas;
unanticipated population growth or decline and changes in market demand caused by changes in demographic or
customer consumption patterns;
the creditworthiness of customers, suppliers and financial derivative counterparties;
market conditions and pricing of natural gas relative to other energy sources;
unanticipated changes that may affect our liquidity or access to capital markets, including volatility in the credit
environment and financial services sector;
capital market conditions, including their effect on financing costs, the fair value of pension assets and on pension and
other postretirement benefit costs;
application of the Oregon Public Utility Commission rules interpreting Oregon legislation intended to ensure that
utilities do not collect more income taxes in rates than they actually pay to government entities;
weather conditions, natural phenomena including earthquakes or other geohazard events, and other pandemic events;
competition for retail and wholesale customers and our ability to remain price competitive;
our ability to access sufficient gas supplies and our dependence on a single pipeline transportation company for natural
gas transmission;
property damage associated with a pipeline safety incident, as well as risks resulting from uninsured damage to our
property, intentional or otherwise;
financial and operational risks relating to business development and investment activities, including the Palomar
pipeline and the proposed Gill Ranch underground gas storage facility;
unanticipated changes in interest or foreign currency exchange rates or in rates of inflation;
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changes in estimates of potential liabilities relating to environmental contingencies or in timely and adequate regulatory
or insurance recovery for such liabilities;
unanticipated changes in future liabilities and legislation relating to employee benefit plans, including changes in key
assumptions;
our ability to transfer knowledge of our aging workforce and maintain a satisfactory relationship with the union that
represents a majority of our workers;
potential inability to obtain permits, rights of way, easements, leases or other interests or other necessary authority to
construct pipelines, develop storage or complete other system expansions and the timing of such projects;
federal, state or other regulatory actions related to climate change; and
legal and administrative proceedings and settlements.
These forward-looking statements involve risks and uncertainties. We may make other forward-looking statements from
time to time, including statements in press releases and public conference calls and webcasts. All forward-looking statements made
by us are based on information available to us at the time the statements are made and speak only as of the date on which such
statement is made. We undertake no obligation to update any forward-looking statement to reflect events or circumstances after
the date on which such statement is made or to reflect the occurrence of unanticipated events. New factors emerge from time to
time and it is not possible for us to predict all such factors, nor can we assess the impact of each such factor or the extent to which
any factor, or combination of factors, may cause results to differ materially from those contained in any forward-looking statement.
Some of these risks and uncertainties 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.
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NORTHWEST NATURAL GAS COMPANY
PART I
ITEM 1. BUSINESS
General
Northwest Natural Gas Company (NW Natural) was incorporated under the laws of Oregon in 1910. Our company and
its predecessors have supplied gas service to the public since 1859. We have been doing business as NW Natural since
September 1997. We maintain operations in Oregon, Washington and California and conduct business through NW Natural, two
wholly-owned subsidiaries and a joint venture. A reference to NW Natural (“we,” “us” or “our”) in this report means NW Natural
and it subsidiaries and joint venture unless otherwise noted.
Business Segments
We operate in two primary reportable business segments, Local Gas Distribution and Gas Storage. We also have other
investments and business activities not specifically related to one of these two reporting segments which we aggregate and report as
Other.
Local Gas Distribution
We are principally engaged in the distribution of natural gas in Oregon and southwest Washington. We refer to this
business segment as our local gas distribution or utility. Local gas distribution involves building and maintaining a safe and reliable
pipeline distribution system, purchasing gas from producers and marketers, contracting for the transportation of gas over pipelines
from the supply basins to our service territory, and reselling the gas to customers subject to rates and terms approved by the
Oregon Public Utility Commission (OPUC) or by the Washington Utilities and Transportation Commission (WUTC). Gas
distribution also includes transporting gas owned by large customers from the interstate pipeline connection, or city gate, to the
customers’ facilities for a fee, also approved by the OPUC or WUTC. Approximately 96 percent of our consolidated assets and
85 percent of our consolidated net income in 2008 were related to the local gas distribution segment. The OPUC has allocated to
us as our exclusive service area a major portion of western Oregon, including the Portland metropolitan area, most of the
Willamette Valley and the coastal area from Astoria to Coos Bay. We also hold certificates from the WUTC granting us exclusive
rights to serve portions of three southwest Washington counties bordering the Columbia River. We provide gas service in 124 cities
and neighboring communities in 15 Oregon counties, as well as in 14 cities and neighboring communities in three Washington
counties. The city of Portland is the principal retail and manufacturing center in the Columbia River Basin, and is a major port for
trade with Asia.
At year-end 2008, we had approximately 662,000 total customers, consisting of 599,000 residential, 62,000 commercial
and 1,000 industrial sales and transportation customers. Approximately 90 percent of our customers are located in Oregon and 10
percent are in Washington. Industries we serve include: pulp, paper and other forest products; the manufacture of electronic,
electrochemical and electrometallurgical products; the processing of farm and food products; the production of various mineral
products; metal fabrication and casting; the production of machine tools, machinery and textiles; the manufacture of asphalt,
concrete and rubber; printing and publishing; nurseries; government and educational institutions; and electric generation. No
individual customer or industry accounts for a significant portion of our revenues.
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Utility Gas Supply, Storage and Transportation Capacity
We meet the expected needs of our core utility customers through natural gas purchases from a variety of suppliers. Our
supply and capacity plan is based on forecasted customer requirements and takes into account estimated load growth by type of
customer, attrition, conservation, distribution system constraints, interstate pipeline capacity and contractual limitations and the
forecasted movement of large customers between sales service and transportation-only service. We perform sensitivity analyses
based on factors such as weather variations and price elasticity effects. We have a diverse portfolio of short-, medium- and longterm firm gas supply contracts that we supplement during periods of peak demand with gas from storage facilities either owned by
or contractually committed to us.
Gas Acquisition Strategy
Our goals in purchasing gas for our core utility market are:
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Reliability—Ensuring a gas resource portfolio that is sufficient to satisfy core utility customer requirements under
extremely cold weather conditions as described below in “Source of Supply—Design Day Sendout;”
Lowest reasonable cost—Applying strategies to acquire gas supplies at the lowest reasonable cost to utility
customers;
Price stability—Making use of physical assets (e.g. gas storage) and financial instruments (e.g. financial hedge
contracts such as price swaps) to manage commodity price variability; and
Cost recovery—Managing gas purchase costs prudently to minimize the risks associated with regulatory review and
recovery of gas acquisition costs.
To achieve our gas acquisition strategy, we employ a gas purchasing strategy that emphasizes a diversity of supply,
liquidity, price risk management, asset optimization and regulatory alignment as described below.
Diversity of supply. There are three primary means by which we diversify our gas supply acquisitions: regional supply
basins; contract types; and contract durations.
Our utility obtains its gas supplies from three key supply basins. They are the Alberta and British Columbia regions in
Canada, and the Rocky Mountain region in the United States. We believe that gas supplies available in the western United States
and Canada are adequate to serve our core utility requirements for the foreseeable future, but we are considering shifting more of
our supply mix to the U.S. Rocky Mountains based on projections of declining gas imports from western Canada and increased
gas production in the U.S. Rocky Mountains. We believe that the cost of natural gas coming from these regions will continue to
track market prices, but there may be price discounts on supplies from the U.S. Rocky Mountains in the near term due to of the
limited amount of transmission capacity to transport that supply to existing markets. Several projects have been proposed recently
to increase pipeline capacity out of the U.S. Rocky Mountain region. In addition, we also believe the potential development of a
liquefied natural gas (LNG) import terminal would benefit the Pacific Northwest. If constructed, an LNG import terminal would
introduce a new source of gas supply to our utility customers and the region, thereby increasing the diversity of available sources of
energy and increasing the overall supply of natural gas available to meet future demand growth in the region.
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We typically enter into gas purchase contracts for:
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•
•
year-round baseload supply;
additional baseload supply for the winter heating season;
winter heating season contracts where we have the option to call on all or some of the supplies on a daily basis; and
spot purchases, taking into account forecasted customer requirements, storage injections and withdrawals and
seasonal weather fluctuations.
Other less frequent types of contracts include non-heating season baseload contracts, non-heating season contracts where
the supplier has the option to supply gas to us on a daily basis, and seasonal exchange purchase and sale contracts. We try to
maintain a diversified portfolio of purchase arrangements.
We also use a variety of multi-year contract durations to avoid having to re-contract a significant portion of our supplies
every year. See “Core Utility Market Basic Supply,” below.
Trading Points. We purchase our gas supplies at liquid trading points to facilitate competition and price transparency.
These trading points include the NOVA Inventory Transfer (NIT) point in Alberta (also referred to as AECO), Huntingdon/Sumas
and Station 2 in British Columbia, and various receipt points in the U.S. Rocky Mountains.
Price risk management. There are four general methods that we currently use for managing gas commodity price risk:
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negotiating fixed prices directly with gas suppliers;
negotiating financial instruments that exchange the floating price in a physical supply contract for a fixed price (referred
to as price swaps);
negotiating financial instruments that set a ceiling or floor price, or both, on a floating price contract (referred to as
calls, puts, and collars); and
buying gas and injecting it into storage. See “Cost of Gas,” below.
Asset optimization. We use our gas supply, storage and transportation flexibility to capture opportunities that emerge
during the course of the year for gas purchases, sales, exchanges or other means to manage net gas costs. In particular, our Mist
underground storage facility provides flexibility in this regard. In addition, in an effort to maximize the value of our gas storage and
pipeline capacity, we contract with an independent energy marketing company that optimizes our unused capacity when those
assets are not serving the needs of our core utility customers. This asset optimization service performed by the independent energy
marketing company produces cost savings that are refunded to core utility customers, as well as generates incremental revenues
which are included in our gas storage business segment. See Note 2.
Regulatory alignment. Mechanisms for gas cost recovery are designed to be fair, and balance the interests of
customers and shareholders. In general, utility rates are designed to recover the cost of, but not earn a return on, the gas
commodity purchased, and we attempt to minimize risks associated with cost recovery through:
•
re-setting customer rates annually for changes in forecasted purchased gas costs and customer deferrals of prior
year’s actual versus forecasted gas purchase costs. (see Part II, Item 7., “Results of Operations—Regulatory
Matters—Rate Mechanisms—Purchased Gas Adjustment”);
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aligning customer and shareholder interests, such as through the use of our purchased gas adjustment (PGA) incentive
sharing mechanism, weather normalization, conservation, and gas storage sharing mechanisms (see Part II, Item 7.,
“Results of Operations—Regulatory Matters”); and
periodic review of regulatory deferrals with state regulatory commissions and key customer groups.
Cost of Gas
The cost of gas to supply our core utility customers primarily consists of the purchase price paid to suppliers, charges paid
to pipeline companies to store and transport the gas to our distribution system and gains or losses related to commodity hedge
contracts entered into in connection with the purchase of gas for core utility customers.
Supply cost. Volatility in natural gas commodity prices has increased dramatically over the last several years primarily due
to shifts in the balance of supply and demand, which has been affected by the level of gas imports, regional accessibility to gas
supplies, supply disruptions, changes in the global energy markets, availability of pipeline capacity to transport natural gas from
region to region, and changes in general economic conditions. We are in a favorable position with respect to gas production
because of the proximity of our service territory to supply basins in western Canada and the U.S. Rocky Mountains, where some
growth in gas production is expected to continue for the foreseeable future.
Transportation cost. Pipeline transportation rates charged by our pipeline suppliers had been relatively stable until
recently. In 2006, two of the five major pipelines used by NW Natural filed with the Federal Energy Regulatory Commission
(FERC) for significant rate increases which were implemented in 2007. Pipeline transportation rate increases are generally passed
on to our customers through state-approved annual PGA mechanisms.
Gas price hedging. We seek to mitigate the effects of higher gas commodity prices and price volatility on core utility
customers by using our underground storage facilities strategically and by entering into financial hedge contracts to fix or limit the
price of gas commodity purchases.
Managing the Cost of Gas
We manage natural gas commodity price risk through active physical and financial hedging programs Our financial hedge
contracts make up a majority of our commodity price hedging activity, and these contracts are with a variety of investment-grade
credit counterparties, typically with credit ratings of AA- or higher. See Part II, Item 7A., “Quantitative and Qualitative Disclosures
About Market Risk—Credit Risk—Credit exposure to financial derivative counterparties.” Under our financial hedge program, we
enter into commodity swaps, puts, calls and collars anywhere from one month up to five years into the future. Realized gains or
losses from financial commodity hedge contracts are treated as reductions or increases to the cost of gas.
In addition to the prices that are hedged through financial contracts, we also use gas storage as a physical hedge. We
purchase and inject about 15 to 20 percent of our annual gas supply requirements into storage during the summer when demand
and gas prices are generally lower. The gas is stored for withdrawal during the winter months in five different storage facilities. We
own and operate three of
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these storage facilities located within our service territory, which eliminates the need for additional upstream pipeline capacity and
provides significant cost savings. The other two storage facilities are owned and operated by our primary pipeline supplier.
The intended effect of our physical and financial hedging programs are to manage the price exposure for a majority of our
gas supply portfolio for the following gas contract year, with prices hedged for approximately 60 percent of year round supplies
and 80 percent or more of our expected winter-heating season supplies based on forecasted customer requirements.
Source of Supply—Design Year and Design Day Sendout
The effectiveness of our gas supply program ultimately rests on whether we provide reliable service at a reasonable cost
to our core utility customers. For this purpose, we develop a composite design year that is based on the coldest weather
experienced over the last 20 years in our service territory. We start with the coldest heating season during the last 20 years and
then modify it to include the coldest single weather day over that same 20-year period. This coldest “design day” is the maximum
anticipated demand on the natural gas distribution system during a 24-hour period, which currently assumes weather at an average
temperature of 12 degrees Fahrenheit. We also assume that all usage by interruptible customers will be curtailed on the design day.
Our projected sources of delivery for design day firm utility customer sendout total approximately 9 million therms. We are
currently capable of meeting 63 percent of our firm customer design day requirements with storage and peaking supply sources
located within or adjacent to our service territory. Optimal utilization of storage and peaking facilities on our design day reduces the
cost and dependency on firm interstate pipeline transportation. On January 5, 2004, we experienced our current-record firm
customer sendout of 7.2 million therms, and a total sendout of 8.9 million therms, on a day that was approximately 9 degrees
Fahrenheit warmer than the design day temperature. That January 2004 cold weather event lasted about 10 days, and the actual
firm customer sendout each day provided data indicating that load forecasting models required very little re-calibration. Similar cold
temperatures experienced in December 2008 produced very high sendout days but they were still about 20 percent below our
2004 record. Accordingly, we believe that our supplies would be sufficient to meet firm customer demand if we were to experience
design day conditions. We will continue to evaluate and update our forecasts of design day requirements in connection with our
integrated resource plan (IRP) process (see “Integrated Resource Plan,” below).
The following table shows the sources of supply that are projected to be used to satisfy the design day sendout for the
2008-2009 winter heating season:
Projected Sources of Supply for Design Day Sendout
Therms
(in millions)
3.3
1.1
2.4
1.8
0.4
9.0
Sources of Supply
Firm supplier contracts
Off-system firm storage contracts
Mist underground storage (utility only)
Company-owned LNG storage
Recall agreements
Total
Percent
37
12
27
20
4
100
We believe the combination of the natural gas supply purchases under contract, our peaking supplies and the
transportation capacity held under contract on the interstate pipelines sufficiently satisfies the needs of existing customers and
positions the utility to meet future requirements.
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Core Utility Market Basic Supply
We purchase gas for our core utility customers from a variety of suppliers located in western Canada and the U.S. Rocky
Mountain area. Currently, about 60—70 percent of our supply comes from Canada, with the balance coming primarily from the
U.S. Rocky Mountain region, but we are considering shifting more of our supply mix to the U.S. Rocky Mountains based on
projections of declining gas imports from western Canada and increased gas production in the U.S. Rocky Mountains. At
January 1, 2009, we had 28 firm contracts with 15 suppliers and remaining terms ranging from five months to six years, which
provide for a maximum of 2.2 million therms of firm gas per day during the peak winter heating season and 1.1 million therms per
day during the entire year. These contracts have a variety of pricing structures and purchase obligations. During 2008, we
purchased 831 million therms of gas under the following contract durations:
Contract Duration (primary terms)
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
50
16
34
100
We regularly renew or replace our gas supply contracts with new agreements with a variety of existing and new suppliers.
Aside from the optimization of our core utility gas supplies by the independent energy marketing company (see “Gas Acquisition
Strategy—Asset optimization,” above), our daily contract requirements are provided by multiple sources with no more than three
suppliers providing between 10 and 15 percent of our average daily contract volumes. Firm year-round supply contracts have
remaining terms ranging from one to six years. All term gas supply contracts use price formulas tied to monthly index prices. We
hedge a majority of these contracts each year using financial instruments as part of our gas purchasing strategy (see “Managing the
Cost of Gas,” above).
In addition to the year-round contracts, we continue to contract in advance for firm gas supplies to be delivered only
during the winter heating season primarily under short-term contracts. During 2008, new short-term purchase agreements were
entered into with nine suppliers. These agreements have a variety of pricing structures and provide for a total of up to 1.5 million
therms per day during the 2008-2009 heating season. We intend to enter into new purchase agreements in 2009 for equivalent
volumes of gas with existing or new suppliers, as needed, to replace contracts that will expire during 2009.
We also buy gas on the spot market as needed to meet core utility customer demand. We have flexibility under the terms
of some of our firm supply contracts enabling us to purchase spot gas in lieu of firm contract volumes, thereby allowing us to take
advantage of favorable pricing on the spot market from time to time.
We continue to purchase a small amount of gas from a non-affiliated producer in the Mist gas field in Oregon. The
production area is situated near our underground gas storage facility. Current production is approximately 19,000 therms per day
from about 17 wells, supplying less than 1 percent of our total annual purchase requirements. Production from these wells varies as
existing wells are depleted and new wells are drilled.
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Core Utility Market Peaking Supply and Storage
We supplement our firm gas supplies with gas from storage facilities we own or that are contractually committed to us.
Gas is generally purchased and stored during periods of low demand for use at a later time during periods of peak demand. In
addition to enabling us to meet our peak demand, these facilities make it possible to lower the annual average cost of gas by
allowing us to minimize our pipeline transportation contract demand costs and to purchase gas for storage during the summer
months when gas prices are generally lower.
Underground storage. We provide daily and seasonal peaking gas supplies to our Oregon core utility customers from
our underground gas storage facility in the Mist gas storage field. Including the latest expansions in 2008, this facility has a maximum
daily deliverability of 5.1 million therms and a total working gas capacity of about 16 Bcf. In 2004, we completed our South Mist
pipeline extension project, which is a utility transmission pipeline from our Mist gas storage field to growing portions of our
distribution service area. In May 2008, a total of 100,000 therms per day of Mist storage capacity that had previously been
available for storage services was recalled and committed to use for core utility customers. This is the first recalled capacity since
2004. Under our regulatory agreement with the OPUC, storage capacity that has been developed and used by the gas storage
segment can be recalled as needed and transferred to utility rate base at our original cost less accumulated depreciation, with a
corresponding rate increase to customers to reflect the cost of service. The core utility market now has 2.4 million therms per day
of deliverability and approximately 9 Bcf of working gas committed from the Mist storage facility. As storage capacity is recalled to
serve core utility customers, we may be able to develop new storage capacity to replace it and continue serving interstate
customers.
We also have contracts with The Williams Companies’ Northwest Pipeline (Northwest Pipeline) for firm gas storage
services from an underground storage facility at Jackson Prairie near Chehalis, Washington, and an LNG facility at Plymouth,
Washington. Together, these two facilities provide us with daily firm deliverability of about 1.1 million therms and total seasonal
capacity of about 16 million therms. Separate contracts with Northwest Pipeline provide for the transportation of these storage
supplies to our service territory. All of these contracts have reached the end of their primary terms, but we have exercised our
renewal rights that allow for annual extensions at our option.
Company-owned LNG. We own and operate two LNG storage facilities in our Oregon service territory that liquefy gas
for storage during the summer months so that it is available for withdrawal during the peak winter heating season. These two
facilities provide a maximum combined daily deliverability of 1.8 million therms and a total seasonal capacity of 17 million therms.
Recallable capacity from transportation customers. We also have contracts with one electric generator and two
industrial customers that together provide an additional 52,000 therms per day of year-round upstream capacity, plus 390,000
therms per day of recallable capacity and supply. The contracts for 52,000 therms per day of year-round capacity expire in July
2009. Two of the three recallable capacity/supply contracts are renewed on a year-to-year basis, while the third expires in 2010 at
which time we would expect to renew annually.
Transportation
Single transportation pipeline. Our distribution system is directly connected to a single interstate pipeline, Northwest
Pipeline. Although we are dependent on a single pipeline, the pipeline’s
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gas flows are bi-directional and it transports gas into the Portland metropolitan market from two directions: (1) the north, which
brings supplies from British Columbia and Alberta supply basins; and (2) the east, which brings supplies from Alberta as well as the
U.S. Rocky Mountain supply basins. In 2003 a federal order requiring Northwest Pipeline to replace its 26-inch mainline from the
Canadian border to our service territory underscored the need for pipeline transportation diversity. That replacement project was
completed by Northwest Pipeline in November 2006. We are pursuing options to further diversify our pipeline transportation
paths. Specifically, we are currently developing plans to build a pipeline project (Palomar) that would connect TransCanada
Pipelines Limited’s (TransCanada) Gas Transmission Northwest (GTN) interstate transmission line to our gas distribution system.
In August 2007, we entered into an agreement with GTN for the purpose of jointly developing, owning and operating this
proposed pipeline. Additionally, we entered into precedent agreements to become a shipper on the Palomar Pipeline. If
constructed, this pipeline would provide an alternate transportation path for gas purchases from Alberta that currently move through
the Northwest Pipeline system (See Part II, Item 7., “2009 Outlook”).
Rates. FERC establishes rates for interstate pipeline transportation service under long-term transportation agreements
within the U.S., and Canadian federal or provincial authorities establish rates for service under agreements with the Canadian
pipelines over which we ship gas.
Transportation agreements. The largest of our transportation agreements with Northwest Pipeline extends through
September 2013 and provides for firm transportation capacity of up to 2.1 million therms per day. This agreement provides access
to natural gas supplies in British Columbia and the U.S. Rocky Mountains.
Our second largest transportation agreement with Northwest Pipeline extends through November 2011. It provides up to
1.0 million therms per day of firm transportation capacity from the point of interconnection of the Northwest Pipeline and GTN
systems in eastern Oregon to our service territory. GTN’s pipeline runs from the U.S./Canadian border through northern Idaho,
southeastern Washington and central Oregon to the California/Oregon border. We have firm long-term capacity on GTN’s pipeline
and two upstream pipelines in Canada, which match the amount of Northwest Pipeline capacity northward into Alberta, Canada.
We also have an agreement with Northwest Pipeline that previously extended into 2009 for approximately 350,000
therms per day of firm transportation capacity from the U.S. Rocky Mountain region. In February 2008, we extended the term of
this contract through 2044. Also in February 2008, we executed an agreement with a third party to take assignment of their firm
gas supply transportation contract starting no earlier than 2012 nor later than 2017, with the term extending through 2046. This
contract consists of 120,000 therms per day on Northwest Pipeline from the U.S. Rocky Mountain region.
In addition, we have firm long-term pipeline transportation contracts with two other major transporters located in Canada.
One contract extends through October 2014 and provides approximately 600,000 therms per day of firm gas transportation from
Station 2 in northern British Columbia to the Huntingdon/Sumas connection with Northwest Pipeline at the U.S./Canadian border.
Another contract extends through October 2020 and provides approximately 470,000 therms per day of firm gas transportation
from southeastern British Columbia to the same Huntingdon/Sumas connection with Northwest Pipeline. Our capacity on this
second contract is matched with companion contracts for pipeline capacity on the TransCanada BC system and NOVA system in
British Columbia and Alberta, allowing purchases to be made from the gas fields of Alberta, Canada.
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Integrated Resource Plan
The OPUC and WUTC have implemented IRP processes under which utilities develop plans defining alternative growth
scenarios and resource acquisition strategies. Elements of these plans include:
•
•
•
•
an evaluation of supply and demand resources;
the consideration of uncertainties in the planning process and the need for flexibility to respond to changes;
a primary goal of “least cost” service; and
consistency with state energy policy.
We filed our 2008 IRP with the OPUC and an update to our 2007 IRP with the WUTC in April 2008. In October 2008,
we received notification from the WUTC that our 2007 IRP met the requirements of the Washington Administrative Code. In
January 2009, the OPUC acknowledged our 2008 IRP. Although OPUC acknowledgment of the IRP does not constitute
ratemaking approval of any specific resource acquisition strategy or expenditure, the OPUC generally indicates that it would give
considerable weight in prudency reviews to utility actions that are consistent with acknowledged plans. The WUTC has indicated
that the IRP process is one factor it will consider in a prudency review.
Competition and Marketing
Competition with Other Energy Products
We have no direct competition in our service area from other natural gas distributors. However, for residential customers,
we compete primarily with electricity, fuel oil and propane. We also compete with electricity and fuel oil for commercial
applications. In the industrial market, we compete with all forms of energy, including competition from third-party sellers of natural
gas commodity. Competition among gas suppliers is based on price, perceived environmental impact, sustainability, reliability,
efficiency and performance, market conditions, technology and legislative policy. Whether or not we provide the gas supplies to
serve our transportation-eligible customers, our net margins are not materially affected because we generally do not make any
margin on the commodity sales to our utility customers (see “Industrial Markets,” below).
Residential and Commercial Markets
The relatively low market saturation of natural gas in residential single-family dwellings in our service territory, estimated at
approximately 50 percent, and our operating convenience and environmental advantage over fuel oil, provides the potential for
continuing growth from residential and commercial conversions. In 2008, 9,609 net new residential customers were added,
primarily from single- and multi-family new construction, but also from the conversion of existing homes from oil, electric or
propane appliances to natural gas. The net increase of all new customers added in 2008 was 10,329. This represents a 12-month
growth rate of 1.6 percent, which is above the national average for local gas distribution companies as reported by the American
Gas Association. On an annual basis, residential and commercial customers typically account for about 55 percent of our utility’s
total volumes delivered and about 85 percent of gross operating revenues, while industrial customers account for about 45 percent
of volumes and about 13 percent of gross revenues. The remaining 2% of gross operating revenues is derived from miscellaneous
services and other regulatory charges.
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Industrial Markets
Competition to serve the industrial and large commercial market in the Pacific Northwest has been relatively unchanged
since the early 1990s in terms of numbers and types of competitors. Competitors consist of gas marketers, oil/propane sellers and
electric utilities.
Industrial customers we serve include: pulp, paper and other forest products; the manufacture of electronic,
electrochemical and electrometallurgical products; the processing of farm and food products; the production of various mineral
products; metal fabrication and casting; the production of machine tools, machinery and textiles; the manufacture of asphalt,
concrete and rubber; printing and publishing; nurseries; government and educational institutions; and electric generation. No
individual customer or industry group accounts for a significant portion of our revenues or margins.
The OPUC and WUTC have approved transportation tariffs under which we may contract with customers to deliver
customer-owned gas. Transportation tariffs available to industrial customers are priced at our sales service rate less the commodity
cost included in that rate. Therefore, we are unaffected financially if industrial customers buy commodity supplies directly from
marketers rather than purchasing gas from us, as long as they remain on a tariff or contract with the same quality of service. We do
not generally make any margin on the sale of the gas commodity. However, industrial customers may select between firm and
interruptible service, among other levels of service, and these choices can positively or negatively affect margin. The relative level
and volatility of prices in the natural gas commodity markets, along with the availability of pipeline capacity to ship customer-owned
gas, are among the primary factors that have caused some industrial customers to alternate between sales and transportation
service or between higher and lower levels of service.
We redesigned our industrial rates in Oregon and Washington as part of our general rate cases in 2003 and 2004,
respectively, in order to better reflect relative costs of service and to become more competitive in the industrial market. In August
2006, the OPUC and WUTC approved tariff changes to the service options for our industrial accounts. The changes set out
additional parameters that give us more certainty in the level of gas supplies we will need to purchase in order to serve this
customer group. The parameters include an annual election cycle period, special pricing provisions for out-of-cycle changes and the
requirement that customers on our annual weighted average cost of gas tariff complete the agreed upon term of their service. In the
case of customers switching out-of-cycle from transportation to sales service, the customer will be charged the cost of incremental
gas supply under our regulatory tariff.
We have negotiated special transportation service agreements with several of our largest industrial customers. These
special agreements are designed to provide transportation rates that are competitive with the customer’s alternative capital and
operating costs of installing direct connections to Northwest Pipeline’s interstate pipeline system, which would allow them to
bypass our gas distribution system. These agreements generally prohibit bypass during their terms. Due to the cost pressures that
confront a number of our largest customers competing in global markets, bypass continues to be a competitive threat. Although we
do not expect a significant number of our large customers to bypass our system in the foreseeable future, we may experience
further deterioration of margin associated with customers transferring to special contracts where pricing is specifically designed to
be competitive with their bypass alternative.
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Gas Storage
Our gas storage business segment includes natural gas storage services provided to interstate and intrastate customers in
the Pacific Northwest using underground gas storage and pipeline facilities we own and operate. We also use an independent
energy marketing company to provide asset optimization services for the utility under a contractual arrangement, the results of
which are included in this business segment.
Currently, 3 percent of our consolidated assets and 12 percent of our consolidated net income in 2008 are related to the
gas storage business segment. For each of the years ended December 31, 2008, 2007, and 2006, this business segment derived a
majority of its revenues from multi-year contracts with less than 10 customers taking service at our Mist storage facility. The total
working gas capacity at our Mist gas storage facility is approximately 16 Bcf. Of this capacity, approximately 9 Bcf, or 56 percent
of storage capacity, is currently used by our utility, and the remaining 7 Bcf, or 44 percent, is committed to gas storage customers
primarily under firm storage contracts. See Note 2 for more information on total assets and results of operations for the years
ended December 31, 2008, 2007 and 2006.
Pre-tax income from gas storage at Mist and third-party optimization services using our utility’s storage or transportation
capacity is subject to revenue sharing with core utility customers. In Oregon, 80 percent of the pre-tax income is retained by the
gas storage segment when the costs of the capacity used have not been included in utility rates, or 33 percent of the pre-tax income
is retained when the capacity costs have been included in utility rates. The remaining 20 percent and 67 percent of pre-tax income
in each case are credited to a deferred regulatory account for refund to our core utility customers. We have a similar sharing
mechanism in Washington for pre-tax income derived from gas storage services and third-party optimization activities.
We are currently in the process of developing a second underground gas storage facility and related pipeline in the Fresno,
California area. This project is expected to serve the California market. We plan to move ahead with construction later this year,
subject to market conditions and our ability to obtain regulatory approvals (see “Gill Ranch,” below).
Seasonality of business. Generally, gas storage revenues do not follow seasonal patterns similar to those experienced
by the utility because rates for firm storage contracts are in the form of fixed monthly reservation charges and are not affected by
customer usage. However, there is some seasonal variation from the optimization of excess utility storage and related transportation
capacity. Excess capacity is usually available during the spring and summer months when the demand for gas by utility customers is
low.
Customers. Our gas storage business segment generally enters into contracts with customers for firm storage capacity for
terms ranging from one to 10 years. Currently, our revenues are primarily derived from a few large storage customers who provide
energy related services, including natural gas distribution, electric generation and energy marketing companies. Five storage
customers currently contracted account for over 90 percent of our existing gas storage capacity, with the largest customer
accounting for about half of total capacity. These five customers have contracts that expire at various dates between April 2009
through March 2015, with the largest customer’s contract expiring in March 2015.
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Competitive conditions. Our existing gas storage facility faces limited competition from other west coast storage
projects primarily because of its geographic location. In the future, we could face increased competition from new or expanded
natural gas storage facilities as well as from natural gas pipelines and marketers.
Interstate gas storage. This part of the business segment currently provides firm and interruptible gas storage services at
Mist with related transportation services on the utility’s system to and from Mist to interstate pipeline interconnections. The
interstate storage services, and maximum rates for these services, are authorized by the FERC. The storage capacity used by this
business segment has been developed as a non-utility investment by NW Natural in advance of core utility customers’
requirements.
Intrastate gas storage. We provide intrastate gas storage services under an OPUC-approved rate schedule that
includes service and site-specific qualifications. The firm storage service terms and conditions mirror the firm interstate storage
service regulated by FERC, except that these customers are located and served in Oregon.
Gill Ranch. In September 2007, we announced a joint project with Pacific Gas & Electric Company (PG&E) to
develop a new underground natural gas storage facility at Gill Ranch near Fresno, California (Gill Ranch). We formed a whollyowned subsidiary of NW Natural to develop and operate the facility, Gill Ranch Storage, LLC. Our subsidiary will initially own 75
percent of the project, and PG&E will own 25 percent. The initial development of this new storage facility is expected to provide
approximately 20 Bcf of underground gas storage capacity and will include approximately 27 miles of transmission pipeline when
the initial phase is completed. We estimate our 75 percent share of the total project cost for the initial phase of development, which
began in 2008 and is expected to continue through 2010, to be between $160 million and $180 million. In July 2008, Gill Ranch
filed an application with the California Public Utilities Commission (CPUC) for a Certificate of Public Convenience and Necessity.
If granted, Gill Ranch will be subject to CPUC regulation with respect to rates and will require regulatory approvals for certain
activities, including but not limited to securities issuance, terms of services, systems of accounts, lien grants and sales of property.
We expect the initial phase of Gill Ranch to be in-service by late 2010.
Other
We have non-utility investments and other business activities which are aggregated and reported as a business segment
called “Other.” Although in the aggregate these investments and activities are not material, we identify and report them as a standalone segment based on our current organization structure and decision-making process and because these business investments
and activities are not specifically related to our utility or gas storage segments. This segment primarily consists of an equity method
investment in a joint venture to build and operate an interstate gas transmission pipeline in Oregon (see Part II, Item 7., “2009
Outlook—Strategic Opportunities—Pipeline Diversification,” below) and pipeline assets in NNG Financial Corporation, as well as
some operating and non-operating expenses of the parent company that cannot be charged to utility operations. Until recently, this
segment also had equity investments in several windpower and solar electric generating projects in California and a Boeing 737
aircraft leased to a commercial airline. The aircraft investment was sold in April 2008, and the windpower and solar investments
were sold in years prior to 2008. Approximately 1 percent of our consolidated assets and about 3 percent of 2008 consolidated
net income are related to activities in the “Other” business segment. See Note 2 for more information on total assets and results of
operations for the three years ended December 31, 2008.
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Regulation and Rates
We are subject to regulation with respect to, among other matters, rates, terms of services, and systems of accounts
established by the OPUC, the WUTC and the FERC. The OPUC and WUTC also regulate our issuance of securities.
Approximately 90 percent of our utility operating revenues are derived from Oregon customers, and the balance is derived from
Washington customers.
We periodically file general rate case and rate tariff requests with the OPUC, WUTC and FERC to change the rates we
charge our utility and storage customers. With certain exceptions, our most recent agreement with the OPUC precludes us from
filing a general rate case request before September 2011, but does not preclude us from filing other types of rate adjustment
requests. In 2008, we filed a general rate case in Washington that was approved on December 26, 2008 with the resulting changes
to rates effective on January 1, 2009 (see Part II, Item 7., “Results of Operations—Regulatory Matters—General Rate Cases,”
below). We are required under our Mist interstate storage certificate authority and rate approval orders to file every three years
either a petition for rate approval or a cost and revenue study to change or justify maintaining the existing rates for the interstate
storage service. In the future, we may be subject to regulation in other states, such as California, resulting from our strategic
investments such as Gill Ranch. For further information, see Part II, Item 7., “Results of Operations—Regulatory Matters,” and
“Gas Storage—Gill Ranch,” above.
Environmental Issues
Properties and Facilities
We have properties and facilities that are subject to federal, state and local laws and regulations related to environmental
matters. These laws and regulations may require expenditures over a long timeframe to control environmental effects. Estimates of
liabilities for environmental response costs are difficult to determine with precision because of the various factors that can affect
their ultimate disposition. These factors include, but are not limited to, the following:
•
•
•
•
•
•
•
the complexity of the site;
changes in environmental laws and regulations at the federal, state and local levels;
the number of regulatory agencies or other parties involved;
new technology that renders previous technology obsolete, or experience with existing technology that proves
ineffective;
the ultimate selection of a particular technology;
the level of remediation required; and
variations between the estimated and actual period of time that must be dedicated to respond to an environmentallycontaminated site.
We own, or previously owned, properties currently being investigated that may require environmental response, including:
a property in Multnomah County, Oregon that is the site of a former gas manufacturing plant that was closed in 1956 (Gasco site);
a property adjacent to the Gasco site that is now the location of a manufacturing plant owned by Siltronic Corporation (Siltronic
site); an area adjacent to the Gasco and the Siltronic sites in the Willamette River that has been listed by the U.S. Environmental
Protection Agency as a Superfund site for which we have been identified as one of a number of potentially responsible parties
(Portland Harbor site); the former location of a gas manufacturing plant operated by our predecessor that is outside the geographic
scope of the current Portland Harbor site (Front Street site); and the former site of three manufactured gas tanks (Central
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Service Center site). Based on our current assessment of regulatory and insurance recovery of environmental costs, we do not
expect that the ultimate resolution of these matters will have a material adverse effect on our financial condition, results of
operations or cash flows; however, if it is determined that both the insurance recovery and future rate recovery of such costs are
not probable, then the costs not expected to be recovered will be charged to expense in the period such determination is made and
could have a material impact on our financial condition or results of operations. See Note 12, for a further discussion of potential
environmental responses, related costs and regulatory and insurance recovery.
Future Environmental Issues
We recognize that our business is likely to face future carbon constraints. A variety of legislative and regulatory measures
to address greenhouse gas emissions are in various phases of discussion or implementation. These include the proposed
international standards, proposed federal legislation and proposed or enacted state actions to develop statewide or regional
programs, each of which have imposed or would impose measures to achieve reductions in greenhouse gas emissions. The
outcome of federal and state climate change initiatives cannot be determined at this time, but these initiatives could produce a
number of results including potential new regulations, additional charges to fund energy efficiency activities, or other regulatory
actions. These actions could result in increased costs associated with operating and maintaining our facilities, could increase other
costs to our business and could impact the prices we charge our customers. Because natural gas is a fossil fuel with low carbon
content, it is possible that future carbon constraints could create additional demand for natural gas, both for electric production and
direct use in homes and businesses.
We continue to take steps to address future greenhouse gas emission issues, including actively participating in policy
development through the Oregon Governor’s Task Force on Climate Change and leading efforts within the American Gas
Association to promote the enactment of fair federal climate change legislation. In 2008, our current President and CEO was
appointed to the newly formed Oregon Global Warming Commission. We continue to engage in policy development and in
identifying ways to reduce greenhouse gas emissions associated with our operations and our customers’ gas use, including the
introduction of the Smart Energy program, which allows customers to contribute funds to projects that offset greenhouse gases
produced from their natural gas use.
Employees
At December 31, 2008, our workforce consisted of 717 members of the Office and Professional Employees International
Union (OPEIU), Local No. 11, AFL-CIO, and approximately 400 management level and other non-bargaining employees. Our
labor agreement (Joint Accord) with members of OPEIU that covers wages, benefits and working conditions extends to May 31,
2009, and thereafter from year to year unless either party serves notice of its intent to negotiate modifications to the collective
bargaining agreement. Each party has served notice of intent to negotiate the terms of an agreement prior to the May 31, 2009
expiration date.
Additions to Infrastructure
We expect to make a significant level of capital expenditures for additions to utility and storage infrastructure over the next
five years, reflecting continued investments in customer growth, technology, distribution system enhancements and the development
of additional gas storage facilities. In 2009, utility capital expenditures are estimated to be between $100 and $110 million, and
non-utility
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capital investments are estimated to be between $50 and $70 million for business development projects that are currently in
process. For the years 2009-2013, capital expenditures for the utility are estimated to be between $450 and $500 million, while
the amount for business development investments after 2009 will depend largely on future decisions about potential opportunities in
gas storage and pipeline projects.
Available Information
We file annual, quarterly and special reports and other information with the Securities and Exchange Commission (SEC).
Reports, proxy statements and other information filed by us can be read and copied at the public reference room of the SEC, 100
F Street, N.E., Washington, D.C. 20549. You can obtain additional information about the Public Reference Room by calling the
SEC at 1-800-SEC-0330. The SEC also maintains a website (http://www.sec.gov) that contains reports, proxy statements and
other information that we file electronically. In addition, we make available on our website (http://www.nwnatural.com), our annual
report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports, as well
as proxy materials, filed or furnished pursuant to Section 13(a) or 15(d) and Section 14 of the Securities Exchange Act of 1934, as
amended (Exchange Act), as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC.
We have adopted a Code of Ethics for all employees and a Financial Code of Ethics that applies to senior financial
employees, both of which are available on our website. We intend to disclose amendments to, and any waivers from, such codes of
ethics on our website. Our Corporate Governance Standards, Director Independence Standards, charters of each of the
committees of the Board of Directors and additional information about us are also available on 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.
Our Chief Executive Officer certified to the New York Stock Exchange (NYSE) on May 23, 2008 that, as of that date,
he was not aware of any violation by the company of the NYSE’s corporate governance listing standards, and that we had filed
with the SEC, as Exhibits 31.1 and 31.2 to our Annual Report on Form 10-K for the year ended December 31, 2007, the
certificates of the Chief Executive Officer and the Chief Financial Officer certifying the quality of NW Natural’s internal control over
financial reporting and public disclosures. For the year-ended December 31, 2008, the certificates of the Chief Executive Officer
and the Chief Financial Officer are filed with this report as Exhibits 31.1 and 31.2.
ITEM 1A. RISK FACTORS
Our business and financial results are subject to a number of risks and uncertainties. When considering any investment in
our securities, investors should consider the following information, as well as information contained in the caption “Forward
Looking Statements,” and other documents we file with the SEC. This list is not exhaustive and our management places no priority
or likelihood based on their order of presentation.
Economic risk. Changes in the economy and in the financial markets may have a negative impact on our
financial condition and results of operations.
The global credit and financial markets have been experiencing significant disruption and volatility in recent months. At the
same time the U.S. economy has slowed, unemployment rates are
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rising, and there has been an increase in mortgage defaults and a decrease in the value of homes and investment assets, which has
adversely affected the income and financial resources of many domestic households. It is unclear whether the federal responses to
these conditions will lessen the severity or duration of this economic downturn. Our operations are affected by these economic
conditions. Less new housing construction, fewer conversions to natural gas, higher levels of residential foreclosures and vacancies,
and personal and business bankruptcies or reduced spending could all result in a decline in energy consumption and customer
growth and have a negative effect on our financial condition and results of operations.
Regulatory risk. Regulation of our business, including changes in the regulatory environment in general, and
failure of regulatory authorities to approve rates which provide for timely recovery of our costs and an adequate return
on invested capital in particular, may adversely impact our financial condition and results of operations.
The OPUC and WUTC have general regulatory authority over our utility business in Oregon and Washington,
respectively, including rates and charges, the issuance of securities, services and facilities, terms of customer services, system of
accounts, investments, safety standards, transactions with affiliated interests and other matters. In addition, FERC has regulatory
authority over our interstate gas storage services, and the CPUC will have regulatory authority over our Gill Ranch gas storage
development and operations.
The rates we charge to customers must be approved by the applicable regulatory agencies. Our rates are generally
designed to allow us to recover the costs of providing such services and to earn an adequate return on our capital investment.
However, we expect the rates charged to customers of Gill Ranch for gas storage services will be based on what customers are
willing to pay (i.e. market-based rates) rather than on our recovery of costs plus a return on our investment. We expect to continue
to make expenditures to expand, improve and operate our distribution and storage systems. Regulators can deny recovery of
expenditures we make if they find that such expenditures were not prudently incurred according to their regulatory standards.
In addition, in the normal course of our business we may place assets in service or incur higher 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.
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.
In recent years, we have seen a significant increase in the volatility of natural gas commodity prices, primarily due to shifts
in the balance of supply and demand. Early in 2008, we saw natural gas prices rise to record high levels as demand grew,
especially for new electric power generation, which was outpacing North American gas production. Then during the second half of
2008, the price of natural gas fell significantly as our national economy fell into a recession and demand for natural gas declined
while North American gas production increased. There are a number of external factors that affect the balance of natural gas supply
and demand, including the level of gas imports, regional accessibility to gas supplies, supply disruptions, changes in the global
energy markets, the availability of pipeline capacity to transport natural gas from region to region and changes in general economic
conditions. The cost we pay for natural gas is generally passed through to our customers through an
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annual PGA rate adjustment in Oregon and Washington (see below). Significant increases in the commodity price of natural gas
raises the cost of energy to our existing customers, thereby causing those customers to conserve or potentially switch to alternate
sources of energy. Significant price increases could also cause new home builders and commercial developers to select heating
systems other than natural gas. Decreases in the volume of gas we sell could reduce our earnings in the absence of decoupled rate
structures, and a decline in customers could slow growth in our future earnings.
Higher gas prices may also cause us to experience an increase in short-term debt and temporarily reduce liquidity because
we pay suppliers for gas when it is purchased, which can be materially in advance of when these costs are recovered through rates.
Significant increases in the price of gas can also slow our collection efforts as customers experience increased difficulty in paying
their higher energy bills, leading to higher than normal delinquent accounts receivable. This could contribute to higher short-term
debt levels, greater expense associated with collection efforts and increased bad debt expense.
In Oregon and Washington, our utility has PGA tariffs which provide for annual revisions in rates resulting from changes in
the cost of purchased gas including the expected impact on bad debt expense. In Oregon, we also have a price-elasticity
adjustment that adjusts rates through the annual PGA for expected increases or decreases in customer usage due to higher or lower
gas prices. The Oregon PGA tariff also provides an incentive to the Company to achieve lower gas costs such that a percentage,
set annually, of any difference between the actual purchased gas costs and the actual recoveries of gas costs in rates be recognized
as current income or expense (see Part II, Item 7., “Results of Operations—Regulatory Matters—Rate Mechanisms”).
Accordingly, higher gas costs than those assumed in setting rates can adversely affect our operating cash flows, liquidity and results
of operations, until such costs are recovered from customers. 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.
Inability to access capital market risk. Our inability to access capital or significant increases in the cost of
capital could adversely affect our business.
Our ability to obtain adequate and cost effective short-term and long-term financing depends on our credit ratings as well
as the liquidity and stability of financial markets. Our businesses rely on access to capital markets, including the commercial paper
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. A negative change in our ratings by credit rating agencies could adversely affect
our financing cost, liquidity and access to capital. Additionally, downgrades in our current credit ratings below investment-grade
could cause additional delays in accessing the credit markets by the utility while we seek supplemental regulatory approval from the
OPUC. Disruptions in the capital and credit markets could also adversely affect our ability to access short-term and long-term
capital. 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. Longer 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 may negatively impact our ability to run the business and make strategic
investments.
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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.
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 and other financial market risks. We attempt to manage these exposures and mitigate our risks
through enforcement of established risk limits and risk management procedures, including hedging activities that are in accordance
with our derivatives policies. These risk limits and risk management procedures may not always work as planned and cannot
entirely eliminate the risks associated with hedging. Additionally, our hedging activities may cause us to incur additional expenses
which could result in a material adverse effect on our operating revenues, costs, derivative assets and liabilities, and operating cash
flows.
We cannot and do not hedge our entire interest rate or commodity cost exposure, and the unhedged exposure will vary
over time. Gains or losses experienced through hedging activities, including carrying costs, generally flow through the PGA
mechanism or are recovered in future general rate cases, thereby limiting our exposure to earnings volatility on a year-to-year basis.
However, the hedge transactions we enter into for the utility are subject to a prudency review by the OPUC and WUTC, and, if
deemed imprudent, those expenses may be disallowed, which could have a material adverse effect on our operating revenues,
costs, derivative assets and liabilities, and operating cash flows. In addition, actual business requirements and available resources
may vary from forecasts, which are used as the basis for our hedging decisions, and could cause our exposure to be more or less
hedged than we anticipated. Additionally, if our derivative instruments and hedging transactions do not qualify for hedge accounting
under Statement of Financial Accounting Standards (SFAS) No. 133, “Accounting for Derivative Instruments and Hedging
Activities,” our hedges may not be effective and our results of operations, cash flows and financial condition could be adversely
affected.
We also have credit related exposure to financial derivative counterparties. In general, we require our counterparties to
have a high level investment-grade credit rating at the time the derivative instrument is entered into, and we specify limits on the
contract amount and duration based on each counterparty’s credit rating. Nevertheless, counterparties owing us money or physical
natural gas commodities could breach their obligations. Should the counterparties to these arrangements fail to perform, we may be
forced to enter into alternative arrangements. In that event, our financial results could be adversely affected. Although our valuations
take into account the expected probability of default by counterparties, an actual default by a particular counterparty could have a
greater impact than we estimated. Additionally, under most of our hedging arrangements, any downgrade of our senior secured
long-term debt credit rating below investment grade 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 draws from our
borrowing facilities.
Customer growth risk. Our results of operations may be negatively affected if we are unable to sustain customer
growth rates in our local gas distribution business.
Our 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. Should there be continued weakness in the new housing market, a slowdown
in the conversion market or declining use of natural gas by our residential and commercial customer base, there could be an
adverse long-term impact on our utility margin, earnings and cash flows.
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Risk of competition. Our gas distribution and storage businesses are subject to increased competition which
could negatively affect our results of operations.
In the residential market, our gas distribution business competes primarily with suppliers of electricity, fuel oil and propane.
We also compete with suppliers of electricity and fuel oil for commercial applications. In the industrial market, we compete with all
forms of energy suppliers. Competition among these forms of energy is based on price, reliability, efficiency and performance.
Higher natural gas prices have at times eroded, or in some cases eliminated, the competitive price advantage of natural gas
over other energy sources. Also, technological improvements in other energy sources could erode our competitive advantage. If
natural gas prices continue to rise relative to other energy sources, it may negatively affect our ability to attract new customers, and
our residential, commercial and industrial customers may use alternative sources of energy or bypass our systems in favor of
contracts with lower per-unit costs, which could have a negative impact on our customer growth rate and results of operations.
Additionally, our existing gas storage segment currently faces limited competition from other west coast storage projects
primarily because of its geographic location. In the future, we could face increased competition from new or expanded natural gas
storage facilities, interstate pipelines and gas marketers seeking to provide or arrange transportation, storage and other services for
customers.
Reliance on third parties to supply natural gas risk. We rely on third parties to supply all of the natural gas we
store and deliver, and limitations on our ability to obtain supplies could have a material impact on our financial results.
Our ability to provide natural gas for current and future sales depends upon our ability to obtain and deliver supplies of
natural gas, as well as our ability to acquire supplies directly from new sources. Certain factors including the following may affect
our ability to acquire and deliver natural gas to our current and future customers: suppliers or other third parties’ control over the
drilling of new wells and facilities to transport natural gas to our distribution system; competition for the acquisition of natural gas;
priority allocations on transmission pipelines; impact of severe weather disruptions to natural gas supplies such as occurred with
Hurricane Katrina in 2005; the regulatory and pricing policies of federal, state and local government agencies; and the availability of
Canadian reserves for export to the United States. If we are unable to obtain or are limited in our ability to obtain natural gas from
our current suppliers or new sources, our financial results could be materially impacted.
Single transportation pipeline risk. We rely on a single pipeline company for the transportation of gas to our
service territory, a disruption of which could adversely impact our ability to meet our customers’ gas requirements.
Our distribution system is directly connected to a single interstate pipeline, Northwest Pipeline. The pipeline’s gas flows
are bi-directional and it transports gas into the Portland metropolitan market from two directions: (1) the north, which brings
supplies from 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. Our results of operations may be negatively impacted if there is a rupture in the pipeline and we
incur costs associated with actions taken to mitigate service disruptions.
Business development risk. The development, construction, startup and operation of our business development
projects may involve unanticipated changes or delays that could negatively impact our costs as well as our financial
condition, results of operations and cash flows.
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Business development projects involve many risks. We are in the early development stages on two strategic business
development projects: the Gill Ranch gas storage facility in California, and the Palomar gas transmission pipeline in Oregon. We
may also engage in other business development projects in the future. With respect to these projects, we may not be able to obtain
required governmental permits and approvals, or financing, to complete our projects in a cost-efficient or timely manner. If we do
not obtain the necessary regulatory approvals in a timely manner, development projects may be delayed or abandoned. There also
may be startup and construction delays, construction cost overruns, inability to negotiate acceptable agreements such as rights-ofway, easements, construction, gas supply or other material contracts, changes in market prices; and operating cost increases.
Additionally, natural gas storage and gas transportation markets are intensely competitive, both within the natural gas industry and
with alternative sources of energy. To complete our business development projects, we will need to secure financing from willing
lenders at reasonable interest rates. If the current tight credit markets persist or become more inaccessible, we may be unable to
acquire the necessary financing to fund our business development projects at acceptable interest rates within a timeframe favorable
for completing the project. Similarly, an inability to obtain the necessary state permits, secure acceptable financing, or arrange for
sufficient supplier commitments, could impact the viability of an LNG terminal on the Columbia river and may mean that we would
not proceed with the western portion of Palomar. One or more of these events may mean that our equity investments could
become impaired and such impairment could have an adverse effect on our financial condition, results of operations and cash flows.
Joint partner risk. Investing in business development projects through partnerships, joint ventures or other
business arrangements decreases our ability to manage certain risks.
We use joint ventures and other business arrangements to manage and diversify the risks of certain non-utility
development projects, including Palomar and Gill Ranch, and we may acquire interests in other similar types of projects in the
future. Under these types of business arrangements, we may not be able to fully direct the management and policies of the business
relationships, and other participants in those relationships may take action contrary to our interests. In addition, other participants
may withdraw from the project, become financially distressed or bankrupt, or have economic or other business interests or goals
that are inconsistent with ours. Although we have contractual and other legal remedies to enforce our interests, if a participant in
one of these business arrangements acts contrary to our interests, it could adversely impact our financial condition, results of
operations and cash flows.
Environmental risk. Certain of our properties and facilities may pose environmental risks requiring remediation,
the cost of which could adversely affect our results of operations, financial condition and cash flows.
We own, or previously owned, properties that require environmental remediation or other action. We accrue all material
loss contingencies relating to these properties, but our results of operations may be adversely affected to the extent that estimates of
the probable costs increase significantly as additional information becomes available and to the extent we are not able to recover
the incremental cost from insurance or through customer rates. A regulatory asset has already been recorded for some of these
estimated costs pursuant to a deferral order from the OPUC. To the extent we are unable to recover these deferred costs in rates
or through insurance, we would be required to reduce our regulatory asset which could adversely affect our results of operations
and financial condition. In addition, disputes may arise between potentially responsible parties and regulators as to
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the severity of particular environmental matters and what remediation efforts are appropriate. These disputes could lead to
adversarial administrative proceedings or litigation, with uncertain outcomes.
We cannot predict with certainty the amount or timing of future expenditures related to environmental investigation and
remediation that may be required because of the difficulty of estimating such costs. There is also uncertainty in quantifying liabilities
under environmental laws that impose joint and several liability on all potentially responsible parties. There are also no assurances
that existing environmental regulations will not be revised or that new stricter regulations seeking to protect the environment will not
be adopted or become applicable to us. Revised environmental regulations which result in increased compliance costs or additional
operating restrictions could have an adverse effect on our results of operations, particularly if those costs are not fully recoverable
from customers.
Global climate change legislation risk. Management expects that future legislation may impose carbon
constraints to address global climate change exposing us to regulatory and financial risk.
There are a number of new federal and state legislative and regulatory initiatives being proposed and adopted in an
attempt to control or limit the effects of global warming and overall climate change, including greenhouse gas emissions such as
carbon dioxide. The outcome of federal and state actions to address climate change could result in a variety of regulatory programs
including potential new regulations, additional requirements to fund energy efficiency activities, or other regulatory actions. These
actions could result in increased compliance and other costs, additional operating restrictions, and could impact the prices we
charge our customers, which could adversely affect our business practices, financial condition or results of operations.
Weather risk. Our results of operations may be negatively affected by warmer than average or colder than
average weather.
We are exposed to weather risk primarily in our utility business segment. A majority of our volume is driven from gas sales
made to space heating residential and commercial customers during each winter heating season. Current utility rates are based on
an assumption of average weather. Weather that is warmer than average typically results in lower gas sales. Sustained cold weather
could adversely affect our utility margin in the short-term as we may be required to purchase gas at spot rates in a rising price
market to obtain sufficient volumes to fulfill customer requirements. Although the effects of warmer or colder weather on utility
margin in Oregon are intended to be largely mitigated through the operation of our weather normalization mechanism. Oregon
customers may opt out of the mechanism. Approximately 10 percent of our residential and commercial customers are in
Washington where we do not have a weather normalization mechanism or conservation tariff. Furthermore, continuation of the
weather normalization mechanism and conservation tariff in Oregon after October 2012, are subject to regulatory approval. As a
result, we may not be fully protected against warmer than average or colder than average weather, both of which may have an
adverse affect on our financial condition, results of operations and cash flows.
Customer conservation risk. Customers’ conservation efforts may have a negative impact on our revenues.
Higher gas costs and rates and an increasing national focus on energy conservation may result in increased gas
conservation by customers, which can decrease sales and adversely affect our results of operations. The OPUC authorized our
conservation tariff, which is designed to recover lost margin
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due to changes in residential and commercial customers’ consumption. The conservation tariff is scheduled to expire in October
2012 (see “Results of Operations—Rate Mechanisms—Conservation Tariff,” below). The failure of the OPUC to extend the
conservation tariff in the future could adversely affect our financial condition, cash flows and results of operations. We do not have
a conservation tariff in Washington.
Operating risk. Transporting and storing natural gas involves numerous risks that may result in accidents and
other operating risks and costs.
Our gas distribution activities are subject to a variety of operating hazards and risks that cannot be completely avoided,
such as leaks, accidents, mechanical problems, fires, explosions, earthquakes, floods, storms, landslides and other adverse weather
conditions and hazards, which could cause substantial financial losses. In addition, these risks could result in loss of human life,
significant damage to property, environmental pollution and disruption of our operations, which in turn could lead to substantial
losses. The occurrence of any of these events may not be covered by our insurance policies or be recoverable through rates, which
could adversely affect our financial condition and results of operations.
Business continuity risk. We may be adversely impacted by national disasters, terrorist activities and other
extreme events to which we may not able to promptly respond.
National disasters, terrorist activities and other extreme events are a threat to our assets and operations. Companies in our
industry may face a heightened risk to exposure to actual acts of terrorism that could target or impact our natural gas distribution,
transmission and storage facilities and result in a disruption in our operations and ability to meet customer requirements. In addition,
the threat of terrorist activities could lead to increased economic instability and volatility in the price of natural gas that could affect
our operations. Threatened or actual national disasters or terrorist activities may also disrupt capital markets and our ability to raise
capital, or impact our suppliers or our customers directly. We maintain emergency planning and training programs to remain ready
to respond to extreme events. However, a slow or inadequate response to extreme events may have an adverse affect on
operations and earnings. We may not be able to obtain sufficient insurance to cover all risks associated with national disasters,
terrorist activities and other extreme events, which could increase the risk that an event could adversely affect our operations or
financial results.
Employee benefit risk. The cost of providing pension and postretirement healthcare benefits is subject to changes
in pension asset values, changing demographics and actuarial assumptions which may have an adverse effect on our
financial results.
We provide pension plans and postretirement healthcare benefits to eligible full-time employees. Our costs of providing
such benefits is subject to changes in the market value of our pension fund assets, changing demographics, including longer life
expectancies of beneficiaries, an expected increase in the number of eligible former employees over the next five to 10 years,
increases in healthcare costs, current and future legislative changes and various actuarial calculations and assumptions. The actuarial
assumptions used may differ materially from actual results due to changing market and economic conditions, withdrawal rates,
interest rates and other factors. These differences may result in a significant impact on the amount of pension expense or other
postretirement benefit costs recorded in future periods. Sustained declines in equity markets and reductions in bond yields may
have a material adverse effect on the value of our pension fund assets. In these circumstances, we may be required to recognize
increased contributions and pension expense earlier than we had planned
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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 cash flows and results of operations.
Workforce risk. Our business is heavily dependent on being able to attract and retain qualified employees and to
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 in our gas distribution business is dependent upon
our continuing ability to attract and retain talented professionals and a technically skilled workforce, and being able to transfer the
knowledge and expertise of our workforce to new employees as our aging employees retire. Without an appropriately skilled
workforce, our ability to provide quality service to our customers and meet our regulatory requirements will be challenged and this
could negatively impact our earnings. Additionally, a majority of our workers are represented by Office and Professional
Employees International Union Local No.11 AFL-CIO (the Union) and are covered by a collective bargaining agreement that will
expire May 31, 2009. The Company and the Union are expected to negotiate an agreement, but failure to reach an acceptable
collective bargaining agreement with the Union in a timely manner could result in instability in our labor relationship and work
stoppages that could impact the timely delivery of our product and services, which could strain relationships with customers and
state regulators and cause a loss of revenues which could adversely affect our results of operations. The terms of a revised
collective bargaining agreement may increase the cost of employing our workforce, affect our ability to continue offering marketbased salaries and employee benefits, limit our flexibility in dealing with our workforce, and limit our ability to change work rules
and practices and implement other efficiency-related improvements to successfully compete effectively in today’s competitive
marketplace.
Legislative and taxing authority risk. We are subject to governmental regulation, and our compliance with
local, state and federal requirements, including taxing requirements, and unforeseen changes in or interpretations of such
requirements could affect our financial condition and results of operations.
We are subject to regulation by federal, state and local governmental authorities. We are required to comply with a variety
of laws and regulations and to obtain authorizations, permits, approvals and certificates from governmental agencies in various
aspects of our business. We cannot predict with certainty the impact of any future revisions or changes in interpretations of existing
regulations or the adoption of new laws and regulations applicable to them. Changes in regulations or the imposition of additional
regulations could negatively influence our operating environment and results of operations. For example, Oregon legislation that
became effective in 2006, requires that utilities not collect in rates more income taxes than they actually pay to taxing authorities. If
amounts paid differ from amounts we collect by more than $100,000 we are required to implement a rate schedule with an
automatic adjustment clause to refund or surcharge the difference, which could be material.
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 negatively affect our results of operations. Tax law
and its related regulations and case law are inherently complex. 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
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taxing authorities. Unforeseen changes in laws, regulations or adverse judgments may negatively affect our financial condition and
results of operations.
ITEM 1B. UNRESOLVED STAFF COMMENTS
We have no unresolved comments.
ITEM 2. PROPERTIES
Our natural gas distribution system consists of approximately 13,800 miles of distribution and transmission mains located
in our service territory in Oregon and Washington. In addition, the distribution system includes service pipes, meters and regulators,
and gas regulating and metering stations. The mains are located in municipal streets or alleys pursuant to valid franchise or
occupation ordinances, in county roads or state highways pursuant to valid agreements or permits granted pursuant to statute, or on
lands of others pursuant to valid easements obtained from the owners of such lands. We also hold all necessary permits for the
crossing of the Willamette River and a number of smaller rivers by our mains.
We own service facilities in Portland, as well as various satellite service centers, garages, warehouses and other buildings
necessary and useful in the conduct of our business. We lease office space in Portland for our corporate headquarters, which lease
expires on May 31, 2018. Resource centers are maintained on owned or leased premises at convenient points in the distribution
system. We own LNG storage facilities in Portland and near Newport, Oregon.
We hold interests in approximately 8,500 net acres of underground natural gas storage and approximately 1,600 net acres
of oil and gas leases in Oregon. 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.
In order to reduce risks associated with gas leakage in older parts of our system, we undertook an accelerated pipe
replacement program under which we removed or replaced 100 percent of our cast iron mains by October 2000. In 2001, we
initiated an accelerated pipe replacement program under which we expect to eliminate all bare steel mains and services in the
system by 2021.
We consider all of our properties currently used in our operations, both owned and leased, to be well maintained, in good
operating condition, and, along with planned additions, adequate for our present and foreseeable future needs.
Our Mortgage and Deed of Trust is a first mortgage lien on substantially all of the property constituting our utility plant.
ITEM 3. LEGAL PROCEEDINGS
Other than the proceedings disclosed in Note 12, we have only routine nonmaterial litigation in the ordinary course of
business.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
There were no matters submitted to a vote of security holders, through the solicitation of proxies or otherwise, during the
quarter ended December 31, 2008.
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PART II
ITEM 5. MARKET FOR THE REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND
ISSUER PURCHASES OF EQUITY SECURITIES
(A) Our common stock is listed and trades on the New York Stock Exchange under the symbol “NWN.”
The high and low trades for our common stock during the past two years were as follows:
2008
Quarter Ended
March 31
June 30
September 30
December 31
High
$ 50.74
48.22
55.23
53.71
2007
Low
$ 41.07
43.08
43.66
36.61
High
$ 46.34
52.85
49.37
50.89
Low
$ 39.79
44.05
40.98
44.28
The closing quotations for our common stock on December 31, 2008 and 2007 were $44.23 and $48.66, respectively.
(B) As of December 31, 2008, there were 7,673 holders of record of our common stock.
(C) We have paid quarterly dividends on our common stock in each year since the stock first was issued to the public in
1951. Annual common dividend payments per share, adjusted for stock splits, have increased each year since 1956. Dividends per
share paid during the past two years were as follows:
Payment Date
February 15
May 15
August 15
November 15
Total per share
2008
0.375
0.375
0.375
0.395
$
1.520
$
2007
0.355
0.355
0.355
0.375
$
1.440
$
The amount and timing of dividends payable on our common stock are within the sole discretion of our Board of
Directors. Our Board of Directors expects to continue paying cash dividends on our common stock on a quarterly basis. However,
the declaration and amount of future dividends depend upon our earnings, cash flows, financial condition and other factors.
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(D) The following table provides information about purchases of our equity securities that are registered pursuant to
Section 12 of the Securities Exchange Act of 1934 during the quarter ended December 31, 2008:
ISSUER PURCHASES OF EQUITY SECURITIES
Period
Balance forward
10/01/08-10/31/08
11/01/08-11/30/08
12/01/08-12/31/08
Total
(1)
(2)
(a)
(b)
Total Number
of Shares
Purchased (1)
Average
Price Paid
per Share
1,645
21,275
1,349
24,269
$
$
$
$
43.88
47.83
44.01
47.35
(c)
Total Number of Shares
Purchased as Part of
Publicly Announced
Plans or Programs (2)
2,124,528
2,124,528
(d)
Maximum Dollar Value of
Shares that May Yet Be
Purchased Under the
Plans or Programs (2)
$
16,732,648
$
16,732,648
During the quarter ended December 31, 2008, 22,005 shares of our common stock were purchased on the open market to
meet the requirements of our Dividend Reinvestment and Direct Stock Purchase Plan. In addition, 2,264 shares of our
common stock were purchased on the open market during the quarter under equity-based programs. During the three months
ended December 31, 2008, no shares of our common stock were accepted as payment for stock option exercises pursuant
to our Restated Stock Option Plan.
We have a share repurchase program for our common stock under which we purchase shares on the open market or through
privately negotiated transactions. We have Board authorization through May 31, 2009 to repurchase up to an aggregate of
2.8 million shares or up to an aggregate of $100 million. For the year ended December 31, 2008, no shares of our common
stock were purchased pursuant to this program. Since the program’s inception in 2000 we have repurchased 2.1 million
shares of common stock at a total cost of $83.3 million.
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ITEM 6. SELECTED FINANCIAL DATA
Thousands, except per share amounts and
ratio of earnings to fixed charges
Utility operating revenues:
Residential sales
Commercial sales
Industrial - firm sales
Industrial - interruptible sales
Total gas sales revenues
Transportation
Regulatory adjustment for income taxes paid (1)
Other
Total gross utility operating revenues
Cost of gas sold
Revenue taxes
Utility net operating revenues
Non-utility net operating revenues
Net operating revenues
For the year ended December 31,
2007
2006
2005
$ 566,840
298,943
46,579
68,978
981,340
14,288
1,760
21,784
1,019,172
656,504
25,072
337,596
18,619
$ 356,215
$ 555,312
298,800
54,567
74,876
983,555
14,191
5,996
12,228
1,015,970
639,094
25,001
351,875
17,167
$ 369,042
$ 536,468
290,666
66,986
93,107
987,227
12,800
—
161
1,000,188
648,081
24,840
327,267
12,909
$ 340,176
$ 471,502
250,287
64,507
100,740
887,036
10,755
—
2,862
900,653
563,772
21,633
315,248
9,745
$ 324,993
$ 383,067
200,424
45,259
55,380
684,130
12,655
—
4,160
700,945
399,176
16,865
284,904
6,591
$ 291,495
Net income
$
$
$
$
$
2008
Average common shares outstanding:
Basic
Diluted
69,525
26,438
26,594
74,497
26,821
26,995
63,415
27,540
27,657
58,149
2004
27,564
27,621
50,572
27,016
27,283
Earnings per share of common stock:
Basic
Diluted
$
$
2.63
2.61
$
$
2.78
2.76
$
$
2.30
2.29
$
$
2.11
2.11
$
$
1.87
1.86
Dividends paid per share of common stock
$
1.52
$
1.44
$
1.39
$
1.32
$
1.30
Total assets - at end of period
$2,378,152
$2,014,061
$1,956,856
$2,042,304
$1,732,195
Long-term debt
Ratio of earnings to fixed charges
$ 512,000
3.76
$ 512,000
3.92
$ 517,000
3.40
$ 521,500
3.32
$ 484,027
3.02
(1)
Regulatory adjustment for income taxes paid is the result of the implementation of the utility regulation as described in Part II, Item 7., “ Business Segments - Utility Operations Regulatory Adjustment for Income Taxes Paid.”
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SELECTED FINANCIAL DATA (continued)
Thousands, except customer and gas cost per therm data
Capitalization - at end of period
Common stock equity
Long-term debt
Total capitalization
Gas sales and transportation deliveries (therms):
Residential
Commercial
Industrial - firm
Industrial - interruptible
Total gas sales
Transportation
Total volumes delivered
2008
For the year ended December 31,
2007
2006
2005
2004
$ 628,373
512,000
$1,140,373
$ 594,751
512,000
$1,106,751
$ 599,545
517,000
$1,116,545
$ 586,931
521,500
$1,108,431
$ 568,517
484,027
$1,052,544
428,787
265,531
47,340
87,484
829,142
431,609
1,260,751
398,960
249,659
52,340
89,128
790,087
424,882
1,214,969
382,665
242,683
66,971
112,736
805,055
387,594
1,192,649
371,538
233,987
74,880
149,106
829,511
328,056
1,157,567
352,356
222,875
62,843
104,278
742,352
389,514
1,131,866
594,481
61,756
625
180
136
657,178
580,346
60,749
634
189
128
642,046
564,700
59,889
650
197
99
625,535
545,163
58,914
666
201
78
605,022
525,976
57,973
629
178
106
584,862
Customers (average for period):
Residential
Commercial
Industrial - firm
Industrial - interruptible
Transportation
Total customers
Customer statistics:
Heat requirements:
Actual degree days
Percent colder (warmer) than average
Average annual use per customer in therms:
Residential
Commercial
Gas purchased cost per therm - net (cents)
31
4,576
7%
4,374
3%
4,089
(4%)
4,178
(2%)
3,853
(10%)
721
4,300
86.56
687
4,110
75.00
678
4,052
75.37
682
3,972
71.42
670
3,844
56.60
Table of Contents
ITEM 7.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS
The following is management’s assessment of Northwest Natural Gas Company’s (NW Natural) financial condition,
including the principal factors that affect results of operations. The discussion refers to our consolidated activities for the years
ended December 31, 2008, 2007 and 2006. Unless otherwise indicated, references in this discussion to “Notes” are to the Notes
to Consolidated Financial Statements in this report.
The consolidated financial statements include the accounts of NW Natural and its wholly-owned subsidiaries, NNG
Financial Corporation (Financial Corporation) and Gill Ranch Storage, LLC (Gill Ranch), and an equity investment in a proposed
natural gas pipeline. These accounts consist of our regulated local gas distribution business, our regulated gas storage business, and
other regulated and non-regulated investments primarily in energy-related businesses. In this report, the term “Utility” is used to
describe our regulated local gas distribution segment, and the term “Non-utility” is used to describe our gas storage segment (gas
storage) and our other regulated and non-regulated investments and business activities (other segment) (see “Strategic
Opportunities,” below, and Note 2).
In addition to presenting results of operations and earnings amounts in total, certain measures are expressed in cents per
share. These amounts reflect factors that directly impact earnings. We believe this per share information is useful because it enables
readers to better understand the impact of these factors on earnings. All references in this section to earnings per share are on the
basis of diluted shares (see Note 1).
Executive Summary
Highlights of 2008:
•
•
•
•
•
•
•
•
Consolidated net income was $69.5 million, or $2.61 per share;
Net operating revenues decreased 3 percent from $369.0 million to $356.2 million, largely due to a $17.6 million
swing in our utility’s sharing of higher gas costs;
Operations and maintenance expense decreased 6 percent or $7.1 million;
Cash flow from operations decreased $148.9 million due to temporary working capital requirements, while our credit
and liquidity position remained strong;
General rate case was approved in Washington with a $2.7 million increase in annual revenues, effective January 1,
2009;
Permit applications were filed for our gas storage project in California and our gas transmission pipeline project in
Oregon, keeping these strategic investment opportunities on track for potential development over the next few years;
We ranked number one in the nation among gas utilities in the 2008 J.D. Power and Associates Gas Utility Residential
Customer Satisfaction Survey; and
We raised the quarterly common stock dividend by 5 percent to $0.395 per share in the fourth quarter of 2008,
making this the 53rd consecutive year of increasing dividends paid to shareholders.
Our business primarily consists of our regulated utility and gas storage operations. Factors critical to the success of the
utility business include: maintaining a safe and reliable distribution system; acquiring an adequate supply of natural gas; providing
distribution services at competitive prices; and being able to recover our operating and capital costs in the rates charged to
customers in a
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reasonable and timely manner. Our utility is regulated by two state commissions, the Oregon Public Utility Commission (OPUC)
and the Washington Utilities and Transportation Commission (WUTC). Factors critical to the success of our gas storage business
include: developing additional storage capacity at competitive market prices; retaining existing customers or being able to market
storage capacity to new customers; planning for the replacement of capacity that is expected to be recalled by the utility to serve
growing demands of its customers; obtaining timely approval of reasonable rate increases; and with respect to future development
of gas storage projects, being able to obtain financing to fund future development. Our existing gas storage business charges rates
that are approved by the Federal Energy Regulatory Commission (FERC) for interstate customers or the OPUC for intrastate
customers. The Gill Ranch gas storage project currently under development will be subject to regulation by the California Public
Utilities Commission (CPUC), upon completion of certain milestones (see “2009 Outlook—Strategic Opportunities—Gas Storage
Development,” below).
2009 Outlook
In 2009, we intend to remain focused on improving our core businesses, enhancing our strategic position, advancing
business development projects related to our primary businesses, and strengthening our organizational effectiveness. The following
is a brief summary of management’s plans and objectives in these four areas.
Business Improvements. We are developing and implementing new technology into our operations while honing the new
processes established by the changes to our operating model over the last several years. Our goal is to integrate, consolidate and
streamline operations and support our employees with new technology tools that should enable us to become more effective and
efficient. We intend to continue developing new technology such as: an enterprise resource planning system, which provides an
integrated comprehensive suite of business application software to more efficiently process and manage information in all parts of
our business; continued deployment of our new automated dispatching system throughout the business, which provides integrated
planning and scheduling with global positioning capabilities to more effectively collect and distribute data to employees in remote
locations; and completing the installation of our automated meter reading system, which will convert the remaining customer meters
so that all of our meters can be read electronically by the end of 2009. We expect these and other new technologies to continue
supporting our new operating model, which re-aligned our operating functions into key process areas such as customer services,
energy supply and gas delivery, to help centralize and standardize all of our business operations. For further discussion, see
“Strategic Opportunities,” below.
Strategic Position. In our rapidly changing business environment, we remain focused on creating shareholder value while
balancing the interests of our customers, employees and the communities we serve. In doing so, we intend to develop and re-work
plans in response to our changing business environment, including potential climate change legislation as well as ongoing economic,
regulatory, business development and workforce challenges and opportunities. For further discussion, see “Issues, Challenges and
Performance Measures,” and “Strategic Opportunities,” below.
Business Development. In addition to exploring new growth opportunities, we intend to continue advancing key natural
gas infrastructure investments during 2009, including our gas transmission pipeline project in Oregon and our gas storage project in
California. For further discussion of these two projects, see “Strategic Opportunities,” below.
Organizational Effectiveness. Our employees continue to be our most highly valued resource. We intend to continue
supporting our employees with a positive work environment, providing
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development training, and developing new technologies to achieve our goals and facilitate improvements to our operating model.
For further discussion see “Strategic Opportunities,” below.
Issues, Challenges and Performance Measures
Managing the business in a period of gas price volatility. Our gas acquisition strategy is primarily designed to secure
sufficient supplies of natural gas to meet the needs of our utility’s residential, commercial and industrial customers on firm service.
Equally important, however, is our strategy to hedge gas prices for a significant portion of our annual purchase requirements based
upon our utility’s gas load forecast for core utility customers. We have hedged gas prices for the majority of our gas purchases for
the gas contract year that began on November 1, 2008, and we believe we have sufficient supplies of natural gas to meet the needs
of our core utility customers. Although gas prices reached historically high levels during the third quarter of 2008, the price of
natural gas has declined significantly in recent months and is currently below the prices embedded in our customers’ rates through
our annual purchased gas adjustment (PGA). Gas costs lower or higher than those set in the PGA may positively or negatively
impact earnings, respectively, due to an incentive sharing mechanism in Oregon. Higher gas costs are also likely to affect our
competitive advantage because they could reduce our ability to add residential and commercial customers and potentially cause
industrial customers to shift their energy needs to alternative fuel sources. In October 2008, the OPUC approved a change to the
PGA incentive sharing mechanism that allows us to select a cost-sharing ratio annually. The PGA cost-sharing ratio, along with gas
hedging strategies and inventories in storage, enables us to manage and reduce earnings risk exposure due to higher gas costs. We
believe the modification to the Oregon PGA better aligns customer and shareholder interests. In Washington, where we recover
100 percent of our actual gas purchase costs from customers, there has been no change to the PGA mechanism (see “Results of
Operations—Regulatory Matters—Rate Mechanisms—Purchased Gas Adjustment,” below).
Economic weakness and financial market stress. The overall weakness in the U.S. economy, including disruption in
the global credit and financial markets, increasing numbers of foreclosures and bankruptcies, lower rates of new housing
construction, and volatility in energy prices, has resulted in significant negative pressure on consumer demand and business
spending. These conditions could have a negative impact on our financial results including certain key performance measures such
as margins, customer growth rates, bad debt expense, and net interest charges. Our customer growth rate, which in recent years
has slowed but continues at a rate above the national average, declined to 1.6 percent during 2008 compared to 2.4 percent in
2007. Based on current market conditions, we expect customer growth rates in 2009 to continue at or near 2008 levels, or
possibly lower if economic conditions deteriorate further, but our growth rate should remain above the national average due to a
relatively low market penetration of natural gas in our service territory, the forecasted population growth in our service territory, the
potential for environmental initiatives in Oregon and Washington that could favor natural gas as an energy source, and our efforts to
convert existing homes from other heating fuels to natural gas.
Our funding for strategic investment opportunities is dependent upon our ability to access capital markets and maintain
working capital sufficient to meet operating requirements. We intend to continue focusing on: maintaining a strong balance sheet;
providing sufficient liquidity resources; monitoring and managing critical business risks; and securing, as needed, proceeds from the
issuance of equity or long-term debt securities in order to fund utility and business development capital expenditures. To help
mitigate the effect of the negative economic and capital market trends referred to
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above, we expect to manage costs, extend short-term debt maturities, maintain higher cash balances, increase the aggregate
commitment amount under existing or new credit facilities as needed, and access capital markets to secure proceeds from the
issuance of long-term securities for capital expenditure requirements. If we are unable to secure financing to fund certain strategic
opportunities, we may look at potentially re-prioritizing the use of existing resources or consider delaying investments until market
conditions improve.
We believe that, despite the current economic and credit market environment, our financial condition, including our
liquidity position, is strong and we can access capital at reasonable costs. See Part I, Item 1A., “Risk Factors,” above and
“Financial Condition—Liquidity and Capital Resources,” below.
Strategic Opportunities
Business Process Improvements. To address our economic and competitive challenges, we intend to re-assess business
processes for continuous improvements. Our goal is to integrate, consolidate and streamline operations and support our employees
with new technology tools that enable us to become more effective and efficient. In 2008, we implemented the first phase of our
new enterprise resource planning (ERP) system, and in February 2009 we implemented the second phase. This new ERP system
provides a comprehensive suite of business application software that interfaces with our existing customer information and
automated dispatching systems. We expect this new ERP system to improve overall operating efficiencies by automating:
•
•
•
the integration of systems and data;
the control procedures with auditable financial and operational workflows; and
certain areas of our monthly closing and financial reporting process.
In 2006, we automated the reading of gas meters on approximately one-third of our customers’ meters. The meters
equipped with this technology now electronically transmit usage data to receiving devices located in our vehicles as they are driven
in the area, substantially reducing the labor costs associated with manually reading those customer meters. In 2008, we initiated a
project to automate the reading of gas meters (AMR) for our remaining customers. The capital cost of this project is estimated to
be $30 million, and in January 2009 we filed for regulatory recovery of this investment. Also in 2008, we initiated an automated
dispatching system, which provides integrated planning and scheduling with global positioning system capabilities to more effectively
collect and distribute data. These technology investments and other initiatives are expected to facilitate process improvements and
contribute to long-term operational efficiencies throughout NW Natural.
Pipeline Diversification. Currently, we depend on a single interstate pipeline company to ship gas supplies to our
system. Palomar Gas Transmission, LLC, (Palomar) is a wholly-owned subsidiary of Palomar Gas Holdings, LLC, (PGH). PGH is
owned 50 percent by NW Natural and 50 percent by TransCanada Gas Transmission Northwest’s (GTN). Palomar is seeking to
build and operate a 217-mile natural gas transmission pipeline in Oregon to serve our utility and the growing markets in Oregon and
other parts of the western United States. The Palomar pipeline would extend west from an interconnection with GTN’s existing
interstate transmission mainline near Madras, Oregon to an interconnection with NW Natural’s gas distribution system near
Molalla, Oregon and then extend further west to additional interconnections including a possible connection to one of the several
liquefied natural gas (LNG) terminals proposed to be built on the Columbia River. Palomar would
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diversify NW Natural’s delivery options and enhance the reliability of service to our utility customers by providing an alternate
transportation path for gas purchases from different regions in western Canada and the U.S. Rocky Mountains. Palomar would
also provide our utility customers with access to a new source of gas supply if an LNG terminal is built on the Columbia River. The
Palomar pipeline would be regulated by the FERC. In December 2008, Palomar filed for a Certificate of Public Convenience and
Necessity with the FERC.
Palomar continues to work on the planning and permitting phase of the project, which is expected to extend through
2010. The total cost for planning and permitting is estimated to be between $40 million and $45 million, 50 percent of which is our
investment based on our ownership interest. At December 31, 2008, the amount we had invested was $14.2 million. The total cost
estimate for the entire 217-mile pipeline, if constructed, is estimated to be between $700 million and $800 million, with our current
50 percent share estimated at between approximately $350 million and $400 million. During 2009 and 2010, PGH will continue to
evaluate market conditions and project status to determine if and when to proceed with construction of all or some portion of the
project. Palomar has executed binding precedent agreements with shippers, including our own utility, for a majority of the current
design capacity on the pipeline. These agreements also provide commitments of credit support to the project. We will continue to
assess project risks and evaluate the project costs and fair value of our investment on a quarterly basis, including a valuation of the
available credit support.
Gas Storage Development. In September 2007, we announced a joint project with Pacific Gas & Electric Company
(PG&E) to develop an underground natural gas storage facility near Fresno, California. We formed a wholly-owned subsidiary, Gill
Ranch, to plan, develop and operate the facility. In July 2008, Gill Ranch filed an application with the CPUC for a Certificate of
Public Convenience and Necessity. In December 2008, the CPUC indicated that our application qualified for a Mitigated Negative
Declaration, which allows an expedited review process. We expect to establish the application review schedule with the CPUC
early in 2009 and to receive a decision on our application by the end of 2009. Gill Ranch will become subject to CPUC regulation
regarding various matters including, but not limited to, securities issuances, lien grants and sales of property. We estimate our share
of the total cost of this project to be between $160 and $180 million. Our share represents 75 percent of the total cost of the initial
phase of storage development for an estimated 20 Bcf of gas storage capacity and approximately 27 miles of gas transmission
pipeline during the 2008 to 2010 period. The initial phase of gas storage at Gill Ranch is currently scheduled to be in-service by late
2010.
Earnings and Dividends
Net income was $69.5 million, or $2.61 per share, for the year ended December 31, 2008, compared to $74.5 million,
or $2.76 per share, and $63.4 million, or $2.29 per share, for the years ended December 31, 2007 and 2006, respectively.
Returns on equity for these three years were 11.4 percent, 12.5 percent and 10.7 percent, respectively.
2008 compared to 2007:
Factors contributing to decreased earnings were:
•
•
a $5.5 million loss in utility margin from our regulatory share of gas cost increases in 2008 compared to a margin gain
of $12.1 million in 2007 from gas cost decreases;
a $4.2 million decrease in utility margin from a lower customer surcharge related to regulatory adjustments for income
taxes paid;
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•
•
•
a $3.8 million increase in depreciation expense primarily due to increased utility plant in service;
a $2.9 million decrease in margin due to a temporary mark-to-market gain in 2007; and
a $1.6 million decrease in utility margin from industrial customers due to weaker economic conditions.
Partially offsetting the above factors were:
•
•
•
•
•
a $7.1 million increase in utility margin from higher sales volumes to residential and commercial customers due to
colder weather and customer growth, after decoupling and weather mechanism adjustments;
a $7.1 million decrease in operation and maintenance expense, partially due to higher costs in 2007 for strategic
initiatives, and partially due to lower bonuses and employee benefit costs in 2008;
a $3.4 million decrease in income tax expense due to lower taxable income;
a $1.1 million after-tax gain from the sale of our investment in an aircraft leased to a commercial airline; and
a $0.8 million increase in utility margin due to curtailment charges for use by a small number of industrial customers
during cold weather.
2007 compared to 2006:
Positive factors contributing to increased earnings were:
•
•
•
•
•
a $9.7 million increase in utility margin from higher sales volumes to residential and commercial customers due to
customer growth;
a $6.0 million increase in utility margin from a regulatory adjustment for income taxes paid;
a $4.0 million increase in utility margin from our regulatory share of gas cost savings, up from $8.1 million in 2006 to
$12.1 million in 2007;
a $5.8 million increase in utility margin from temporary mark-to-market adjustments on derivative contracts, with a
$2.9 million gain realized in 2007 and a $2.9 million loss realized in 2006; and
a $4.2 million increase in margin from gas storage operations, due to an expansion of firm storage capacity and higher
revenues sharing from asset optimization.
Partially offsetting the above positive factors were:
•
•
•
a $3.9 million increase in depreciation expense, primarily related to increased utility plant in service;
a $5.9 million increase in operations and maintenance expense due to higher bonuses tied to improved operating
results and increases for certain strategic initiatives including utility maintenance projects and training; and
a $7.8 million increase in income tax expense related to higher taxable income.
Dividends paid on our common stock were $1.52 a share in 2008, compared to $1.44 a share in 2007 and $1.39 a share
in 2006. The current indicated annual dividend rate is $1.58 per share.
Application of Critical Accounting Policies and Estimates
In preparing our financial statements using generally accepted accounting principles in the United States of America
(GAAP), management exercises judgment in the selection and application of
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accounting principles, including making estimates and assumptions that affect reported amounts of assets, liabilities, revenues,
expenses and related disclosures in the financial statements. Management considers our critical accounting policies to be those
which are most important to the representation of our financial condition and results of operations and which require management’s
most difficult and subjective or complex judgments, including accounting estimates that could result in materially different amounts if
we reported under different conditions or used different assumptions. Our most critical estimates and judgments include accounting
for:
•
•
•
•
•
•
regulatory cost recovery and amortizations;
revenue recognition;
derivative instruments and hedging activities;
pensions;
income taxes; and
environmental contingencies.
Management has discussed the 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 1.
Regulatory Accounting
We are regulated by the OPUC and WUTC, which establish our utility rates and rules governing utility services provided
to customers, and, to a certain extent, set forth the accounting treatment for certain regulatory transactions. In general, we use the
same accounting principles as non-regulated companies reporting under GAAP. However, certain accounting principles, primarily
Statement of Financial Accounting Standards (SFAS) No. 71, “Accounting for the Effects of Certain Types of Regulation,” require
different accounting treatment for regulated companies to show the effects of such regulation. For example, we account for the cost
of gas using a PGA deferral and cost recovery mechanism, which is submitted for approval annually to the OPUC and WUTC (see
“Results of Operations—Regulatory Matters—Rate Mechanisms,” below). There are other expenses or revenues that the OPUC
or WUTC may require us to defer for recovery or refund in future periods. SFAS No. 71 requires us to account for these types of
deferred expenses (or deferred revenues) as regulatory assets (or regulatory liabilities) on the balance sheet. When we are allowed
to recover these expenses from or required to refund them to customers, we recognize the expense or revenue on the income
statement at the same time we realize the adjustment to amounts included in utility rates charged to customers.
The conditions we must satisfy to adopt the accounting policies and practices of SFAS No. 71, which are applicable to
regulated companies, include:
•
•
•
an independent regulator sets rates;
the regulator sets the rates to cover specific costs of delivering service; and
the service territory lacks competitive pressures to reduce rates below the rates set by the regulator.
We continue to apply SFAS No. 71 in accounting for our regulated utility operations. Future regulatory changes or
changes in the competitive environment could require us to discontinue the
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application of SFAS No. 71 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 regulatory and
competitive conditions, we believe that it is reasonable to expect continued application of SFAS No. 71 for our regulated activities,
and that all of our regulatory assets and liabilities at December 31, 2008 and 2007 are recoverable or refundable through future
customer rates. See Note 1, “Industry Regulation.”
Revenue Recognition
Utility revenues, derived primarily from the sale and transportation of natural gas, are recognized when gas is delivered to
and received by the customer. Revenues are accrued for gas delivered to customers, but not yet billed, based on estimates of gas
deliveries from the last meter reading date to month end (accrued unbilled revenues). Accrued unbilled revenues are primarily
based on a percentage estimate of our unbilled gas deliveries each month, which is dependent upon a number of factors, some of
which require management’s judgment. These factors include total gas receipts and deliveries, customer meter reading dates,
customer usage patterns and weather. Accrued unbilled revenue estimates are reversed the following month when actual billings
occur. Estimated unbilled revenues at December 31, 2008 and 2007 were $102.7 million and $78.0 million, respectively. The
increase in accrued unbilled revenues at year-end 2008 was primarily due to higher volumes reflecting colder weather and higher
gas prices included in customer rates. If the estimated percentage of unbilled volume at December 31, 2008 was adjusted up or
down by 1 percent, then our unbilled revenues, net operating revenues and net income would have increased or decreased by an
estimated $4.4 million, $0.4 million and $0.4 million, respectively.
Utility revenues may also include the recognition of a regulatory adjustment for income taxes paid. This revenue
adjustment reflects an OPUC rule whereby we are required to implement a rate refund or a rate surcharge to utility customers. This
refund or surcharge is accrued based on the estimated difference between income taxes paid and income taxes authorized to be
collected in rates for the tax year (see “Results of Operations—Business Segments – Utility Operations—Regulatory Adjustment
for Income Taxes Paid,” below).
Non-utility revenues, derived primarily from our gas storage business segment, are recognized upon delivery of the service
to customers. Revenues from asset optimization, which are included in our gas storage segment, are recognized when services are
provided by the independent energy marketing company in accordance with our contractual agreement. Our current asset
optimization agreement includes guaranteed amounts which are recognized pro-rata on a monthly basis over the contract term.
Accounting for Derivative Instruments and Hedging Activities
Our financial derivatives and gas acquisition policies set forth guidelines for using financial derivative instruments to support
prudent risk management strategies. These policies specifically prohibit the use of derivatives for trading or speculative purposes.
The accounting rules for determining whether a contract meets the definition of a derivative instrument or qualifies for hedge
accounting treatment are complex. The contracts that meet the definition of a derivative instrument are recorded on our balance
sheet at fair value. If certain regulatory conditions are met, then the fair value is recorded together with an offsetting entry to a
regulatory asset or liability account pursuant to SFAS No. 71 (see Note 1, “Industry Regulation”), and no gain or loss is
recognized in current income. The gain or loss from the fair value of a derivative instrument that is subject to regulatory deferral is
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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 gains and losses is recorded in accordance with
SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended by SFAS No. 138 and SFAS
No. 149, collectively referred to as SFAS No. 133 (see Note 1, “Derivatives” and “Industry Regulation”). Derivative contracts
outstanding at December 31, 2008 were measured at fair value using models or other market accepted valuation methodologies
derived from observable market data. The estimate of fair value may change significantly from period-to-period depending on
market conditions and prices. These changes may have an impact on our results of operations, but the impact would largely be
mitigated due to the majority of our derivatives activities being subject to regulatory deferral treatment. For estimated fair values on
unrealized gains and losses at December 31, 2008 and 2007, see Note 11.
Commodity-based derivative contracts entered into by the utility after our annual PGA filing for the current gas contract
period are subject to a regulatory incentive sharing mechanism in Oregon (see “Results of Operations—Regulatory Matters—Rate
Mechanisms—Purchased Gas Adjustment,” below). The portion not deferred to a regulatory account pursuant to that sharing
agreement is recognized either in current income for contracts not qualifying for hedge accounting or in other comprehensive income
for contracts qualifying for hedge accounting. Our interest rate swap qualifies for hedge accounting under SFAS No. 133, assuming
the swap is highly effective.
Derivative hedge contracts are subject to a hedge effectiveness test to determine the financial statement treatment of each
specific derivative. As of December 31, 2008, all of our derivatives were effective economic hedges and either qualified or were
expected to qualify for regulatory deferral or hedge accounting treatment. We use the hypothetical derivative method under SFAS
No. 133 to determine the hedge effectiveness of our interest rate swap which qualifies as a cash flow hedge. We extended the
effective date of our interest rate swap from December 1, 2008 to April 1, 2009 which resulted in an ineffectiveness of $1.5
million. In accordance with SFAS No. 71, we have reclassified this amount to regulatory assets. The ineffectiveness for all other
derivative contracts is determined using the dollar offset method under SFAS No. 133. The effectiveness test applied to financial
derivatives is dependent on the type of derivative and its use.
The following table summarizes the amount of realized gains and losses from commodity price and currency hedge
transactions for the last three years:
Thousands
Net gain (loss) on commodity-price swaps—utility
Net gain (loss) on commodity-price options—utility
Subtotal on commodity—utility
Net gain (loss) on foreign currency forward purchases—utility
Total realized net gain (loss)
2008
$34,256
1,527
35,783
(728)
$35,055
2007
$(41,954)
(662)
(42,616)
662
$(41,954)
2006
$(18,849)
(1,160)
(20,009)
355
$(19,654)
Realized gains (losses) from commodity hedges and foreign currency forward purchase contracts are recorded as
reductions (increases) to the cost of gas and are included in the calculation of annual PGA rate changes. Realized gains (losses)
from interest rate hedges are recorded as reductions (increases) to interest charges over the term of the underlying debt issuances.
Unrealized gains and losses from commodity hedges, foreign currency contracts and interest rate hedges, which reflect quarterly
mark-to-market valuations, are generally not recognized in current income or other comprehensive income, but are recorded as
regulatory liabilities or regulatory assets, and are offset by a corresponding balance in non-trading derivative assets or liabilities (see
Note 11).
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Accounting for Pensions
We maintain two qualified non-contributory defined benefit pension plans covering a majority of our regular employees
with more than one year of service, several non-qualified supplemental pension plans for eligible executive officers and certain key
employees and other employee postretirement benefit plans. Only the two qualified defined benefit pension plans have plan assets,
which are held in a qualified trust to fund retirement benefits. Effective January 1, 2007, the Retirement Plan for Non-Bargaining
Unit Employees and the Welfare Benefits Plan for Non-Bargaining Unit Employees were closed to anyone hired or rehired.
Instead, non-bargaining unit employees hired or re-hired after December 31, 2006 are provided an enhanced Retirement K
Savings Plan benefit. Benefits provided to bargaining unit employees under the retirement plan for bargaining unit employees were
not affected by these changes.
Net periodic pension costs (pension costs) and projected benefit obligations (benefit obligations) are determined in
accordance with SFAS No. 87, “Employers’ Accounting for Pensions,” using a number of key assumptions including discount
rates, rate of compensation increases, retirement ages, mortality rates and the expected long-term return on plan assets (see Note
7). These key assumptions have a significant impact on the amounts reported. Pension 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 marketrelated valuation of assets. The market-related valuation reflects differences between expected returns and actual investment
returns, which are recognized over a three-year period from the year in which they occur, thereby reducing year-to-year volatility in
pension costs.
SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans,” requires balance
sheet recognition of the overfunded or underfunded status of pension plans in accumulated other comprehensive income (AOCI),
net of tax, based on the fair value of plan assets compared to the actuarial value of future benefit obligations. However, the pension
costs relating to certain NW Natural pension plans are recovered in utility rates based on SFAS No. 87, and as such we received
regulatory approval from the OPUC pursuant to SFAS No. 71 to record the overfunded or underfunded status as a regulatory
asset or regulatory liability, rather than including it as AOCI under common equity (see “Regulatory Accounting”, above, and Note
1, “Industry Regulation”).
A number of factors are considered in developing pension assumptions, including evaluations of relevant discount rates, an
evaluation of expected long-term investment returns based on asset classes and target asset allocations, and expected changes in
salaries and wages, analyses of past retirement plan experience and current market conditions and input from actuaries and other
consultants. For the December 31, 2008 measurement date, we reviewed and updated:
•
•
•
•
our pension discount rate assumptions from a range of 6.75 to 6.87 percent to a range of 6.44 to 6.72 percent. The
new rate assumptions were determined for each plan based on a matching of the estimated cash flow, which reflects
the timing and amount of future benefit payments, to the Citigroup Above Median Curve, which consists of high
quality bonds rated AA- or higher by Standard & Poor’s (S&P) or Aa3 or higher by Moody’s Investors Service
(Moody’s);
our expected rate of future compensation increases from a range of 4.0 to 5.0 percent to a range of 3.5 to 5.0
percent;
our expected long-term return on plan assets remained unchanged at 8.25 percent; and
other key assumptions as needed.
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At December 31, 2008, our net pension liability (benefit obligations minus market value of plan assets) for the two
qualified defined benefit plans increased by $96.6 million compared to 2007. Poor equity and bond market performance had a
significant impact on the fair value of plan assets resulting in the large increase in our unfunded pension liability. Changes in valuation
assumptions impact our benefit obligations. Benefit obligations at December 31, 2008 increased $7.4 million due to a decrease in
our discount rate assumptions and increased by $5.0 million due to updating our mortality tables.
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 rate of return assumption, we evaluate an analysis of historical actual performance and longterm return projections, which gives consideration to the current asset mix and our target asset allocation. As of December 31,
2008, the actual annualized returns on plan assets, net of management fees, for the past one-year, five-years, 10-years and since
December 1980 were (27.18) percent, 1.82 percent, 2.97 percent and 10.10 percent, 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 pension costs and benefit obligations to future changes in certain actuarial
assumptions:
Thousands, except percent
Discount rate
Expected long-term return on plan assets
Change in
Assumption
(0.25%)
(0.25%)
Impact on
2008 Pension Costs
$
785
$
431
Impact on Benefit
Obligations at
Dec. 31, 2008
$
7,809
N/A
The impact of a change in pension costs on operating results would be less than the amounts shown above because only
between 60 and 70 percent of our pension costs is charged to operations and maintenance expense. The remaining 30 to 40
percent is capitalized to construction accounts as payroll overhead and included in utility plant, which is amortized to expense over
the useful life of the asset placed into service.
Accounting for Income Taxes
We account for income taxes in accordance with SFAS No. 109, “Accounting for Income Taxes,” and Financial
Accounting Standards Board (FASB) Interpretation No. 48 (FIN 48), “Accounting for Uncertainty in Income Taxes,” an
Interpretation of SFAS No. 109, “Accounting for Income Taxes,” which require that deferred tax assets and liabilities be
recognized using enacted tax rates for the effect of temporary differences between the book and tax basis of recorded assets and
liabilities. SFAS No. 109 and FIN 48 also require that deferred tax assets be reduced by a valuation allowance if it is more likely
than not that some portion or all of the deferred tax asset will not be realized. Our net long-term deferred tax liability totaled $257.8
million at December 31, 2008. This liability is estimated based on the expected future tax consequences of items recognized in the
financial statements. After application of the federal statutory tax rate to book income, judgment is required with respect to the
timing and deductibility of expense in our tax returns. For state income tax and other taxes, judgment is also required with respect
to the apportionment among the various jurisdictions. A valuation allowance is recorded if we expect that it is more likely than not
that our deferred tax assets will not be realized. At December 31, 2008, we did not have a valuation allowance due to our
expectation that all of these assets will be realized.
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SFAS No. 109 also requires the recognition of additional deferred income tax assets and liabilities for temporary
differences where regulators require us to flow through deferred income tax benefits or expenses in the ratemaking process of the
regulated utility (regulatory tax assets and liabilities). This is consistent with the ratemaking policies of the OPUC and WUTC.
Regulatory tax assets and liabilities are recorded to the extent we believe they will be recoverable from, or refunded to, customers
in future rates. At December 31, 2008 and 2007, we had regulatory assets representing differences between book and tax basis
related to pre-1981 property of $69.9 million and $68.6 million, respectively, and recorded an offsetting deferred tax liability for
the same amounts (see Note 1, “Income Tax Expense”). We received authorization from the OPUC and WUTC in 2008 to
accelerate the recovery of these pre-1981 regulatory assets through future utility rates (see “Regulatory Accounting,” above, and
Notes 1 and 8).
Contingencies
Loss contingencies are recorded as liabilities when it is probable that a liability has been incurred and the amount of the
loss is reasonably estimable in accordance with SFAS No. 5, “Accounting for Contingencies.” Estimates of loss contingencies,
including estimates of legal defense costs when such costs are probable of being incurred and are reasonably estimable, and related
disclosures are updated when new information becomes available. Estimating probable losses requires an analysis of uncertainties
that often depend upon judgments about potential actions by third parties. Accruals for loss contingencies are recorded based on
an analysis of potential results. When information is sufficient to estimate only a range of potential liabilities, and no point within the
range is more likely than any other, we recognize an accrued liability at the low end of the range and disclose the range (see
“Contingent Liabilities,” below). It is possible, however, that the range of potential liabilities could be significantly different than
amounts currently accrued and disclosed, with the result that our financial condition and results of operations could be materially
affected by changes in the assumptions or estimates related to these contingencies.
With respect to environmental liabilities and related costs we develop estimates based on a review of information available
from recently completed studies and negotiations involving several sites. Using sampling data, feasibility studies, existing technology
and enacted laws and regulations, we estimate that the total future expenditures for environmental investigation, monitoring and
remediation are $35.9 million as of December 31, 2008. It is our policy to accrue the full amount of such liability when information
is sufficient to reasonably estimate the amount of probable liability. When information is not available to reasonably estimate the
probable liability, or when only the range of probable liabilities can be estimated and no amount within the range is more likely than
another, then it is our policy to accrue at the lower end of the range. Accordingly, due to numerous uncertainties surrounding the
course of environmental remediation and the preliminary nature of several site investigations, the range of potential loss beyond the
amounts currently accrued, and the probabilities thereof, cannot be reasonably estimated. Therefore, we have recorded the
liabilities at an amount that reflects the most likely estimate or the low end of the range.
We will continue to seek recovery of such costs through insurance and through customer rates, and we believe recovery
of these costs is probable. If it is determined that both the insurance recovery and future rate recovery of such costs are not
probable, the costs will be charged to expense in the period such determination is made (see Note 12).
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Results of Operations
Regulatory Matters
Regulation and Rates
We are subject to regulation with respect to, among other matters, rates and systems of accounts by the OPUC, WUTC
and FERC. The OPUC and WUTC also regulate our issuance of securities. In 2008, approximately 90 percent of our utility gas
volumes were delivered to, and utility operating revenues were derived from, Oregon customers and the balance from Washington
customers. Future earnings and cash flows from utility operations will be determined largely by the Oregon and Washington
economies in general, and by the pace of growth in the residential and commercial markets in particular, and by our ability to
remain price competitive, control expenses, and obtain reasonable and timely regulatory recovery for our utility gas costs, operating
and maintenance costs and investments made in utility plant.
General Rate Cases
Oregon. In our most recent general rate increase in Oregon, which was effective September 1, 2003, the OPUC
authorized rates to customers based on a return on shareholders’ equity (ROE) of 10.2 percent. In 2007, in connection with the
renewal of our conservation tariff and weather normalization rate mechanism, the OPUC approved a stipulation that restricts us
from filing a general rate case with the OPUC prior to September 1, 2011, subject to certain exceptions. Under the agreement, we
would be allowed to file a general rate case if an extraordinary event occurs or significant investments are required on behalf of our
customers and we are unable to reach agreement regarding alternative forms of cost recovery outside of a general rate case. These
exceptions might include additional investments in our pipeline integrity management program. This agreement does not impact our
ability to file annual rate adjustments to reflect changes in gas purchase costs under our PGA mechanism or our ability to collect or
refund prior year’s gas cost deferrals. See “Rate Mechanisms—Purchased Gas Adjustment,” below.
Washington. In December 2008, an all-party stipulated agreement regarding our Washington general rate case was
approved by the WUTC. As part of the stipulation, the WUTC authorized rates to our customers based on a ROE of 10.1
percent, which was consistent with a rate of return on total long-term capitalization of 8.4 percent. These new customer rates went
into effect on January 1, 2009. Under these new rates, our annual revenue requirements will increase by approximately $2.7
million, or 3 percent. Although we agreed not to file another general rate case in Washington before January 2010, the parties
agreed that we may file separately for a decoupling mechanism upon completion of a trial program currently being conducted by
another utility, which is expected to be completed during 2009.
Federal. We are required under our Mist interstate storage certificate authority and rate approval orders to file every
three 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. We filed a cost and revenue study and an associated petition for rate approval in April 2008. As a result
of that proceeding, the current maximum cost-based rates for our interstate gas storage services were approved by FERC in
August 2008, with our maximum rates unchanged from the levels approved by FERC in 2005. The maximum cost-based rates are
designed to reflect updated costs related to the further development of the Mist gas storage facility from 2005 to
2008. Additionally, we made a filing
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in December 2008 to obtain FERC approval to revise the depreciation rates associated with Mist assets used to derive the costbased interstate storage rates. In that proceeding, which is currently pending, we are requesting FERC approval to revise the
depreciation rates used for the Mist interstate storage services to match the depreciation rates for the same assets that were
recently adjusted under state regulation. We do not expect the approval of these new depreciation rates to have a material impact
on our maximum rates approved by FERC, or any immediate impact on the actual rates currently charged to interstate storage
customers.
Rate Mechanisms
Purchased Gas Adjustment. Rate changes are established each year under PGA mechanisms in Oregon and
Washington to reflect changes in the expected cost of natural gas commodity purchases, including contractual arrangements to
hedge the purchase price with financial derivatives, interstate pipeline demand charges, the application of temporary rate
adjustments to amortize balances in deferred regulatory accounts and the removal of temporary rate adjustments effective for the
previous year.
In October 2008, the OPUC and WUTC approved rate changes effective on November 1, 2008 under our PGA
mechanisms. The effect of the rate changes was to increase the average monthly bills of Oregon residential customers by 14
percent and those of Washington residential customers by 21 percent.
Additionally, in October 2008, the OPUC approved changes to our PGA incentive sharing mechanism. Under the
Oregon PGA mechanism, we collect an amount for purchased gas costs based on estimates included in rates. If the actual
purchased gas costs differ from the estimated amounts included in rates, then we are required to defer that difference and pass it on
to customers as an adjustment to future rates. Under the prior Oregon PGA incentive sharing mechanism effective through
October 31, 2008, 67 percent of the difference was to be deferred such that the impact on current earnings is either a charge to
expense for 33 percent of the higher cost of gas sold, or a credit to expense for 33 percent of the lower purchased gas costs.
Under the new Oregon PGA incentive sharing mechanism, effective November 1, 2008, we are required to select, by
August 1 of each year, either an 80 percent deferral or 90 percent deferral of higher or lower gas costs such that the impact on
current earnings from the gas cost sharing is either 20 percent or 10 percent, respectively. As was the case under the prior
mechanism, we will be subject to an annual earnings review to evaluate the utility’s financial performance. Under both the prior and
the new sharing mechanism, if earnings exceed a threshold level, then 33 percent of the amount above the threshold will be deferred
for future refund to customers. Under the prior Oregon PGA incentive mechanism, effective through the end of October 2008, the
deferral was 67 percent of gas cost differences and the threshold level was equal to our authorized ROE of 10.2 percent plus 300
basis points. Under the new mechanism, if we select the 80 percent deferral, we retain all of our earnings up to 150 basis points
above the currently authorized ROE, or if we select the 90 percent deferral, we retain all of our earnings up to 100 basis points
above the currently authorized ROE. For the PGA year in Oregon beginning on November 1, 2008, we selected the 80 percent
deferral of gas cost differences. The earnings threshold is currently subject to adjustment up or down each year depending on
movements in long-term interest rates.
In 2008 and 2007, the earnings threshold after adjustment for long-term interest rates was 13.1 percent and 13.4 percent,
respectively. No amounts were required to be refunded to customers as a
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result of the 2007 earnings review, and we do not expect that any amounts will be required to be refunded to customers as a result
of the 2008 earnings review, which will be approved by the OPUC during the second quarter of 2009. There has been no change
to the Washington PGA mechanism under which we defer 100 percent of the higher or lower actual purchased gas costs and pass
that difference through to customers as an adjustment to future rates.
Conservation Tariff. In October 2002, the OPUC authorized the implementation of a “conservation tariff,” which is a
rate mechanism designed to adjust margin for changes in consumption patterns due to residential and commercial customers’
conservation efforts. The tariff is a decoupling mechanism that is intended to break the link between utility earnings and the quantity
of gas consumed by customers, removing any financial incentive by the utility to discourage customers’ conservation efforts. In
Washington, customer use is not covered by a conservation tariff, and as such our utility earnings are affected by increases and
decreases in usage based on customers’ conservation efforts. Washington customers account for about 10 percent of our utility
revenues.
The Oregon conservation tariff includes two components: (1) a price elasticity adjustment, which adjusts rates annually for
increases or decreases from expected customer volumes due to annual changes in commodity costs or periodic changes in our
general rates; and (2) a conservation adjustment calculated on a monthly basis to account for the difference between actual and
expected volumes (also referred to as the decoupling adjustment). The margin adjustment resulting from differences between actual
and expected volumes under the decoupling component is recorded to a deferral account, which is included in the next year’s
annual PGA filing. Baseline consumption was determined by customer consumption data used in the 2003 Oregon general rate
case and is adjusted annually for customer growth and the effect of the price elasticity adjustment discussed above. See “Results of
Operations—Comparison of Gas Distribution Operations,” below.
In 2005, an independent study to measure the effectiveness of Oregon’s conservation tariff mechanism recommended
continuation of the tariff with minor modifications, which the OPUC approved. In September 2007, the OPUC extended our
conservation tariff through October 2012.
Weather Normalization. In Oregon, the OPUC approved our use of a weather normalization mechanism through
October 2012. 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 our residential and commercial
customers’ bills between December 1 and May 15 of each heating season. The mechanism adjusts the margin component of
customers’ rates to reflect average weather, which uses the 25-year average temperature for each day of the billing period. Daily
average temperatures and 25-year average temperatures are based on a set point temperature of 59 degrees Fahrenheit for
residential customers and 58 degrees Fahrenheit for commercial customers (see “Comparison of Gas Distribution Operations,”
below). We do not have a weather normalization mechanism approved for our Washington customers, which account for about 10
percent of our utility revenues.
Regulatory and Insurance Recovery for Environmental Costs. In May 2003, the OPUC approved our request to
defer unreimbursed environmental costs associated with certain named sites including those described in Note 12. Beginning in
2006, the OPUC authorized us to accrue interest on deferred environmental cost balances, subject to an annual demonstration that
we have maximized our insurance recovery or made substantial progress in securing insurance recovery for unrecovered
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environmental expenses. Through a series of extensions, this authorization has been extended through January 25, 2009. We have
requested another extension through January 2010, and that request is currently pending. See Note 12.
Industrial Tariffs. In August 2006, the OPUC and WUTC approved tariff changes to the service options for our major
industrial customers. The changes set forth additional parameters that give us more certainty in the level of gas supplies we will need
to acquire to serve this customer group. The parameters include an annual election period, special pricing provisions for out-ofcycle changes and a requirement that customers on our annual weighted average cost of gas tariff complete the term of their service
election.
System Integrity Program. In July 2004, the OPUC approved specific accounting treatment and cost recovery for our
transmission pipeline integrity management program, a program mandated by the Pipeline Safety Improvement Act of 2002 and the
related rules adopted by the U.S. Department of Transportation’s Pipeline and Hazardous Materials Safety Administration. We
record these costs as either capital expenditures or regulatory assets, accumulate the costs over each 12 months ending
September 30, and recover the costs, subject to audit, through rate changes effective with the annual PGA in Oregon. The rate
treatment for these costs expired on September 30, 2008. In February 2009, the OPUC approved a stipulated agreement to
create a new, consolidated system integrity program (SIP). The new SIP would integrate the older and the proposed programs into
a single program. The SIP also includes a component for a proposed distribution integrity management program, which will be
implemented following issuance of new federal regulations. Costs will be tracked into rates annually, with recovery to be sought
after the first $3.3 million of capital costs which are our responsibility. An annual cap for expenditures will be approximately $12
million, with any extraordinary costs above the cap to be approved with written consent of all parties.
The SIP applies to costs incurred in Oregon during the period from October 2008 to October 2011, or until the effective
date of new rates adopted in the company’s next general rate case. We do not have any special accounting or rate treatment for
pipeline integrity costs incurred in the state of Washington.
AMR Deferral Application. In 2006, we automated the reading of gas meters on approximately one-third of our
customers’ meters. In 2008, we initiated a project to automate the reading of gas meters for our remaining customers. The capital
cost of our AMR project is estimated to be $30 million, and in January 2009 we filed for approval to defer the costs associated
with the AMR project. This request is pending before the OPUC. If the request for deferral accounting is approved, we will then
seek approval to recover the deferred costs in our next PGA filing.
Depreciation Study. In December 2008, the OPUC and WUTC approved our filed depreciation study and our request
to change the amortization of our regulatory asset account balance on pre-1981 plant. These approvals specifically authorized the
implementation of new depreciation rates in Oregon and Washington, with corresponding decrease to customer rates effective
January 1, 2009. The new amortization rates on pre-1981 plant, with a corresponding increase to customer rates, became effective
January 1, 2009 in Washington and will be effective November 1, 2009 in Oregon. The implementation of these new rates will
have the effect of decreasing depreciation expense and increasing effective income tax expense rates, both of which will be offset
by a corresponding change in utility operating revenues. In addition, in December 2008 we filed our depreciation study with FERC
requesting approval to apply these same new depreciation rates for our gas storage business assets. If approved, we expect the
new depreciation rates to be effective as of January 1, 2009. Our FERC filing is currently pending.
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Business Segments - Utility Operations
Our utility margin results are affected by customer growth and to a certain extent by changes in weather and customer
consumption patterns, with a significant portion of our earnings being derived from natural gas sales to residential and commercial
customers. In Oregon, we have a conservation tariff that adjusts revenues to offset changes in margin resulting from increases or
decreases in residential and commercial customer consumption. We also have a weather normalization mechanism that adjusts
customer bills up or down to offset changes in margin resulting from above- or below-average temperatures during the winter
heating season (see “Results of Operations—Regulatory Matters—Rate Mechanisms,” above). Both mechanisms are designed to
reduce the volatility of our utility earnings.
2008 compared to 2007:
Total utility margin decreased $14.3 million or 4 percent in 2008 compared to 2007 even though residential and
commercial customers contributed an additional $7.1 million to margin in 2008, including the effects of the weather normalization
and decoupling mechanisms. Total utility volumes sold and delivered in 2008 increased by 4 percent over last year due to the
colder than average weather and 1.6 percent customer growth. The major factors contributing to the decline in utility margin were
the $17.6 million swing in our regulatory share of higher gas costs, a $4.2 million decrease in regulatory adjustments for income
taxes paid and a $1.6 million decrease in margin from industrial customers due to weaker economic conditions.
Our weather normalization mechanism offset residential and commercial margin gains by $15.3 million for the year ended
December 31, 2008 based on weather that was 7 percent colder than average, compared to an offset increased residential and
commercial margins of $2.5 million for the year ended December 31, 2007 based on weather that was 3 percent colder than
average. Our decoupling mechanism offset $4.9 million of residential and commercial margin losses in 2008, after adjusting for
price elasticity in the annual Oregon PGA filing, compared to a margin increase of $0.5 million in 2007.
2007 compared to 2006:
Total utility margin increased $24.6 million or 8 percent in 2007 compared to 2006 with residential and commercial
customers contributing an additional $9.7 million to margin in 2007, including the effects of the weather normalization and
decoupling mechanisms. The $1.0 million decrease in margin from industrial customers in 2007 was partially offset by a decrease in
other margin adjustments from regulatory deferrals and amortizations and miscellaneous fees. Total utility volumes sold and
delivered in 2007 were about the same as in 2006. An increase in our regulatory share of gas cost savings of $4.0 million and a
regulatory adjustment related to income taxes paid of $6.0 million also contributed to the increase in margin (see “Regulatory
Adjustment for Income Taxes Paid,” and “Cost of Gas Sold,” below).
Our weather normalization mechanism offset residential and commercial margin gains by $2.5 million for the year ended
December 31, 2007 based on weather that was 3 percent colder than average, compared to an increase of $2.3 million in added
margin for the year ended December 31, 2006 based on weather that was 4 percent warmer than average. The decoupling
mechanism added $0.5 million to residential and commercial margin in 2007, after adjusting for price elasticity in the annual Oregon
PGA filing, compared to a margin decrease of $2.6 million in 2006.
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The following table summarizes the composition of gas utility volumes and revenues for the years ended December 31,
2008, 2007 and 2006:
Thousands except degree day and
customer data
Utility volumes - therms:
Residential sales
Commercial sales
Industrial - firm sales
Industrial - firm transportation
Industrial - interruptible sales
Industrial - interruptible transportation
Total utility volumes sold and delivered
Utility operating revenues-dollars:
Residential sales
Commercial sales
Industrial - firm sales
Industrial - firm transportation
Industrial - interruptible sales
Industrial - interruptible transportation
Regulatory adjustment for income taxes paid (1)
Other revenues
Total utility operating revenues
Cost of gas sold
Revenue taxes
Utility net operating revenues (utility
margin)
Favorable/(Unfavorable)
2008
2007
vs. 2007
vs. 2006
2008
2007
2006
428,787
265,531
47,340
184,832
87,484
246,777
1,260,751
398,960
249,659
52,340
161,790
89,128
263,092
1,214,969
382,665
242,683
66,971
150,153
112,736
237,441
1,192,649
$ 566,840
298,943
46,579
6,370
68,978
7,918
1,760
21,784
1,019,172
656,504
25,072
$ 555,312
298,800
54,567
5,927
74,876
8,264
5,996
12,228
1,015,970
639,094
25,001
$ 536,468
290,666
66,986
4,901
93,107
7,899
—
161
1,000,188
648,081
24,840
$
11,528
143
(7,988)
443
(5,898)
(346)
(4,236)
9,556
3,202
(17,410)
(71)
$
18,844
8,134
(12,419)
1,026
(18,231)
365
5,996
12,067
15,782
8,987
(161)
$ 337,596
$ 351,875
$ 327,267
$
(14,279)
$
24,608
$ 224,683
90,402
29,771
6,381
(5,505)
436
346,168
(15,266)
4,934
1,760
$ 337,596
$ 213,698
85,960
31,333
4,966
12,135
(229)
347,863
(2,496)
512
5,996
$ 351,875
$ 204,951
83,334
32,383
4,333
8,083
(5,473)
327,611
2,282
(2,626)
—
$ 327,267
$
10,985
4,442
(1,562)
1,415
(17,640)
665
(1,695)
(12,770)
4,422
(4,236)
(14,279)
$
8,747
2,626
(1,050)
633
4,052
5,244
20,252
(4,778)
3,138
5,996
24,608
29,827
15,872
(5,000)
23,042
(1,644)
(16,315)
45,782
16,295
6,976
(14,631)
11,637
(23,608)
25,651
22,320
(2)
Utility margin:
Residential sales
Commercial sales
Industrial - sales and transportation
Miscellaneous revenues
Gain (loss) from gas cost incentive sharing
Other margin adjustments
Margin before regulatory adjustments
Weather normalization mechanism
Decoupling mechanism
Regulatory adjustment for income taxes paid (1)
Utility margin
Customers - end of period:
Residential customers
Commercial customers
Industrial customers
Total number of customers - end of period
Actual degree days
Percent colder (warmer) than average (3)
599,285
62,115
941
662,341
589,676
61,397
939
652,012
575,116
60,523
945
636,584
4,576
4,374
4,089
7%
3%
$
9,609
718
2
10,329
$
14,560
874
(6)
15,428
(4%)
(1)
Regulatory adjustment for income taxes paid is the result of the implementation of the utility regulation as described below under “Regulatory
Adjustment for Income Taxes Paid.”
(2)
Amounts reported as margin for each category of customers are net of demand charges and revenue taxes.
(3)
Average weather represents the 25-year average degree days, as determined in our last Oregon general rate case.
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Residential and Commercial Sales
Residential and commercial sales are impacted by customer growth, seasonal weather patterns, energy prices, competition
from other energy sources and economic conditions in our service areas. Typically, 80 percent or more of our annual utility
operating revenues are derived from gas sales to weather-sensitive residential and commercial customers. Although variations in
temperatures between periods will affect volumes of gas sold to these customers, the effect on margin and net income is significantly
reduced due to our weather normalization mechanism in Oregon where about 90 percent of our customers are served. Beginning in
2006, this mechanism became effective for the period from December 1 through May 15 of each heating season. Approximately
10 percent of our eligible Oregon customers have opted out of the mechanism. In Oregon, we also have a conservation decoupling
mechanism that is intended to break the link between our earnings and the quantity of gas consumed by our customers, so that we
do not have an incentive to encourage greater consumption contrary to customers’ energy conservation efforts. In Washington,
where the remaining approximately 10 percent of our customers are served, we do not have a weather normalization or a
conservation decoupling mechanism. As a result, we are not fully insulated from earnings volatility due to weather and conservation.
The primary factors that impact results of operations in the residential and commercial markets are customer growth,
seasonal weather patterns, competition from other energy sources and economic conditions in our service territory.
2008 compared to 2007:
•
•
•
operating revenues increased 1 percent due to a 7 percent increase in volumes, partially offset by lower customer
rates of 8 to 10 percent over the first 10 months of 2008;
volumes were 7 percent higher, primarily reflecting 1.6 percent customer growth and 5 percent colder weather; and
margin was 2 percent higher, reflecting increased volumes from customer growth and from colder weather for
customers not covered by weather normalization (see “Cost of Gas Sold,” below).
2007 compared to 2006:
•
•
•
operating revenues increased 3 percent, primarily due to a 4 percent increase in volumes;
volumes were 4 percent higher, primarily reflecting 2.4 percent customer growth and 7 percent colder weather; and
margin before regulatory adjustments for weather normalization, decoupling and income taxes paid was 4 percent
higher, reflecting increased volumes from customer growth and higher gas cost savings from our PGA incentive sharing
mechanism in Oregon (see “Cost of Gas Sold,” below).
Industrial Sales and Transportation
Industrial operating revenues include the commodity cost component of gas sold under sales service but not to
transportation service. Therefore, industrial customer switching between sales service and transportation service can cause swings
in operating revenues but generally our margins are not affected because we do not mark up the cost of gas. As such, we believe
margin is a better
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measure of performance for the industrial sector. The primary factors that impact results of operations in industrial sales and
transportation markets are as follows:
2008 compared to 2007:
•
•
•
operating revenues decreased $13.8 million, or 10 percent, due to a transfer of customer volumes from sales service
to transportation and to lower sales rates during the first 10 months in 2008;
volumes delivered to industrial customers increased 0.1 million therms, or less than 1 percent, reflecting a reduction in
sales volumes of 6.6 million therms offset by an increase in transportation volumes of 6.7 million therms; and
margin decreased $1.6 million, or 5 percent, reflecting a shift in margin from higher margins to lower margin rate
schedules and from customers that reduced their usage due to the current economic environment, but this decrease
was partially offset by a margin gain of $0.8 million from curtailment charges for use by a small number of industrial
customers during cold weather.
2007 compared to 2006:
•
•
•
operating revenue decreased $29.3 million, or 17 percent, due to customers transferring from sales service to
transportation service where cost of gas is not a component in operating revenues;
volumes delivered to industrial customers decreased 1.0 million therms, or less than 1 percent, reflecting a reduction in
sales volumes of 38.2 million therms offset by an increase in transportation volumes of 37.3 million therms; and
margin decreased 3 percent, reflecting higher volumes under lower margin special contracts.
Several large industrial customers transferred from sales service back to transportation service in 2008. High natural gas
prices can result from time to time in a number of our large industrial customers switching from transportation service, where they
arrange for their own supplies through independent third parties, to sales service, where we sell them the gas commodity under
regulatory tariffs. In such cases, our tariff requires us to charge the incremental cost of gas supply incurred to serve those
customers.
Regulatory Adjustment for Income Taxes Paid
The Oregon legislature passed legislation, effective January 1, 2006, to ensure that regulated utility operations do not
collect in rates more money for income taxes than the utility actually pays to taxing authorities. Under this legislation, if we pay less
in income taxes than we collect from our Oregon utility customers, or if our consolidated taxes paid are less than the taxes we
collect from our Oregon utility customers, then we are required to record a refund due to our Oregon utility customers. Conversely,
if we pay more income taxes than we actually collect from our Oregon utility customers, as set forth under our most recent general
rate case, then we are required to record a surcharge due from our Oregon utility customers.
For the 2006 tax year, we filed to recover $1.7 million through a surcharge to our Oregon utility customers. This
surcharge was primarily driven by higher income taxes paid on gains from gas cost savings from our PGA incentive sharing
mechanism in 2006 and strong operating results. The OPUC
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approved our filing, and we collected a total of $1.9 million, representing a surcharge of $1.7 million plus accrued interest of $0.2
million, from customers in June 2008. For the 2007 tax year, we filed to recover $5.5 million through a surcharge to our Oregon
utility customers. We have reached an agreement in principle with OPUC Staff and other parties on that surcharge and are in the
process of finalizing a stipulation and supporting documentation. We expect to collect a total of $6.4 million, representing a
surcharge of $5.5 million plus accrued interest of $0.9 million. Again, this surcharge was primarily driven by higher income taxes
paid on gains from gas cost savings from our PGA incentive mechanism in 2007. For the 2008 tax year, we anticipate that the
difference between income taxes paid and the amounts collected in rates will be less than $100,000, and in accordance with the
rules, we have not recorded any adjustment for this year. However, in 2008 we recognized a combined adjustment for the 2006
and 2007 tax years of $1.8 million, based on revised estimates of our 2006 and 2007 tax surcharges, representing $1.2 million plus
accrued interest of $0.6 million.
Other Revenues
Other revenues include miscellaneous fee income as well as revenue adjustments reflecting deferrals to, or amortizations
from, regulatory asset or liability accounts other than deferrals relating to gas costs. Other revenues increased net operating
revenues by $21.8 million in 2008, compared to $12.2 million in 2007 and $0.2 million in 2006.
2008 compared to 2007:
Other revenues in 2008 were $9.6 million higher than in 2007 primarily due to a $10.5 million refund to utility customers
for the gas storage sharing mechanism revenues, partially offset by a $1.9 million surcharge for our rate adjustment for income taxes
paid.
2007 compared to 2006:
Other revenues in 2007 were $12.1 million higher than in 2006 primarily due to a $3.1 million increase in deferrals under
the decoupling mechanism (see “Results of Operations—Regulatory Matters—Rate Mechanisms,” above), a $6.1 million decrease
in amortization expense related to the decoupling deferrals from prior periods, a $1.7 million increase in interstate gas storage
credits to customers reflecting higher regulatory sharing of net income from storage operations and a decrease of $1.3 million in
amortization expense related to demand side management deferrals.
Cost of Gas Sold
The cost of gas sold includes current gas purchases, gas drawn from storage inventory, gains and losses from commodity
hedges, pipeline demand charges, seasonal demand cost balancing adjustments, regulatory gas cost deferrals and company gas use.
Our regulated utility does not generally earn a profit or incur a loss on gas commodity purchases. The OPUC and the WUTC
require the natural gas commodity cost to be billed to customers at the same cost incurred or expected to be incurred by the utility.
However, under the PGA mechanism in Oregon, our net income is affected by differences between actual and expected purchased
gas costs primarily due to market fluctuations and volatility affecting unhedged purchases (see “Results of Operations—Regulatory
Matters—Rate Mechanisms—Purchased Gas Adjustment,” above). We use natural gas derivatives, primarily fixed-price
commodity swaps, under the terms of our financial derivatives policies to help manage our exposure to rising gas prices. Gains and
losses from financial hedge contracts are generally included in our PGA prices and normally do not impact net income as the
hedges are usually 100 percent passed
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through to customers in annual rate changes, subject to a regulatory prudency review. However, utility gas hedges entered into after
the annual PGA filing in Oregon may impact net income to the extent of our share of any gain or loss under the PGA. In
Washington, 100 percent of the actual gas costs, including hedge gains and losses, are passed through in customer rates (see
“Application of Critical Accounting Policies and Estimates—Accounting for Derivative Instruments and Hedging Activities,” and
“Results of Operations—Regulatory Matters—Rate Mechanisms—Purchased Gas Adjustment,” above, and Note 11).
2008 compared to 2007:
•
•
•
total cost of gas sold increased $17.4 million or 3 percent;
the average cost of gas sold decreased 2 percent from 81 cents per therm in 2007 to 79 cents in 2008, primarily
reflecting our 8 to 10 percent PGA rate decreases effective November 1, 2007 and our 14 to 21 percent increases
effective November 1, 2008; and
net gains of $35.1 million were realized from our financial hedges and included in cost of gas sold, compared to $42.0
million of net losses in 2007.
2007 compared to 2006:
•
•
•
total cost of gas sold decreased $9.0 million or 1 percent;
the average cost of gas sold remained at 81 cents per therm; and
net losses of $42.0 million were realized from our financial hedges, compared to $20.0 million of net losses in 2006.
For the year ended December 31, 2008, our actual gas costs were higher than the gas costs embedded in rates, while
during the same period in 2007 and 2006 our actual gas costs were significantly lower than gas costs embedded in rates. The effect
on shareholders from the gas cost incentive sharing was a margin gain of $12.1 million and $8.1 million in 2007 and 2006,
respectively, compared to a margin loss of $5.5 million in 2008. For a discussion of the change in our Oregon gas cost sharing
incentive mechanism, effective November 1, 2008, see “Results of Operations—Regulatory Matters—Rate Mechanisms—
Purchased Gas Adjustment,” above.
Business Segments Other than Utility Operations
Gas Storage
Our gas storage segment primarily consists of the non-utility portion of our Mist underground storage facility, asset
optimization and Gill Ranch. In 2008, we earned $8.4 million, or 31 cents per share, from our gas storage business segment, after
regulatory sharing and income taxes. This compares to net income of $8.5 million, or 32 cents per share, in 2007 and $6.0 million,
or 21 cents per share, in 2006. Earnings in 2008 and 2007 were higher than 2006 primarily because of increased revenues from
additional contract storage and higher margins from optimization services under a contract with an independent energy marketing
company.
In Oregon, we retain 80 percent of the pre-tax income from gas storage services as well as from optimization services
when the costs of the capacity being used is not included in utility rates, or 33 percent of the pre-tax income from such storage and
optimization services when the capacity being used is included in utility rates. The remaining 20 percent and 67 percent,
respectively, are credited to a deferred regulatory account for refund to our core utility customers. We have a similar sharing
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mechanism in Washington for pre-tax income derived from gas storage and optimization services. We are currently in the process
of developing a second underground storage facility, Gill Ranch, and related pipeline near Fresno, California. Our Gill Ranch
project is expected to serve the California and west coast market. See Note 2.
Other
Our other business segment consists of Financial Corporation, an equity investment in Palomar and other non-utility
investments and business activities. Financial Corporation’s equity balance as of December 31, 2008 and 2007 was $1.3 million
and $1.4 million, respectively, and our equity balance in the proposed Palomar transmission pipeline was $14.2 million and $6.0
million, respectively. In 2008 and 2007, we sold the last of our non-core assets, resulting in after-tax gains of $1.1 million and $0.9
million, respectively. The remaining investment balance at Financial Corporation reflects a non-controlling interest in the Kelso
Beaver pipeline. The current equity balance in Palomar reflects our investment to date in a proposed 217-mile transmission
pipeline.
Net income from our other business segment for the years ended December 31, 2008, 2007 and 2006 was $2.4 million,
$1.1 million and $0.8 million, respectively. The increase in 2008 compared to 2007 reflects the gain on sale of our investment in a
Boeing 737-300 aircraft and income from our equity investment in Palomar. The increase in 2007 over 2006 reflects the sale of our
limited partnership interest in two wind power electric generation projects in California. See Note 2.
Consolidated Operations
Operations and Maintenance
Operations and maintenance expenses decreased by $7.1 million in 2008, or 6 percent, compared to 2007. In 2007
operations and maintenance expense included additional costs for strategic initiatives. Operations and maintenance expense
increased $5.9 million in 2007, or 5 percent, compared to 2006, also reflecting higher expenditures for strategic initiatives in 2007.
The following summarizes the major factors that contributed to changes in operations and maintenance expense:
2008 compared to 2007:
•
•
a $4.3 million decrease due to additional costs incurred in 2007 for strategic initiatives including maintenance projects,
training and promotional and safety campaigns; and
a $5.6 million decrease in employee compensation and benefit expense, primarily due to lower bonuses related to
lower operating results which affected annual and long-term incentives.
Partially offsetting the above decreases were:
•
•
a $2.0 million increase in costs related to serving a growing customer base and increased operating expenses during
the December cold weather episode; and
a $0.2 million, or 6 percent, increase in uncollectible expense reflecting higher revenues due to rate increases and sales
volume increases. Delinquent account balances were $0.1 million higher than last year, compared to a $36.5 million,
or 25 percent, increase in accounts receivable and unbilled revenues. Our bad debts as a percent of revenues
remained consistent with 2007 at 0.3 percent.
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2007 compared to 2006:
•
•
•
•
a $3.8 million increase in employee compensation and benefit expense, primarily due to bonuses related to improved
financial and operating results on annual and long-term incentive plan performance goals;
a $1.9 million increase in costs for maintenance projects and geo-hazard repairs;
a $0.9 million increase in training, maintenance and telecommunication expenses related to the implementation of the
first phase of a new integrated information system; and
a $0.3 million increase in start up expenses for the Smart Energy program.
Partially offsetting the above increases was:
•
a $1.5 million decrease in severance expenses.
General Taxes
General taxes, which are principally comprised of property and payroll taxes and regulatory fees, increased $1.4 million,
or 5 percent, in 2008 compared to 2007, and increased $0.9 million, or 4 percent, in 2007 compared to 2006. The major factors
that contributed to changes in general taxes are:
2008 compared to 2007:
•
a $1.3 million increase in property taxes related to higher tax rates and increased utility plant balances.
2007 compared to 2006:
•
•
•
a $0.4 million increase in property taxes related to a 3 percent increase in utility plant balances;
a $0.3 million increase in regulatory fees based on higher gross operating revenue; and
a $0.2 million increase in other taxes due to an increase in the annual fee to the Oregon Department of Energy.
We have been involved in litigation with the Oregon Department of Revenue (ODOR) over whether natural gas
inventories and appliance inventories held for resale are required to be taxed as personal property. In November 2007, the Oregon
Tax Court ruled in our favor stating that these inventories were exempt from property tax. However, the ODOR appealed the
judgment to the Oregon Supreme Court in August 2008. If we are successful in this litigation, we would be entitled to a refund of
over $5.0 million for property taxes paid on inventories beginning with the 2002-2003 tax year, plus accrued interest. Due to the
uncertain outcome of the proceeding, we have not recorded the recovery of property taxes paid on gas inventories or appliance
inventories to recognize the potential gain contingency.
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Depreciation and Amortization
The following table summarizes the increases in total plant and property and total depreciation and amortization for the
three years ended December 31:
Thousands, except percentages
Plant and property:
Utility plant:
Depreciable
Non-depreciable, including construction work in progress
Non-utility property:
Depreciable
Non-depreciable, including construction work in progress
Total plant and property
Depreciation and amortization:
Utility plant
Non-utility property
Total depreciation and amortization expense
2008
2007
2006
$2,101,900
41,088
2,142,988
$2,013,191
38,970
2,052,161
$1,925,837
37,661
1,963,498
62,882
11,624
74,506
$2,217,494
56,444
10,705
67,149
$2,119,310
36,952
5,700
42,652
$2,006,150
$
$
$
$
70,691
1,468
72,159
$
67,410
933
68,343
$
63,552
883
64,435
Average depreciation rate - utility
3.4%
3.4%
3.4%
Average depreciation rate - non-utility
2.5%
2.1%
2.5%
Total depreciation and amortization expense increased by $3.8 million, or 6 percent, in 2008 and by $3.9 million, or 6
percent, in 2007. The increased expense for both years is primarily due to additional investments in utility plant to meet continuing
customer growth and to make system improvements (see “Financial Condition—Cash Flows—Investing Activities,” below, and
Note 9). New depreciation rates were approved by the OPUC and WUTC, effective January 1, 2009 (see “Regulatory
Matters—Rate Mechanisms—Depreciation Study,” above).
Other Income and Expense—Net
The following table provides details on other income and expense – net for the last three years:
Thousands
Gains from company-owned life insurance
Interest income
Income from equity investments
Net interest on deferred regulatory accounts
Gain on sale of investments
Other
Total other income and expense - net
2008
$ 2,190
250
667
552
1,737
(1,650)
$ 3,746
2007
$ 1,939
537
130
84
1,544
(2,789)
$ 1,445
2008 compared to 2007:
Other income and expense–net increased by $2.3 million in 2008 over 2007. The increase was primarily due to an
increase of $1.1 million in other non-operating income (expense), reflecting the
56
2006
$2,609
363
191
(177)
(852)
$2,134
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additional start-up expenses in 2007 for business development and other strategic initiatives, and by a $0.2 million increase from
gain on sale of investments, reflecting the gains on sales of the aircraft in 2008 and the two wind power electric generation projects
in 2007, and a $0.5 million increase in income from equity investments, primarily related to Palomar.
2007 compared to 2006:
Other income and expense–net declined by $0.7 million in 2007 over 2006. The decline was primarily due to a decrease
of $0.7 million in gains from company-owned life insurance, reflecting lower policy benefits realized during 2007, and a net increase
of $1.9 million in other non-operating expenses, reflecting expenses for business development and other strategic initiatives. These
negative changes were partially offset by an increase in earnings from equity investments of Financial Corporation of $1.5 million,
reflecting the gain on sale of its limited partnership interests in two wind power electric generation projects, and an increase of $0.3
million in net interest charges on deferred regulatory accounts, reflecting lower net credit balances outstanding in these accounts.
Interest Charges—Net of Amounts Capitalized
Interest charges—net of amounts capitalized in 2008 decreased by $0.2 million, or less than 1 percent, compared to
2007, reflecting lower balances on long-term debt outstanding due to the redemption of $5 million of medium-term notes (MTNs)
in July 2008, with increased costs due to higher short-term debt balances offset by lower interest rates on short-term debt. In
2007, interest charges—net of amounts capitalized was $1.4 million, or 4 percent, lower than in 2006, reflecting lower balances on
long-term debt outstanding due to the redemption of $20 million of MTNs in March 2007 and $9.5 million of MTNs in May 2007.
The average interest crediting rate for the allowance for funds used during construction, comprised of short-term and long-term
borrowing rates, as appropriate, was 3.6 percent in 2008, 5.4 percent in 2007 and 4.7 percent in 2006.
Income Tax Expense
The decrease in income tax expense of $3.4 million or 8 percent in 2008, compared to 2007 was primarily due to lower
consolidated earnings and a slightly lower effective tax rate of 36.9 percent in 2008 compared to 37.2 percent in 2007. The
decrease in our effective tax rate was primarily the result of a higher non-taxable gain on company-owned life insurance. Income
tax expense increased by $7.8 million or 22 percent in 2007, as compared to total income tax expense of $36.2 million in 2006,
and the effective tax rate increased slightly from an effective rate of 36.4 percent in 2006. For more information on our income
taxes, including a reconciliation between the statutory federal income tax rate and the effective rate, see Note 1 and Note 8.
Financial Condition
Capital Structure
Our goal is to maintain a strong consolidated capital structure, generally consisting of 45 to 50 percent common stock
equity and 50 to 55 percent long-term and short-term debt. When additional capital is required, debt or equity securities are issued
depending upon both the target capital structure and market conditions. These sources also are used to fund long-term debt
redemption requirements and short-term commercial paper maturities (see “Liquidity and Capital Resources,” below, and Notes 5
and 6). Achieving the target capital structure and maintaining sufficient liquidity to meet operating
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requirements are necessary to maintain attractive credit ratings and have access to capital markets at reasonable costs. Our
consolidated capital structure was as follows:
December 31,
Common stock equity
Long-term debt
Short-term debt, including current maturities of long-term debt
Total
2008
45.3%
36.8%
17.9%
100.0%
2007
47.4%
40.8%
11.8%
100.0%
2006
48.1%
41.5%
10.4%
100.0%
Liquidity and Capital Resources
At December 31, 2008, we had $6.9 million of cash and cash equivalents compared to $6.1 million at December 31,
2007. Short-term liquidity is provided by cash balances, internal cash flow from operations, proceeds from the sale of commercial
paper notes, unsecured credit facilities, including multi-year commitments which are primarily used to back-up commercial paper
(see “Credit Agreement,” below), an ability to borrow from cash surrender value in company-owned life insurance policies, and
proceeds from the sale of long-term debt. We use long-term debt proceeds to finance capital expenditures and refinance maturing
short-term or long-term debt.
Our senior long-term debt ratings are AA- and A2 from S&P and Moody’s, respectively, while our short-term debt
ratings are A-1+ and P-1 from S&P and Moody’s, respectively. The capital markets, including the commercial paper market, have
experienced significant volatility and tight credit conditions in recent months, as reflected by increased spreads and limited access to
new financing. As a result of these market conditions, we delayed a planned fourth quarter 2008 debt issuance until the first quarter
of 2009. In lieu of the delayed debt issuance, we entered into two $15 million bilateral bank lines of credit with maturities of one
and three months, and borrowed from corporate-owned life insurance policies to provide added liquidity. With our current debt
ratings we have been able to issue commercial paper notes at attractive rates and have not had to borrow from our $250 million
back-up facility. In the event that we are not able to issue commercial paper or other debt instruments due to market conditions,
we expect that our liquidity needs can be met by using cash balances or drawing upon our committed credit facility (see “Credit
Agreements,” below). We also have a universal shelf registration statement filed with the Securities and Exchange Commission for
the issuance of secured and unsecured debt or equity securities, market conditions permitting.
In the event that our senior secured long-term debt credit ratings are downgraded below investment grade, our
counterparties under derivative contracts could require us to post cash, a letter of credit or other form of collateral, which could
expose us to additional costs and may trigger significant increases in draws from our borrowing facilities.
Based on our current credit ratings, our experience with issuing commercial paper, our current cash reserves, the
availability and size of our committed credit facilities and our ability to issue long-term debt and equity securities under the universal
shelf registration statement, we believe our liquidity is sufficient to meet our anticipated cash requirements, including the contractual
obligations and investing and financing activities discussed below.
Dividend Policy
We have paid quarterly dividends on our common stock in each year since the stock was first issued to the public in
1951. Annual common dividend payments per share, adjusted for stock splits, have increased each year since 1956. The amount
and timing of dividends payable on our common
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stock is within the sole discretion of our Board of Directors. Our Board of Directors expects to continue paying cash dividends on
common stock on a quarterly basis. However, the declarations and amount of future dividends will be dependent upon our
earnings, cash flows, financial condition and other factors.
Off-Balance Sheet Arrangements
Except for certain lease and purchase commitments (see “Contractual Obligations,” below), we have no material offbalance sheet financing arrangements.
Contractual Obligations
The following table shows our contractual obligations at December 31, 2008 by maturity and type of obligation.
Thousands
Commercial paper
Long-term debt maturities
Interest on long-term debt
Postretirement benefit payments(1)
Capital leases
Operating leases
Gas purchase contracts(2)
Gas pipeline commitments
Other purchase commitments
Total
(1)
(2)
Payments Due in Years Ending December 31,
2009
2010
2011
2012
$ 248,000 $
- $
- $
- $
35,000
10,000
40,000
33,417
33,406
30,858
28,536
26,839
19,126
19,556
20,394
599
461
163
21
4,129
4,127
4,080
4,230
229,804
89,079
34,835
21,277
80,670
61,114
64,175
49,067
53,081
5,154
762
$ 676,539 $ 247,467 $ 164,429 $ 163,525 $
2013
27,625
21,571
4,268
21,277
41,602
116,343
Thereafter
$
427,000
285,432
116,388
26,501
17,731
87,826
$
960,878
Total
248,000
512,000
439,274
223,874
1,244
47,335
414,003
384,454
58,997
$ 2,329,181
$
The majority of postretirement benefit payment obligations are related to our qualified defined benefit pension plans, which are
funded by plan assets and future cash contributions. See Note 7.
All gas purchase contracts use price formulas tied to monthly index prices. Commitment amounts are based on index prices at
December 31, 2008.
Other purchase commitments primarily consist of remaining balances under existing purchase orders. These and other
contractual obligations are financed through cash from operations and from the issuance of short-term debt, which is periodically
refinanced through the sale of long-term debt or equity securities.
Holders of one long-term debt issue have a put option that, if exercised, would require the repurchase of up to $20 million
principal amount in 2009. If repurchased prior to maturity, then the interest obligation shown in the above table would be reduced
in future years. The interest rate on this long-term debt issue with a put option is 6.65 percent.
In February 2008, we extended the term of an agreement with Northwest Pipeline for approximately 350,000 therms per
day of firm transportation capacity from the U.S. Rocky Mountain region through 2044. Also in February 2008, we executed an
agreement with a third party to take
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assignment of their firm transportation contract starting no earlier than 2012 and no later than 2017, with the term extending through
2046. This contract consists of 120,000 therms per day on Northwest Pipeline from the U.S. Rocky Mountain region.
Approximately 700 of our utility employees are members of the Office and Professional Employees International Union,
Local No. 11. These employees are covered by a labor agreement (Joint Accord) with respect to wages, benefits and working
conditions. This Joint Accord will expire on May 31, 2009. Each party has served notice of intent to negotiate the terms of an
agreement prior to the May 31, 2009 expiration date.
Commercial Paper
Our primary source of short-term liquidity is from internal cash flows and the sale of commercial paper notes payable. In
addition to issuing commercial paper to meet seasonal working capital requirements, including the financing of gas inventories and
accounts receivable, short-term debt may be used to temporarily fund 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 Agreement,” below and Note 6). Our commercial paper program did not experience any liquidity disruptions as a
result of the recent credit problems that affected issuers of asset-backed commercial paper and certain other commercial paper
programs. At December 31, 2008 and 2007 we had commercial paper outstanding of $248.0 million and $143.1 million,
respectively (see Note 6). This year’s outstanding balances were higher than last year primarily due to gas cost deferrals associated
with higher gas purchases, higher balances in gas inventories and accounts receivable, commodity hedge payments, and delaying
the issuance of long-term debt.
Credit Agreements
We have a syndicated line of credit for unsecured revolving loans totaling $250 million available and committed for a term
expiring on May 31, 2012, with $210 million of that commitment amount extended through May 31, 2013. Additionally, we
entered into two committed bilateral bank lines of credit totaling $30 million in November 2008, of which $15 million expired
December 31, 2008 and $15 million expired February 27, 2009. The lenders under our syndicated and bilateral credit agreements
are major financial institutions with committed balances and investment grade credit ratings as of December 31, 2008 as follows:
Amount
Committed
(in $000’s)
$
135,000
45,000
85,000
$
265,000
Lender rating, by category
AAA/Aaa
AA/Aa
A/A
BBB/Baa
Total
Based on recent conditions in the credit markets, it is possible that one or more lending commitments could be unavailable
to us if the lender defaulted due to lack of funds or insolvency. However, based on our current assessment of the lenders’
creditworthiness, including a review of capital ratios, credit default swap spreads and credit ratings, we believe the risk of lender
default is minimal.
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Pursuant to the terms of our credit agreement for the syndicated line of credit, we may request maturity extensions for
additional one-year periods subject to lender approval. We extended commitments with six of the seven lenders under the
syndicated credit agreement, with commitments totaling $210 million, to May 31, 2013. The credit agreement also allows us to
request increases in the total commitment amount from time to time, up to a maximum amount of $400 million, and to replace any
lenders who decline to extend the terms of the credit agreement. The credit agreement also permits the issuance of letters of credit
in an aggregate amount up to the applicable total borrowing commitment. Any principal and unpaid interest owed on borrowings
under the credit agreement are due and payable on or before the expiration date. There were no outstanding balances under this
credit agreement at December 31, 2008 and 2007. The credit agreement also requires us to maintain a consolidated indebtedness
to total capitalization ratio of 70 percent or less. Failure to comply with this covenant would entitle the lenders to terminate their
lending commitments and accelerate the maturity of all amounts outstanding. We were in compliance with this covenant at
December 31, 2008 and 2007, with our consolidated indebtedness to total capitalization ratios of 54.7 percent, and 52.7 percent,
respectively.
The credit agreement requires that we maintain credit ratings with S&P and Moody’s and notify the lenders of any change
in our senior unsecured debt ratings by such rating agencies. A change in our debt ratings is not an event of default, nor is the
maintenance of a specific minimum level of debt rating a condition of drawing upon the credit agreement. However, interest rates on
any loans outstanding under the credit agreement are tied to debt ratings, which would increase or decrease the cost of any loans
under the credit agreement when ratings are changed.
Credit Ratings
The table below summarizes our credit ratings from two rating agencies, S&P and Moody’s.
S&P
A-1+
AAA+
Negative
Commercial paper (short-term debt)
Senior secured (long-term debt)
Senior unsecured (long-term debt)
Ratings outlook
Moody’s
P-1
A2
A3
Stable
Both rating agencies have assigned investment grade credit ratings to NW Natural. These credit ratings are dependent
upon a number of factors, both qualitative and quantitative, and are subject to change at any time. The disclosure of these credit
ratings is not a recommendation to buy, sell or hold NW Natural securities. Each rating should be evaluated independently of any
other rating. During the fourth quarter of 2008, our ratings outlook was changed from stable to negative by S&P and from positive
to stable by Moody’s.
Redemptions of Long-Term Debt
We redeemed MTNs during 2008, 2007 and 2006 as follows:
Thousands
Medium-Term Notes
6.05% Series B due 2006
6.31% Series B due 2007
6.80% Series B due 2007
6.50% Series B due 2008
61
Redeemed
in 2008
Redeemed
in 2007
Redeemed
in 2006
$
$
$
5,000
20,000
9,500
-
8,000
-
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Cash Flows
Operating Activities
Year-over-year changes in our operating cash flows are primarily affected by net income, changes in working capital
requirements and other cash and non-cash adjustments to operating results. In 2008, cash flow from net income and operating
activity adjustments, excluding working capital changes, decreased $37.9 million compared to 2007. Working capital changes in
2008 decreased cash flow by $111.0 million compared to 2007. The majority of these working capital changes, particularly those
related to accounts receivable, unbilled revenues inventories, income taxes receivable and accounts payable, will reverse over the
next six months reflecting changes in seasonal working capital. The overall change in cash flow from operating activities in 2008
compared to 2007 was a decrease of $148.9 million. The significant factors contributing to the cash flow changes between 2008
and 2007 are as follows:
2008 compared to 2007:
•
•
•
•
an increase in cash flow of $55.4 million in deferred income taxes and investment tax credits primarily from additional
accelerated depreciation and a net operating loss (see Note 8);
a decrease in cash flows of $84.0 million in deferred gas costs, $30.4 million in accounts payable and a $14.3 million
in inventories, primarily due to the higher gas cost prices in 2008 compared to 2007;
a decrease in cash flow of $20.8 million in income taxes receivable primarily due to bonus depreciation and an
estimate for a future pension contribution, for which we saw an increase in deferred income taxes; and
a decrease in cash flow of $58.5 million in accounts receivable and accrued unbilled revenue due to the colder
weather in December 2008 and our November 1, 2008 rate increase (see Results of Operations—Regulatory
Matters—Rate Mechanisms—Purchased Gas Adjustment,” above).
In December 2008, we filed an application for a change in tax accounting method in connection with routine repairs and
maintenance of gas pipeline that are currently being capitalized and depreciated. We anticipate that the Internal Revenue Service
(IRS) will consent to this change during the first quarter of 2009. If consented to by the IRS, then we expect to claim a deduction
and record current tax benefits that will result in a cash refund of taxes paid. If approved, we estimate the tax refund amount in
2009 for prior years’ taxes paid to be in excess of $15 million related to the routine repairs and maintenance.
In 2007, cash flow from net income and operating activity adjustments, excluding working capital changes, increased by
$23.0 million, primarily due an increase in cash collections from deferred gas costs and improved operating results. Working capital
changes in 2007 increased cash flow by $12.1 million. The overall change in cash flow from operations in 2007 was an increase of
$35.1 million compared to 2006. The significant factors contributing to the cash flow changes between 2007 and 2006 are as
follows:
2007 compared to 2006:
•
an increase in cash of $11.2 million in deferred income taxes and investment tax credits related to a smaller reduction
in 2007 than 2006;
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•
•
•
•
•
an increase in cash of $17.9 million in deferred gas costs and an increase in cash of $27.5 million in accounts payable,
reflecting deferral activity between the two years with respect to purchased gas cost savings and off-system gas sales
under our PGA;
a decrease in cash of $17.5 million due to the change in deferred regulatory and other costs;
an increase in cash of $25.8 million in accounts receivable and accrued unbilled revenue, due to decreased rates in
2007 and weather that was warmer at the end of the year;
a decrease in cash of $13.2 million in income taxes receivable resulting from income tax refunds received during 2006;
and
a decrease in cash of $16.7 million in accrued interest and taxes due to higher cash payments in 2007.
We have lease and purchase commitments relating to our operating activities that are financed with cash flows from
operations (see “Liquidity and Capital Resources—Contractual Obligations,” above and Note 12).
Investing Activities
Cash requirements for investing activities in 2008 totaled $109.8 million, down from $117.5 million in 2007. Cash
requirements for the acquisition and construction of utility plant were $96.6 million in 2008, up slightly from $93.8 million in 2007.
Cash requirements for investments in non-utility property were $7.4 million in 2008, primarily related to investments in Gill Ranch,
compared to $24.4 million in 2007, primarily due to investments made related to the Mist gas storage expansion. Cash used in
other investing activities in 2008 totaled $5.8 million compared to cash collected of $0.7 million in 2007. The change in 2008 is
primarily due to a $7.5 million investment in the Palomar project and a $5.0 million restricted cash balance in Gill Ranch, partially
offset by $6.8 million of proceeds received from the sale of our investment in a Boeing 737-300 aircraft.
Cash requirements for investing activities in 2007 totaled $117.5 million, up from $90.6 million in 2006. Cash
requirements for the acquisition and construction of utility plant were $93.8 million in 2007, down slightly from $95.3 million in
2006. Cash requirements for investments in non-utility property increased to $24.4 million in 2007, compared to $1.8 million in
2006, primarily related to investments in Mist gas storage, Gill Ranch and Palomar.
In 2009, utility capital expenditures are estimated to be between $100 and $110 million, and non-utility capital
investments are expected to be between $50 and $70 million for business development projects that are currently in process (see
“2009 Outlook,” above).
Over the five-year period 2009 through 2013, utility construction expenditures are estimated at between $450 and $500
million. The estimated level of capital expenditures over the next five years reflects continued customer growth, gas storage
development at Mist, technology improvements and utility system improvements, including requirements under the Pipeline Safety
Improvement Act of 2002. Most of the required funds are expected to be internally generated over the five-year period and any
remaining funding will be obtained through the issuance of long-term debt or equity securities, with short-term debt providing
liquidity and bridge financing.
Financing Activities
Cash provided by financing activities in 2008 totaled $75.9 million, as compared to cash used of $65.8 million in 2007.
Factors contributing to the $141.7 million net increase in cash include share
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repurchases of $44.6 million in 2007 compared to no repurchases in 2008, long-term debt retired of $5.0 million in 2008
compared to $29.5 million in 2007, and an increase in short-term debt balances of $74.7 million in 2008, including borrowings
from the cash surrender value in company-owned life insurance policies, compared to 2007.
Cash used in financing activities in 2007 totaled $65.8 million, as compared to $59.4 million in 2006. Factors contributing
to the $6.4 million net increase in cash used include an increase in share repurchases of $28.7 million, an increase in long-term debt
retired of $21.5 million, and a reduction in long-term debt issuances of $25.0 million, offset by an increase in cash from the change
in short-term debt balances of $69.6 million in 2007 compared to 2006.
In October 2007, we entered into a forward-starting interest rate swap with a notional principal amount of $50 million.
This fixed-rate forward-starting swap is intended to mitigate a substantial portion of the interest rate exposure associated with our
anticipated issuance of MTNs in the first quarter of 2009 when we would expect to cash settle this contract. The associated gain or
loss on settlement will be recorded as a regulatory asset or liability and amortized in accordance with regulatory requirements. We
did not issue any new long-term debt during 2007 or 2008.
In December 2006, we sold $25 million of 5.15 percent Series B, secured MTNs due 2016 and used the proceeds to
reduce short-term indebtedness and to fund utility construction.
In 2000, we announced a program to repurchase up to 2 million shares, or up to $35 million in value, of our common
stock through a repurchase program. In 2006 that program was modified to 2.6 million shares and $85 million in value, and the
program was further modified in 2007 to authorize the repurchase of up to 2.8 million shares or up to $100 million and was
extended through May 2009. The purchases are made in the open market or through privately negotiated transactions. No
repurchases were made in 2008. Repurchases in 2007 totaled 963,428 shares or $44.2 million; and in 2006 totaled 395,500
shares or $16.0 million. Since the program’s inception, we have repurchased an aggregate 2.1 million shares of common stock at a
total cost of $83.3 million (see Part II, Item 5, “Market for the Registrant’s Common Equity, Related Stockholder Matters and
Issuer Purchases of Equity Securities,” above).
In 2008, we produced negative free cash flow of $115.3 million, compared to free cash flow of $27.5 million in 2007 and
$19.7 million in 2006. Free cash flow is the amount of cash remaining after the payment of all cash expenses, capital expenditures
(investment activities) and dividends. Free cash flow is a non-GAAP financial measure, but we believe this supplemental
information enables the reader of the financial statements to better understand our cash generating ability and to benefit from seeing
cash flow results from management’s perspective in addition to the traditional GAAP presentation. We monitor free cash flow as
one measure of our return on investments. Provided below is a reconciliation from cash provided by operations (GAAP basis) to
our non-GAAP free cash flow.
Thousands (year ended December 31)
Cash provided by operating activities
Cash used in investing activities
Cash dividend payments on common stock
Free cash flow
2008
2007
2006
$ 34,721
(109,825)
(40,178)
$(115,282)
$ 183,640
(117,479)
(38,613)
$ 27,548
$148,566
(90,567)
(38,298)
$ 19,701
The free cash flow information presented above is not intended to be a substitute for, nor is it meant to be a better
measure of, cash flow results prepared in accordance with GAAP. In addition, the
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non-GAAP measure we provide may be calculated differently by other companies that present a similar non-GAAP financial
measure for free cash flow.
Pension Cost and Funding Status of Qualified Retirement Plans
Pension costs are determined in accordance with SFAS No. 87 (see “Application of Critical Accounting Policies and
Estimates – Accounting for Pensions,” above). Pension costs for our two qualified defined benefit plans, which are allocated
between operations and maintenance expense and capital accounts based on employee payroll distributions, totaled $4.3 million in
2008, a decrease of $2.4 million over 2007.
The fair market value of the assets in these two plans decreased to $163.1 million at December 31, 2008 down from
$241.4 million at December 31, 2007. The decrease was due to a negative return on plan assets of $63.3 million and benefit
payments of $15.0 million net of contributions.
We make contributions to our qualified defined benefit pension plans based on actuarial assumptions and estimates, tax
regulations and funding requirements under federal law. The Pension Protection Act of 2006 (the Act) established new funding
requirements for defined benefit plans. The Act establishes a 100 percent funding target for plan years beginning after
December 31, 2008. However, a delayed effective date of 2011 may apply if the pension plan meets the funding targets of 92
percent in 2008, 94 percent in 2009 and 96 percent in 2010. Our qualified defined benefit pension plans are currently underfunded
by $98.4 million at December 31, 2008, and we expect to make at least the minimum contribution required pursuant to the Act,
which is currently estimated at $8 million. We plan to make additional contributions during 2009, which could bring our total
contributions in 2009 up to $40 million. We would need to make a total contribution of at least $17 million during 2009 to avoid
any restrictions on benefit payments. For more information, see Note 7.
Ratios of Earnings to Fixed Charges
For the years ended December 31, 2008, 2007 and 2006, our ratios of earnings to fixed charges, computed using the
Securities and Exchange Commission method, were 3.76, 3.92 and 3.40, 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.
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 SFAS No. 5 (see “Application of Critical Accounting Policies and Estimates—
Contingencies,” above). At December 31, 2008, a cumulative $66.1 million in environmental costs was recorded as a regulatory
asset, consisting of $30.1 million of costs paid to-date, $30.0 million for additional environmental accruals for costs expected to be
paid in the future and accrued regulatory interest of $6.0 million. If it is determined that both the insurance recovery and future
customer rate recovery of such costs was not probable, then the costs will be charged to expense in the period such determination
is made. For further discussion of contingent liabilities, see Note 12.
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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 1.
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 storage facilities, to meet the expected requirements of our core utility customers. Our gas purchase contracts are
primarily index-based and subject to monthly re-pricing, a strategy that is intended to reflect market price trends during the
upcoming year. Our PGA mechanisms in Oregon and Washington provide for the recovery from customers of actual commodity
costs, except that, for Oregon customers, we currently absorb 20 percent of the higher cost of gas sold, or retain 20 percent of the
lower cost, in either case as compared to the annual PGA price built into customer rates.
Commodity Price Risk
Natural gas commodity prices are subject to fluctuations due to unpredictable factors including weather, pipeline
transportation congestion, potential market speculation and other factors that affect short-term supply and demand. Commodityprice financial swap and option contracts (financial hedge contracts) are used to convert certain natural gas supply contracts from
floating prices to fixed or capped prices. These financial hedge contracts are generally included in our annual PGA filing for
recovery, subject to a regulatory prudence review. At December 31, 2008 and 2007, notional amounts under these financial hedge
contracts totaled $393.0 million and $287.6 million, respectively. If all of the commodity-based financial hedge contracts had been
settled on December 31, 2008, a loss of about $139.2 million would have been realized and recorded to a deferred regulatory
account (see Note 11). We monitor the liquidity of our financial hedge contracts. Based on the existing open interest in the
contracts held, we believe existing contracts to be liquid. All of our financial hedge contracts settle by or are extendible to
October 31, 2010. The $139.2 million unrealized loss is an estimate of future cash flows based on forward market prices that are
expected to be paid as follows: $130.3 million in the next 12-month period, and $8.9 million in the following 12-month period. The
amount realized will change based on market prices at the time contract settlements are fixed.
Natural gas commodity prices early in the third quarter of 2008 were higher than prices embedded in the corresponding
PGA for unhedged purchases. To the extent that we purchase gas volumes where the price is not hedged and the current market
prices are above those embedded in rates for current customer consumption (i.e. not for storage injections), our earnings are
negatively impacted because either 10 to 20 percent of any difference between the actual purchase gas costs and the gas costs
embedded in Oregon rates are recognized in current income. In 2008, we recognized a loss of $5.5 million due to higher gas
prices.
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Interest Rate Risk
We are exposed to interest rate risk 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. During the fourth quarter of 2007, we
entered into a forward starting interest rate swap with a notional amount of $50 million to hedge the interest rate on our next longterm debt issuance, which was expected to occur in the latter part of 2008. However, due to credit market conditions, the swap
was extended to the second quarter of 2009. This swap is with an A+/Aa2 rated counterparty and qualifies as a cash flow hedge
under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended by SFAS No. 138 and SFAS
No. 149 (collectively referred to as SFAS No. 133). The mark-to-market unrealized loss at December 31, 2008 related to this
interest rate swap was $11.9 million.
Holders of certain long-term debt have put options that, if exercised, would accelerate maturities by $20 million in 2009
(see Note 5).
Foreign Currency Risk
The costs of certain natural gas commodity supplies and certain pipeline services purchased from Canadian suppliers are
subject to changes in the value of the Canadian currency in relation to the U.S. currency. Foreign currency forward contracts are
used to hedge against fluctuations in exchange rates with respect to purchases of natural gas from Canadian suppliers. At
December 31, 2008 and 2007, notional amounts under foreign currency forward contracts totaled $5.2 million and $6.1 million,
respectively. As of December 31, 2008, no foreign currency forward contracts were outstanding with a maturity date after
November 30, 2009. If all of the foreign currency forward contracts had been settled on December 31, 2008, a loss of $0.4
million would have been realized (see Note 11).
Credit Risk
Credit exposure to suppliers. Certain suppliers that sell us gas have either relatively low credit ratings or are not rated
by major credit rating agencies. To manage this supply risk, we purchase gas from a number of different suppliers at liquid
exchange points. We evaluate and monitor suppliers’ creditworthiness and maintain the ability to require additional financial
assurances, including deposits, letters of credit or surety bonds, in case a supplier defaults. In the event of a supplier’s failure to
deliver contracted volumes of gas, the regulated utility would need to replace those volumes at prevailing market prices, which may
be higher or lower than the original transaction prices. We believe these costs would be subject to the PGA sharing mechanism
discussed above. Since most of our commodity supply contracts are priced at the monthly market index price tied to liquid
exchange points, and we have significant storage flexibility, we believe that it is unlikely that a supplier default would have 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, 2008, our
credit exposure relating to commodity hedge contracts reflected an amount we owed of $130.3 million to our finance derivative
counterparties. Our financial derivatives policy requires counterparties to have a minimum 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. Some counterparties were recently downgraded but continue to maintain investment grade ratings (see table below). Due to
current market conditions and credit concerns, we
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continue to enforce strong credit requirements. We actively monitor our derivative credit exposure and place counterparties on hold
for trading purposes or require letters of credit or guarantees as circumstances warrant. Our actual derivative credit exposure,
which reflects amounts that financial derivative counterparties owe to us, is under contracts that expire or are expected to settle on
or before October 31, 2010.
The following table summarizes our credit exposure, based on estimated fair value, and the corresponding counterparty
credit ratings. The table uses credit ratings from S&P and Moody’s, reflecting the higher of the S&P or Moody’s rating or a middle
rating if the entity is split-rated with more than one rating level difference:
Thousands
AAA/Aaa
AA/Aa
A/A
BBB/Baa
Total
$
$
Financial Derivative Position by Credit Rating
Unrealized Fair Value Gain (Loss)
Dec. 31, 2008
Dec. 31, 2007
(16,827)
$
(309)
(122,287)
(13,941)
(12,006)
123
(151,120)
$
(14,127)
To mitigate the credit risk of financial derivatives we have master netting arrangements with our counterparties that provide
for making or receiving net cash settlements. Generally, transactions of the same type in the same currency that have a settlement on
the same day with a single counterparty are netted and a single payment is delivered or received depending on which party is due
funds.
Additionally we have master contracts in place with each of our derivative counterparties that include provisions for
posting or calling for collateral. Generally we can obtain cash or marketable securities as collateral with one day’s notice. We use
various collateral management strategies to reduce liquidity risk. The collateral provisions vary by counterparty but are not
expected to result in the significant posting of collateral, if any. We have performed stress tests on the portfolio and concluded that
the liquidity risk from collateral calls is not material. Our derivative credit exposure is primarily with investment grade counterparties
rated AA-/Aa3 or higher. Contracts are diversified across counterparties to reduce credit and liquidity risk.
Weather Risk
We are exposed to weather risk primarily from our regulated utility business. A large percentage of our utility margin is
volume driven, and current rates are based on an assumption of average weather. In 2003, the OPUC approved a weather
normalization mechanism for residential and commercial customers. This mechanism affects customer bills between December 1
through May 15 of each winter heating season, increasing or decreasing the margin component of customers’ rates to reflect gas
usage based on “average” weather using the 25-year average temperature for each day of the billing period. The mechanism is
intended to stabilize the recovery of our utility’s fixed costs and reduce fluctuations in customers’ bills due to colder or warmer than
average weather. Customers in Oregon are allowed to opt out of the weather normalization mechanism. As of December 31,
2008, less than 10 percent of our Oregon customers had opted out. In addition to the Oregon customers opting out, our
Washington residential and commercial customers account for approximately 10 percent of our total customer base and are not
covered by weather normalization. The combination of Oregon and Washington customers not covered by a weather normalization
mechanism is less than 20 percent of all residential and commercial customers.
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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Table of Contents
Page
1.
Management’s Report on Internal Control Over Financial Reporting
70
2.
Report of Independent Registered Public Accounting Firm
71
3.
Consolidated Financial Statements:
Consolidated Statements of Income for the Years Ended December 31, 2008,
2007 and 2006
72
Consolidated Balance Sheets at December 31, 2008 and 2007
73
Consolidated Statements of Shareholders’ Equity and Comprehensive Income for the Years Ended December 31,
2008, 2007 and 2006
75
Consolidated Statements of Cash Flows for the Years Ended December 31, 2008,
2007 and 2006
76
Notes to Consolidated Financial Statements
77
4.
Quarterly Financial Information (unaudited)
114
5.
Supplementary Data for the Years Ended December 31, 2008, 2007 and 2006:
Financial Statement Schedule
Schedule II—Valuation and Qualifying Accounts and Reserves
Supplemental Schedules Omitted
All other schedules are omitted because of the absence of the conditions under which they are required or because the
required information is included elsewhere in the financial statements.
69
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Table of Contents
MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
Management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in
Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, as amended. Our internal control over financial
reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial
statements for external purposes in accordance with generally accepted accounting principles in the United States of America
(GAAP). Our internal control over financial reporting includes those policies and procedures that:
(i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and
dispositions involving company assets;
(ii) provide reasonable assurance that transactions are recorded as necessary to permit the preparation of financial
statements in accordance with GAAP, and that receipts and expenditures are being made only in accordance with
authorizations of management and the Board of Directors; and
(iii) provide reasonable assurance regarding prevention or timely detection of the unauthorized acquisition, use or
disposition of our assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements or
fraud. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become
inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Management assessed the effectiveness of NW Natural’s internal control over financial reporting as of December 31,
2008. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the
Treadway Commission (COSO) in Internal Control-Integrated Framework.
Based on our assessment and those criteria, management has concluded that NW Natural maintained effective internal
control over financial reporting as of December 31, 2008.
The effectiveness of internal control over financial reporting as of December 31, 2008 has been audited by
PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears in this
annual report.
/s/ Gregg S. Kantor
Gregg S. Kantor
President and Chief Executive Officer
/s/ David H. Anderson
David H. Anderson
Senior Vice President and Chief Financial Officer
February 27, 2009
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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, 2008 and 2007, and the results of their operations and their cash
flows for each of the three years in the period ended December 31, 2008 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, 2008, based on criteria
established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission
(COSO). The Company’s management is responsible for these financial statements and financial statement schedule, for maintaining effective
internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the
accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express opinions on these financial
statements, on the financial statement schedule, and on the Company’s internal control over financial reporting based on our integrated audits. We
conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards
require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement
and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included
examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used
and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over
financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness
exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included
performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our
opinions.
As discussed in Note 1 to the consolidated financial statements, the Company changed the manner in which it accounts for fair value measurements
in 2008. As discussed in Note 7 to the consolidated financial statements, the Company changed the manner in which it accounts for defined benefit
pension and other postretirement plans effective December 31, 2006.
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, 2009
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NORTHWEST NATURAL GAS COMPANY
CONSOLIDATED STATEMENTS OF INCOME
Thousands, except per share amounts (year ended December 31)
2008
2007
2006
$ 1,037,855
656,568
25,072
356,215
$ 1,033,193
639,150
25,001
369,042
$ 1,013,172
648,156
24,840
340,176
Operating expenses:
Operations and maintenance
General taxes
Depreciation and amortization
Total operating expenses
Income from operations
113,360
26,660
72,159
212,179
144,036
120,488
25,288
68,343
214,119
154,923
114,560
24,419
64,435
203,414
136,762
Other income and expense - net
Interest charges - net of amounts capitalized
Income before income taxes
Income tax expense
Net income
3,746
37,579
110,203
40,678
69,525
1,445
37,811
118,557
44,060
74,497
2,134
39,247
99,649
36,234
63,415
Operating revenues:
Gross operating revenues
Less: Cost of sales
Revenue taxes
Net operating revenues
$
Average common shares outstanding:
Basic
Diluted
$
26,438
26,594
Earnings per share of common stock:
Basic
Diluted
$
$
-------------------------------------------
See Notes to Consolidated Financial Statements.
72
2.63
2.61
$
26,821
26,995
$
$
2.78
2.76
27,540
27,657
$
$
2.30
2.29
Table of Contents
NORTHWEST NATURAL GAS COMPANY
CONSOLIDATED BALANCE SHEETS
Thousands (December 31)
Assets:
Plant and property:
Utility plant
Less accumulated depreciation
Utility plant - net
Non-utility property
Less accumulated depreciation and amortization
Non-utility property - net
Total plant and property
Current assets:
Cash and cash equivalents
Accounts receivable
Accrued unbilled revenue
Allowance for uncollectible accounts
Regulatory assets
Fair value of non-trading derivatives
Inventories:
Gas
Materials and supplies
Income taxes receivable
Prepayments and other current assets
Total current assets
Investments, deferred charges and other assets:
Regulatory assets
Fair value of non-trading derivatives
Other investments
Other
Total investments, deferred charges and other assets
Total assets
2008
2007
$ 2,142,988
659,123
1,483,865
74,506
9,314
65,192
1,549,057
$ 2,052,161
615,533
1,436,628
67,149
7,904
59,245
1,495,873
6,916
81,288
102,688
(2,927)
147,319
4,592
-------------------------------------------
See Notes to Consolidated Financial Statements.
73
6,107
69,442
78,004
(2,890)
17,598
2,903
86,134
9,933
20,811
24,216
480,970
71,079
8,865
25,569
276,677
288,470
146
54,132
5,377
348,125
$ 2,378,152
175,938
324
54,070
11,179
241,511
$ 2,014,061
Table of Contents
NORTHWEST NATURAL GAS COMPANY
CONSOLIDATED BALANCE SHEETS
Thousands (December 31)
2008
Capitalization and liabilities:
Capitalization:
Common stock
Earnings invested in the business
Accumulated other comprehensive income (loss)
Total common stock equity
Long-term debt
Total capitalization
Current liabilities:
Notes payable
Long-term debt due within one year
Accounts payable
Taxes accrued
Interest accrued
Regulatory liabilities
Fair value of non-trading derivatives
Other current and accrued liabilities
Total current liabilities
Deferred credits and other liabilities:
Deferred income taxes and investment tax credits
Regulatory liabilities
Pension and other postretirement benefit liabilities
Fair value of non-trading derivatives
Other
Total deferred credits and other liabilities
Commitments and contingencies (see Note 12)
Total capitalization and liabilities
$
-------------------------------------------
See Notes to Consolidated Financial Statements.
74
336,754
296,005
(4,386)
628,373
512,000
1,140,373
2007
$
331,595
266,658
(3,502)
594,751
512,000
1,106,751
248,000
94,422
12,455
2,785
20,456
136,735
36,467
551,320
143,100
5,000
119,731
13,137
2,827
61,326
14,829
29,794
389,744
257,831
228,157
138,229
21,646
40,596
686,459
$ 2,378,152
206,340
213,764
41,619
3,758
52,085
517,566
$ 2,014,061
Table of Contents
NORTHWEST NATURAL GAS COMPANY
CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY AND
COMPREHENSIVE INCOME
Thousands
Balance at Dec. 31, 2005
Net Income
Minimum pension liability
adjustment, net of $52 of tax
Change in non-qualified employee
benefit plan liability, net of $232
of tax
Restricted stock amortizations
Dividends paid on common stock
Tax benefits from employee stock
option plan
Stock-based compensation
Restricted stock reclassification
Issuance of common stock
Common stock repurchased
Common stock expense
Balance at Dec. 31, 2006
Net Income
Change in unrealized loss from
price risk management activities
Change in non-qualified employee
benefit plan liability, net of $487
of tax
Amortization of non-qualified
employee benefit plan liability,
net of ($81) of tax
Restricted stock amortizations
Dividends paid on common stock
Tax benefits from employee stock
option plan
Stock-based compensation
Issuance of common stock
Common stock repurchased
Balance at Dec. 31, 2007
Net Income
Change in unrealized loss from
price risk management activities
Change in non-qualified employee
benefit plan liability, net of $731
of tax
Amortization of non-qualified
employee benefit plan liability,
net of ($86) of tax
Restricted stock amortizations
Dividends paid on common stock
Tax benefits from employee stock
option plan
Stock-based compensation
Issuance of common stock
Balance at Dec. 31, 2008
Common
Stock
and
Premium
$ 383,805
-
Earnings
Invested in
the Business
$
205,687
63,415
-
-
298
317
555
(650)
2,773
(15,971)
371,127
Unearned
Stock
Compensation
$
(650)
-
Accumulated
Other
Comprehensive
Income (Loss)
$
(1,911)
-
Total
Shareholders’
Equity
$
586,931
63,415
Comprehensive
Income
$
63,415
-
(81)
(81)
(38,298)
-
(364)
-
(364)
298
(38,298)
(30)
230,774
650
-
(2,356)
317
555
2,773
(15,971)
(30)
599,545
$
63,334
74,497
$
74,497
-
74,497
-
-
-
-
(41)
(41)
(41)
-
-
-
(1,232)
(1,232)
(1,232)
285
-
(38,613)
-
266,658
-
-
69,525
-
-
-
-
-
-
-
536
2,094
2,180
(44,627)
331,595
275
282
1,523
3,079
$ 336,754
$
(40,178)
-
296,005
-
$
-
(81)
127
(3,502)
$
73,351
-
69,525
$
69,525
41
41
-------------------------------------------
(4,386)
41
(1,145)
220
-
$
127
536
2,094
2,180
(44,627)
594,751
(1,145)
See Notes to Consolidated Financial Statements.
75
127
285
(38,613)
(1,145)
220
275
(40,178)
$
282
1,523
3,079
628,373
220
$
68,641
Table of Contents
NORTHWEST NATURAL GAS COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
Thousands (year ended December 31)
Operating activities:
Net income
Adjustments to reconcile net income to cash provided by operations:
Depreciation and amortization
Deferred income taxes and investment tax credits
Undistributed gains from equity investments
Deferred gas costs - net
Gain on sale of non-utility investments
Income from life insurance investments
Non-cash expenses related to qualified defined benefit pension plans
Deferred environmental expenditures
Deferred regulatory costs and other
Changes in working capital:
Accounts receivable and accrued unbilled revenue - net
Inventories of gas, materials and supplies
Income taxes receivable
Prepayments and other current assets
Accounts payable
Accrued interest and taxes
Other current and accrued liabilities
Cash provided by operating activities
Investing activities:
Investment in utility plant
Investment in non-utility property
Proceeds from sale of non-utility investments
Proceeds from life insurance
Contributions to non-utility equity investments
Other
Cash used in investing activities
Financing activities:
Common stock issued, net of expenses
Common stock repurchased
Long-term debt issued
Long-term debt retired
Change in short-term debt - net
Cash dividend payments on common stock
Other
Cash provided by (used in) financing activities
Increase (decrease) in cash and cash equivalents
Cash and cash equivalents - beginning of period
Cash and cash equivalents - end of period
Supplemental disclosure of cash flow information:
Interest paid
Income taxes paid
-------------------------------------------
See Notes to Consolidated Financial Statements.
76
2008
2007
2006
$ 69,525
$ 74,497
$ 63,415
72,159
50,192
(667)
(45,291)
(1,737)
(2,190)
2,855
(8,179)
(9,347)
68,343
(5,252)
(130)
38,665
(1,544)
(1,939)
4,387
(8,842)
(2,940)
64,435
(16,440)
(191)
20,752
(495)
(2,609)
5,500
(6,675)
14,533
(36,493)
(16,123)
(20,811)
363
(24,540)
(724)
5,729
34,721
22,029
(1,816)
(6,528)
5,841
(8,190)
7,059
183,640
(3,722)
8,033
13,234
2,952
(21,708)
8,511
(959)
148,566
(96,582)
(7,416)
7,531
208
(7,450)
(6,116)
(109,825)
(93,785)
(24,442)
2,628
881
(5,413)
2,652
(117,479)
(95,307)
(1,773)
2,517
4,009
(13)
(90,567)
2,310
(5,000)
117,751
(40,178)
1,030
75,913
809
6,107
$ 6,916
2,180
(44,627)
(29,500)
43,000
(38,613)
1,739
(65,821)
340
5,767
$ 6,107
3,913
(15,971)
25,000
(8,000)
(26,600)
(38,298)
581
(59,375)
(1,376)
7,143
$ 5,767
$ 37,669
$ 12,300
$ 38,508
$ 56,215
$ 39,294
$ 31,270
Table of Contents
NORTHWEST NATURAL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1.
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:
Organization and Principles of Consolidation
The consolidated financial statements include the accounts of Northwest Natural Gas Company (NW Natural), which
primarily consist of our regulated gas distribution business and our regulated gas storage business, which includes our
wholly-owned subsidiary Gill Ranch Storage, LLC (Gill Ranch), and other investments and business activities, which
primarily consist of our wholly-owned subsidiary NNG Financial Corporation (Financial Corporation) and an equity
investment in a natural gas transmission pipeline (See Note 2).
In this report, the term “utility” is used to describe the gas distribution business and the term “non-utility” is used to
describe the gas storage business and other non-utility investments and business activities (see Note 2). Intercompany
accounts and transactions have been eliminated, except for transactions required by regulatory accounting under
Statement of Financial Accounting Standards (SFAS) No. 71, “Accounting for the Effects of Certain Types of
Regulation,” not to be eliminated.
Investments in corporate joint ventures and partnerships in which our ownership interest is 50 percent or less and over
which we do not exercise control are accounted for by the equity method or the cost method.
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 be reported in future periods. Management believes that the estimates and assumptions used are reasonable.
Industry Regulation
Our principal businesses are the distribution of natural gas, which is regulated by the Oregon Public Utility Commission
(OPUC), and Washington Utilities and Transportation Commission (WUTC), and gas storage services, which are
regulated by the Federal Energy Regulatory Commission (FERC) and to a certain extent by the OPUC. Accounting
records and practices of our regulated businesses conform to the requirements and uniform system of accounts prescribed
by these regulatory authorities in accordance with SFAS No. 71. Our businesses are authorized by the OPUC, WUTC
and the FERC to earn a reasonable return on invested capital.
In applying SFAS No. 71, we capitalize or defer certain costs and revenues as regulatory assets and liabilities pursuant to
orders of the OPUC or WUTC issued to provide for recovery of revenues or expenses from, or refunds to, utility
customers in future periods, including a return or a carrying charge.
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At December 31, 2008 and 2007, the amounts deferred as regulatory assets and liabilities were as follows:
Current
2008
2007
Thousands
Regulatory assets:
Unrealized loss on non-trading derivatives(1)
Income tax asset
Pension and other postretirement benefit obligations(2)
Environmental costs - paid(3)
Environmental costs - accrued but not yet paid(3)
Other(4)
Total regulatory assets
Regulatory liabilities:
Gas costs payable
Unrealized gain on non-trading derivatives(1)
Accrued asset removal costs
Other(4)
Total regulatory liabilities
(1)
(2)
(3)
(4)
Non-Current
2008
2007
$ 136,735
8,074
2,510
$ 147,319
$ 14,788
1,912
898
$ 17,598
$ 21,646
69,948
113,869
36,135
29,969
16,903
$ 288,470
$
$
$ 46,153
2,903
12,270
$ 61,326
$
$
5,284
4,592
10,580
$ 20,456
1,868
146
223,716
2,427
$ 228,157
3,758
68,649
27,152
27,956
35,098
13,325
$ 175,938
6,290
324
204,886
2,264
$ 213,764
An unrealized gain or loss on non-trading derivatives does not earn a rate of return or a carrying charge. These amounts,
when realized at settlement, are recoverable through utility rates as part of the purchased gas adjustment mechanism.
Qualified pension plan and other postretirement benefit obligations are approved for regulatory deferral. Such amounts are
recoverable in rates, including an interest component, when recognized in net periodic benefit cost (see Note 7).
Environmental costs are related to those sites that are approved for regulatory deferral. We earn the authorized rate of
return as a carrying charge on amounts paid, whereas the amounts accrued but not yet paid do not earn a rate of return or
a carrying charge until expended.
Other primarily consists of deferrals and amortizations under other approved regulatory mechanisms. The accounts being
amortized typically earn a rate of return or carrying charge.
We believe that continued application of SFAS No. 71 for regulated activities is appropriate and consistent with the
current regulatory environment, and that all regulated assets and liabilities at December 31, 2008 and 2007 will be
recoverable or refundable through future utility rates. We annually review all regulatory assets for recoverability and more
often if circumstances warrant. If we should determine that all or a portion of these regulatory assets or liabilities no longer
meet the criteria for continued application of SFAS No. 71, then we would be required to write off the net unrecoverable
balances against earnings.
New Accounting Standards
Adopted Standards
Fair Value Measurements. In September 2006, the Financial Accounting Standards Board (FASB) issued SFAS
No. 157, “Fair Value Measurements,” which is effective for fiscal years beginning after November 15, 2007. This
statement defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value
measurements. This statement indicates, among other things, that a fair value measurement assumes that a transaction to
sell
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an asset or transfer a liability occurs in the principal market for the asset or liability or, in the absence of a principal market,
the most advantageous market for the asset or liability. SFAS No. 157 defines fair value based upon an exit price model.
Relative to SFAS No. 157, the FASB issued FASB Staff Positions (FSP) 157-1, 157-2 and 157-3. FSP 157-1 amends
SFAS No. 157 to exclude SFAS No. 13, “Accounting for Leases,” and its related interpretive accounting
pronouncements that address leasing transactions. FSP 157-2 delays the effective date of the application of SFAS
No. 157 to fiscal years beginning after November 15, 2008 for all nonfinancial assets and liabilities except for those that
are recognized or disclosed at fair value in the financial statements on a recurring basis. FSP 157-3, issued and effective
on October 10, 2008, clarifies the application of SFAS No. 157 when relevant observable inputs in active markets are
not available.
We adopted SFAS No. 157, FSP 157-1 and FSP 157-3 as of January 1, 2008, and adopted FSP 157-2 as of
January 1, 2009. The adoption of these new accounting standards did not have, and is not expected to have, a material
effect on our financial condition, results of operations or cash flows.
Fair Value Option for Financial Assets and Liabilities. In February 2007, the FASB issued SFAS No. 159, “The
Fair Value Option for Financial Assets and Financial Liabilities,” which permits, but does not require, entities to measure
many financial instruments and certain other items at fair value. SFAS No. 159 became effective for fiscal years beginning
after November 15, 2007. We elected not to implement SFAS No. 159 because the majority of our assets and liabilities
are regulated by the OPUC and the WUTC, both of which generally allow us to earn a reasonable return on invested
capital based on original cost rather than current market value.
Accounting for Income Tax Benefits of Dividends on Share-Based Payment Awards. On January 1, 2008, we
adopted Emerging Issues Task Force (EITF) 06-11, “Accounting for Income Tax Benefits of Dividends on Share-Based
Payment Awards,” which provides the accounting requirements for recognizing income tax benefits received on dividends
paid to employees holding equity-classified nonvested shares, equity-classified nonvested share units or equity-classified
outstanding share options, and how these benefits are charged to retained earnings under SFAS No. 123R, “Share Based
Payment.” The adoption of EITF 06-11 did not have, and is not expected to have, a material effect on our financial
condition, results of operations or cash flows.
Offsetting Amounts Related to Certain Contracts. On January 1, 2008, we adopted FSP FASB Interpretation No.
FIN 39-1 (FSP FIN39-1), “Offsetting of Amounts Related to Certain Contracts.” FSP FIN 39-1 requires disclosure
when a reporting entity offsets fair value amounts from derivative instruments executed with the same counterparty under
master netting arrangements. Our disclosures on FSP FIN 39-1 are included in Note 11. The adoption and
implementation of FSP FIN 39-1 did not have, and is not expected to have, a material effect on our financial statement
disclosures.
Transfers of Financial Assets and Interests in Variable Interest Entities. In December 2008, the FASB issued
SFAS No. 140-4 and FIN 46R-8, “Disclosures by Public Entities about Transfers of Financial Assets and Interests in
Variable Interest Entities,” effective immediately for periods ending after December 15, 2008. SFAS No. 140-4 and FIN
46R-8 require additional
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disclosures related to the nature of, involvement in and judgments made when transferring assets or liabilities to variable
interest entities. The adoption and implementation of SFAS No. 140-4 and FIN 46R-8 did not have, and is not expected
to have, a material effect on our financial statement disclosures.
Recent Accounting Pronouncements
Business Combinations. In December 2007, the FASB issued SFAS No. 141R, “Business Combinations.” This
statement amends the principles and requirements for how an acquiror accounts for and discloses its business
combinations. SFAS No. 141R is effective for fiscal years and interim periods beginning after December 15, 2008. Based
on our preliminary assessment, this statement is not expected to have a material effect on our financial condition, results of
operations or cash flows.
Noncontrolling Interests in Consolidated Financial Statements. In December 2007, the FASB issued SFAS
No. 160, “Noncontrolling Interests in Consolidated Financial Statements.” This statement amends the reporting
requirements of Accounting Research Bulletin No. 51 for noncontrolling interests in subsidiaries to improve the relevance,
comparability and transparency of the financial information disclosed. SFAS No. 160 is effective for fiscal years beginning
after December 15, 2008. Based on the nature of this new statement and our current organizational structure, adoption of
this statement is not expected to have a material effect on our financial condition, results of operations or cash flows.
Derivative Instruments and Hedging Activities. In March 2008, the FASB issued SFAS No. 161, “Accounting for
Derivative Instruments and Hedging Activities,” which requires enhanced disclosures of derivative instruments and hedging
activities. SFAS No. 161 is effective for reporting periods beginning after November 15, 2008.
SFAS No. 161 will expand current disclosures by adding qualitative disclosures about our hedging objectives and
strategies, fair value gains and losses, and credit-risk-related contingent features in derivative agreements. The disclosures
are intended to provide an enhanced understanding of:
•
•
•
how and why we use derivative instruments;
how derivative instruments and related hedge items are accounted for under SFAS No. 133, “Accounting for
Derivative Instruments and Hedging Activities,” and its related interpretations; and
how derivative instruments and related hedged items affect our financial condition, results of operations and cash
flows.
The adoption of SFAS No. 161 is not expected to have a material effect on our financial statement disclosures.
Determining Whether Instruments Granted in Share-Based Payment Transactions are Participating
Securities. In June 2008, the FASB issued final FSP No. EITF 03-6-1, “Determining Whether Instruments Granted in
Share-Based Payment Transactions are Participating Securities.” This statement requires nonforfeitable rights to dividends
or dividend equivalents on unvested share-based payment to be included in the computation of earnings per share under
the two-class method. This statement will be effective for fiscal years beginning
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after December 15, 2008. Based on our preliminary assessment, the adoption of FSP No. EITF 03-6-1 is not expected
to have a material effect on our financial condition, results of operations or cash flows.
Pensions. In December 2008, the FASB issued SFAS No. 132R-1, “Employers’ Disclosures about Pensions and Other
Postretirement Benefits,” which requires enhanced disclosures of plan assets in an employer’s defined benefit pension or
other postretirement benefit plan. SFAS No. 132R-1 is effective for reporting periods ending after December 15, 2009.
The disclosures are intended to provide an enhanced understanding of:
•
•
•
•
•
how investment allocation decisions are made;
the major categories of plan assets;
the inputs and valuation techniques used to measure the fair value of plan assets;
the effect of fair value measurements using significant unobservable inputs (Level 3 input from SFAS No. 157) on
changes in plan assets for the period; and
significant concentration or risk within plan assets.
The adoption of SFAS No. 132R-1 is not expected to have a material effect on our financial statement disclosures.
Plant and Property and Accrued Asset Removal Costs
Plant and property is stated at cost, including capitalized labor, materials and overhead (see Note 9). In accordance with
SFAS No. 71, the cost of constructing utility plant and gas storage assets generally includes an allowance for funds used
during construction (AFUDC). AFUDC represents the net financing cost during the period the funds are used for
construction purposes (see “Allowance for Funds Used During Construction,” below). When gas storage assets under
construction are expected to be subject to market based rates, then the cost of construction will include capitalized
interest in accordance with GAAP, not regulatory AFUDC.
Our provision for depreciation of utility property is computed under the straight-line, age-life method in accordance with
external engineering studies and as approved by regulatory authorities. The weighted average depreciation rate for plant in
service was approximately 3.4 percent for the years ended December 31, 2008, 2007 and 2006, reflecting the
approximate average economic life of the property.
In accordance with long-standing industry practice, we accrue for future asset removal costs on many long-lived assets
through a charge to depreciation expense allowed in rates and accumulate such amounts in regulatory liabilities. At the
time removal costs are incurred, accumulated depreciation is charged with the costs of removal and the book cost of the
asset. Our estimate of accumulated removal costs is based on rates using approved depreciation studies. No gain or loss
is recognized upon normal retirement. In the rate setting process, the accrued asset removal costs are treated as a
reduction to net rate base.
Allowance for Funds Used During Construction
Certain additions to utility plant include AFUDC, which represents the net cost of borrowed or other funds used during
construction and is calculated using actual current interest rates and authorized rates for return on equity, if applicable. If
borrowings are less than the total costs of
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construction work in progress, then a composite rate of interest on all debt, shown as a reduction to interest charges, and
a return on equity funds, shown as other income, is used to compute the AFUDC. While cash is not realized currently
from AFUDC, it is realized in future years through increased revenues from rate recovery resulting from higher rate base
and higher depreciation expense. Our composite AFUDC rates were 3.6 percent in 2008, 5.4 percent in 2007 and 4.7
percent in 2006.
Cash and Cash Equivalents
For purposes of reporting cash flows, cash and cash equivalents include cash on hand and highly liquid temporary
investments with original maturity dates of three months or less. At December 31, 2008 and 2007, book overdrafts of
$1.0 million and $4.9 million, respectively, were included within accounts payable.
Revenue Recognition and Accrued Unbilled Revenues
Utility revenues, derived primarily from the sale and transportation of gas, are recognized when the gas is delivered to and
received by the customer. Revenues include accruals for gas delivered but not yet billed to customers based on estimates
of gas deliveries from meter reading dates to month end (accrued unbilled revenues). Accrued unbilled revenues are
dependent upon a number of factors that require management’s judgment, including total gas receipts and deliveries,
customer use by billing cycle and weather. Accrued unbilled revenues are reversed the following month when actual
billings occur. Our accrued unbilled revenues at December 31, 2008 and 2007 were $102.7 million and $78.0 million,
respectively.
Utility operating revenues also include the recognition of a regulatory adjustment for income taxes paid. This revenue
adjustment reflects an OPUC rule whereby we are required to implement a rate refund or a rate surcharge to utility
customers. This automatic refund or surcharge is accrued based on the estimated difference between income taxes paid
and income taxes authorized to be collected in rates for each tax year.
Non-utility revenues, derived primarily from gas storage services, are recognized as services are provided by the
independent energy marketing company in accordance with our contractual agreement. Our current asset optimization
agreement includes guaranteed amounts which are recognized pro-rata on a monthly basis over the contact term. See
Note 2.
Accounts Receivable and Allowance for Uncollectible Accounts
Accounts receivable consist primarily of amounts due for gas sales and transportation services to core utility customers,
plus amounts due for gas storage services and other miscellaneous receivables. With respect to these trade receivables,
including accrued unbilled revenues, we establish an allowance for uncollectible accounts (allowance) based on the aging
of receivables, collection experience of current past due accounts including payment plans, and historical trends of writeoffs as a percent of revenues. With respect to large individual customer receivables, a specific allowance is established
and added to the general allowance when amounts are identified as unlikely to be partially or fully recovered. Inactive
accounts are written-off against the allowance after they are 120 days past due or when deemed to be uncollectible.
Differences between our estimated allowance and actual write-offs will occur based on changes in general economic
conditions, customer credit issues and the level of
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natural gas prices. Each quarter the allowance for uncollectible accounts is adjusted, as necessary, based on the most
current information available.
Inventories
Inventories, which consist primarily of natural gas in storage for the utility, are generally stated at the lower of average cost
or net realizable value. The regulatory treatment of gas inventories provides for cost recovery in customer rates. All gas
that is injected into storage is priced into inventory based on actual purchases. All gas that is withdrawn from inventory is
charged to cost of gas during the current period at the weighted average cost of inventory. Material and supplies
inventories are stated at the lower of average cost or net realizable value.
Derivatives
In accordance with SFAS No. 133, as amended by SFAS No. 138, “Accounting for Certain Derivative Instruments and
Certain Hedging Activities,” and SFAS No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging
Activities” (collectively referred to as SFAS No. 133), we measure derivatives at fair value and recognize them as either
assets or liabilities on the balance sheet. SFAS No. 133 requires that changes in the fair value of a derivative be
recognized currently in earnings unless specific hedge accounting criteria are met. SFAS No. 133 provides an exception
for contracts intended for normal purchases and normal sales for which physical delivery is probable. In addition, certain
derivatives contracts are approved by regulatory authorities for recovery or refund through customer rates. Accordingly,
the changes in fair value of these contracts are deferred as regulatory assets or liabilities pursuant to SFAS No. 71.
Derivatives contracts entered into for core utility customer requirements after the purchased gas adjustment (PGA) rate
has been set are subject to the PGA incentive sharing mechanism. Under our PGA sharing mechanism in effect prior to
November 1, 2008, 67 percent of the changes in fair value were deferred as regulatory assets or liabilities and the
remaining 33 percent was recorded to the income statement for derivatives that do not qualify for hedge accounting, and
to Other Comprehensive Income for hedges that do qualify for hedge accounting. A modified PGA sharing mechanism
was approved in Oregon, effective on November 1, 2008, under which we are required to select, by August 1 of each
year, either an 80 percent deferral or 90 percent deferral of higher or lower gas costs such that the impact on current
earnings from the gas cost sharing is either 20 percent or 10 percent, respectively. For the PGA year in Oregon beginning
November 1, 2008, we selected the 80 percent deferral of gas cost differences. See Note 11.
Our financial derivatives policies set forth the guidelines for using selected financial derivative products to support prudent
risk management strategies within designated parameters. Our objective for using derivatives is to decrease the volatility of
earnings and cash flows and to prevent speculative risk. The use of derivatives is permitted only after the risk exposures
have been identified, are determined to exceed acceptable tolerance levels and are considered to be unavoidable because
they are necessary to support normal business activities. We do not enter into derivative instruments for trading purposes
and we believe that any increase in market risk created by holding derivatives should be offset by the exposures they
modify.
Fair Value
In accordance with SFAS No. 157, we use fair value measurements to record adjustments to certain financial assets and
liabilities and to determine fair value disclosures. When developing
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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; and (g) credit spreads, as well as other relevant
economic measures. See Note 10.
Revenue Taxes
We account for revenue-based taxes assessed by governmental entities as a separate cost collected from customers for
remittance to those governmental entities. Therefore, revenue taxes are accounted for as a cost of sale and presented
separately on the income statement.
Income Tax Expense
NW Natural and its wholly-owned subsidiaries file consolidated federal and state income tax returns. Current income
taxes are allocated based on each entity’s respective taxable income or loss and investment tax credits as if each entity
filed a separate return. We account for income taxes in accordance with SFAS No. 109, “Accounting for Income Taxes.”
SFAS No. 109 requires recognition of deferred tax liabilities and assets for the future tax consequences of events that
have been included in the consolidated financial statements or tax returns. Under this method, deferred tax liabilities and
assets are determined based on the difference between the financial statement and tax basis of assets and liabilities using
enacted tax rates in effect for the year in which the differences are expected to reverse (see Note 8).
SFAS No. 109 also requires recognition of deferred income tax assets and liabilities for temporary differences where
regulators prohibit deferred income tax treatment for ratemaking purposes. We have recorded a deferred tax liability
equivalent to $69.9 million and $68.6 million at December 31, 2008 and 2007, respectively, to recognize future taxes
payable resulting from transactions that have previously been reflected in the financial statements for these temporary
differences. Regulatory assets or liabilities corresponding to such additional deferred income tax assets or liabilities may be
recorded to the extent we believe they will be recoverable from or payable to customers through the ratemaking process.
Pursuant to SFAS No. 71, a corresponding regulatory asset has been recorded which represents the probable future
revenue that will result from inclusion in rates charged to customers of taxes which will be paid in the future. The probable
future revenue to be recorded takes into consideration the additional future taxes which will be generated by that revenue.
Amounts applicable to income taxes due from customers primarily represent differences between the book and tax basis
of net utility plant in service and actual removal costs incurred.
Deferred investment tax credits on utility plant additions and leveraged leases, which reduce income taxes payable, are
deferred for financial statement purposes and amortized over the life of the related plant or lease.
Other Income and Expense—Net
Other income and expense—net consists of income from company-owned life insurance, interest on deferred regulatory
account balances and short-term debt cash investments, income
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from equity investments, gain on sale of investments, non-operating expenses related to our proposed pipeline project and
other miscellaneous income and expense from merchandise sales, rents, leases and other items.
Thousands
Gains from company-owned life insurance
Interest income
Income from equity investments
Net interest on deferred regulatory accounts
Gain on sale of investments
Other
Total other income and expense - net
2008
$ 2,190
250
667
552
1,737
(1,650)
$ 3,746
2007
$ 1,939
537
130
84
1,544
(2,789)
$ 1,445
2006
$2,609
363
191
(177)
(852)
$2,134
Earnings Per Share
Basic earnings per share are computed using the weighted average number of common shares outstanding each year.
Diluted earnings per share reflect the potential effects of the exercise of stock options and other stock-based
compensation. Diluted earnings per share are calculated as follows:
Thousands, except per share amounts
Net income
2008
$ 69,525
2007
$ 74,497
2006
$ 63,415
26,438
156
26,594
26,821
174
26,995
27,540
117
27,657
Average common shares outstanding - basic
Effect on shares from stock based compensation
Average common shares outstanding - diluted
Earnings per share of common stock - basic
$
2.63
$
2.78
$
2.30
Earnings per share of common stock - diluted
$
2.61
$
2.76
$
2.29
For the years ended December 31, 2008, 2007 and 2006, 1,248 shares, 442 shares and 4,681 shares, respectively,
represent the number of stock options which were excluded from the calculation of diluted earnings per share because the
effect was antidilutive.
2.
CONSOLIDATED SUBSIDIARY OPERATIONS AND SEGMENT INFORMATION:
We operate in two primary reportable business segments, local gas distribution and gas storage. We also have other
investments and business activities not specifically related to one of these two reporting segments which we aggregate and
report as Other. We also refer to our local gas distribution business as the “utility,” and our “gas storage” and “other”
business segments as “non-utility.” Our gas storage segment includes Gill Ranch, LLC (Gill Ranch), and our “other”
segment includes our equity investment in a natural gas transmission pipeline and our Financial Corporation subsidiary.
Local Gas Distribution
Our local gas distribution segment is a regulated utility principally engaged in the purchase, sale and delivery of natural gas,
including related services, to customers in Oregon and southwest Washington. As a regulated utility, we are responsible
for building and maintaining a safe and reliable pipeline distribution system, purchasing sufficient gas supplies from
producers
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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 by the WUTC. Gas distribution also includes taking customer-owned gas and transporting it
from interstate pipeline connections, or city gates, to the customers’ end-use facilities for a fee, also approved by the
OPUC or WUTC. Approximately 90 percent of our customers are located in Oregon and 10 percent are in Washington.
On an annual basis, residential and commercial customers typically account for about 55 percent of our utility’s total
volumes delivered and about 85 percent of gross operating revenues, while industrial customers account for about 45
percent of volumes and about 13 percent of gross revenues. The remaining 2 percent of gross operating revenues is
derived from miscellaneous services and other regulatory charges.
Industrial customers we serve include: pulp, paper and other forest products; the manufacture of electronic,
electrochemical and electrometallurgical products; the processing of farm and food products; the production of various
mineral products; metal fabrication and casting; the production of machine tools, machinery and textiles; the manufacture
of asphalt, concrete and rubber; printing and publishing; nurseries; government and educational institutions; and electric
generation. No individual customer or industry group accounts for a significant portion of our revenues or margins.
Gas Storage
Our gas storage business segment includes natural gas storage services provided to interstate and intrastate customers in
the Pacific Northwest using underground gas storage and pipeline facilities we own and operate. We also use an
independent energy marketing company to provide asset optimization services for the utility under a contractual
arrangement, the results of which are included in this business segment. For each of the years ended December 31, 2008,
2007 and 2006, this business segment derived a majority of its revenues from a few large storage customers who provide
energy related services, including natural gas distribution, electric generation and energy marketing companies. Five
storage customers currently account for over 90 percent of our existing contract storage capacity, with the largest
customer accounting for about half of that total capacity. These five customers have contracts that expire at various dates
through March 2015, with the largest customer’s contract expiring in March 2015.
Results for the gas storage segment include revenues, net of amounts shared with core utility customers, from a contract
with an independent energy marketing company that optimizes the use of our utility assets when not needed to serve core
utility customers. In Oregon, we retain 80 percent of the pre-tax income from these services when the costs of the
capacity have not been included in utility rates, or 33 percent of the pre-tax income when the costs have been included in
utility rates. The remaining 20 percent and 67 percent, respectively, are credited to a deferred regulatory account for
crediting back to core utility customers. We have a similar sharing mechanism in Washington for revenue derived from
storage and third party optimization.
In September 2007, we announced a joint project with Pacific Gas & Electric Company (PG&E) to develop a new
underground natural gas storage facility at Gill Ranch near Fresno, California. We formed a wholly-owned subsidiary of
NW Natural to develop and operate the
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facility. Gill Ranch Storage, LLC, will initially own 75 percent of the project, and PG&E will own 25 percent. As of
December 31, 2008 and 2007, our investment balance in Gill Ranch was $13.1 million and $0.3 million, respectively.
Other
We have non-utility investments and other business activities which are aggregated and reported as a business segment
called “other.” Although in the aggregate these investments and activities are not material, we identify and report them as a
stand-alone segment based on our current organizational structure and decision-making process because these business
investments and activities are not specifically related to our utility or gas storage segments. This segment primarily consists
of an equity method investment in a joint venture to build and operate an interstate gas transmission pipeline in Oregon
(Palomar) and other pipeline assets in Financial Corporation. This segment also includes some operating and nonoperating expenses of the parent company that cannot be charged to utility operations. As of December 31, 2008 and
2007, our investment balance in Palomar was $14.2 million and $6.0 million, respectively. The total cost estimate for the
entire 217-mile pipeline, if constructed, is estimated to be between $700 million and $800 million, with our current 50
percent share estimated at between approximately $350 million and $400 million. Palomar has executed binding
precedent agreements with shippers, including our own utility, for a majority of the current design capacity on the pipeline.
These agreements also provide commitments of credit support to the project. Our maximum loss exposure related to
Palomar at December 31, 2008 would be limited to our investment balance of $14.2 million less any commitments or
credit support from third parties.
In April 2008, NW Natural sold its investment in a Boeing 737-300 aircraft for approximately $6.8 million total including
accrued rents. We purchased the aircraft in 1987 and leased it to Continental Airlines for the entire time it was owned by
NW Natural. As a result of the sale, we recognized an after-tax gain of $1.1 million in the second quarter of 2008. In
2007, we sold our limited partnership interest in two wind power electric generation projects in California for $2.1 million,
which resulted in an after-tax net gain on sale of $0.9 million.
Financial Corporation holds certain non-utility financial investments, but its assets primarily consist of an active, whollyowned subsidiary which owns a 10 percent interest in an 18-mile interstate natural gas pipeline. Financial Corporation’s
total assets were $1.3 million and $1.4 million at December 31, 2008 and 2007, respectively.
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Segment Information Summary
The following table presents summary financial information about the reportable segments for the years ended 2008, 2007
and 2006. Inter-segment transactions are insignificant.
3.
Thousands
2008
Net operating revenues
Depreciation and amortization
Income from operations
Net income
Total assets at Dec. 31, 2008
Utility
Gas Storage
Other
Total
$ 337,596
70,690
128,957
58,739
2,289,601
$
18,459
1,469
14,943
8,363
72,073
$
160
136
2,423
16,478
$ 356,215
72,159
144,036
69,525
2,378,152
2007
Net operating revenues
Depreciation and amortization
Income from operations
Net income
Total assets at Dec. 31, 2007
$ 351,875
67,410
140,434
64,938
1,940,722
$
16,999
933
14,481
8,454
62,651
$
168
8
1,105
10,688
$ 369,042
68,343
154,923
74,497
2,014,061
2006
Net operating revenues
Depreciation and amortization
Income from operations
Net income
$ 327,267
63,552
126,366
56,653
$
12,761
883
9,870
5,982
$
148
526
780
$ 340,176
64,435
136,762
63,415
CAPITAL STOCK:
Common Stock
At the annual meeting of shareholders, held on May 22, 2008, our shareholders approved an amendment to our Restated
Articles of Incorporation increasing the total number of authorized shares of common stock from 60 million to 100 million.
At December 31, 2007, we had 60 million common shares authorized.
As of December 31, 2008, we had reserved for issuances 203,533 shares of common stock under the Employee Stock
Purchase Plan (ESPP), 577,713 shares under our Dividend Reinvestment and Direct Stock Purchase Plan and 1,318,810
shares under our Restated Stock Option Plan (Restated SOP).
In connection with the restatement of our Restated Articles of Incorporation, effective May 31, 2006, the par value of our
common stock was eliminated. As a result, at December 31, 2008 and 2007, our “common stock” and “premium on
common stock” account balances are reflected on the balance sheet as “common stock.”
Stock Repurchase Program
We have a share repurchase program for our common stock under which we purchase shares on the open market or
through privately negotiated transactions. We have Board authorization through May 2009 to repurchase up to an
aggregate of 2.8 million shares, or up to $100.0 million. No shares of common stock were repurchased pursuant to this
program in 2008. Since inception in 2000, a total of 2.1 million shares have been repurchased at a total cost of $83.3
million.
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Summary of Changes in Common Stock
The following table shows the changes in the number of shares of our common stock issued and outstanding for the years
2008, 2007 and 2006:
Shares
27,579,296
31,397
68,548
(395,500)
27,283,741
21,373
75,850
(973,616)
26,407,348
19,500
74,340
26,501,188
Balance, Dec. 31, 2005
Sales to employees
Exercise of stock options - net
Repurchase
Change to no-par common stock
Balance, Dec. 31, 2006
Sales to employees
Exercise of stock options - net
Repurchase
Balance, Dec. 31, 2007
Sales to employees
Exercise of stock options - net (1)
Repurchase
Balance, Dec. 31, 2008
(1)
4.
Premium on
common
stock
(thousands)
$
296,471
285
(1,461)
(295,295)
$
n/a
n/a
n/a
$
n/a
n/a
n/a
$
-
For further details, see Restated SOP in Note 4.
STOCK-BASED COMPENSATION:
We have the following stock-based compensation plans: the Long-Term Incentive Plan (LTIP); the Restated SOP; the
Employee Stock Purchase Plan (ESPP); and the Non-Employee Directors Stock Compensation Plan (NEDSCP). These
plans are designed to promote stock ownership in NW Natural by employees and officers and, in the case of the
NEDSCP, by non-employee directors.
Long-Term Incentive Plan. The LTIP is intended to provide a flexible, competitive compensation program for eligible
officers and key employees. An aggregate of 500,000 shares of common stock was authorized for grants under the LTIP
as stock bonus, restricted stock or performance-based stock awards. Shares awarded under the LTIP may be purchased
on the open market.
At December 31, 2008, 247,898 shares of common stock were available for award under the LTIP, assuming that
performance based grants currently outstanding are awarded at the target level. The LTIP stock awards are
compensatory awards for which compensation expense is recognized based on the fair value of performance-based stock
awards earned, or a pro rata amortization over the vesting period for the outstanding awards of restricted stock.
Performance-based Stock Awards. Since the LTIP’s inception in 2001, performance-based stock awards
have been granted annually based on three-year performance periods. At December 31, 2008, certain performancebased stock award measures had been achieved for
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the 2006-08 award period. Accordingly, participants are estimated to receive 61,654 shares of common stock and a
dividend equivalent cash payment equal to the number of shares of common stock received on the award payout
multiplied by the aggregate cash dividends paid per share during the performance period. At December 31, 2007 and
2006, we awarded 66,666 and 40,446 shares of common stock, respectively, for the 2005-07 and 2004-06 award
periods, plus a dividend equivalent cash payment equal to the number of shares of common stock received on the award
payout multiplied by the aggregate cash dividends paid per share during the performance period. During 2008, we
accrued and expensed $0.5 million related to the 2006-08 performance-based stock award, and on a cumulative basis
we accrued a total $2.0 million related to the 2006-08 performance period. In 2007 and 2006, we accrued and expensed
$0.6 million and $0.9 million, respectively, related to the 2005-07 and 2004-06 performance-based stock award periods,
and on a cumulative basis we accrued a total of $2.0 million and $1.7 million, respectively.
At December 31, 2008, the aggregate number of performance-based shares granted and outstanding at the threshold,
target and maximum levels were as follows:
Year
Awarded
Performance
Period
2007
2008
2007-09
2008-10
Total
Threshold
7,980
9,215
17,195
Performance Share Awards Outstanding
Target
42,000
48,500
90,500
Maximum
84,000
97,000
181,000
The threshold level estimates future payout assuming the minimum award payable is reached for each component of the
formula in the LTIP. For each of these performance periods, awards will be based on total shareholder return relative to a
peer group of gas distribution companies over the three-year performance period and on performance results achieved
relative to specific core and non-core strategies. Compensation expense is recognized in accordance with SFAS
No. 123R, based on performance levels achieved and an estimated fair value using a Black-Scholes or binomial model.
The weighted-average per share grant date fair value of unvested shares at December 31, 2008 and 2007 was $14.73
and $25.45, respectively. The weighted-average per share grant date fair value of shares vested during the year was
$38.40 and granted during the year was $10.89. In 2008, under these LTIP grants we accrued $1.0 million and expensed
$0.9 million, while in 2007, we accrued $2.7 million and expensed $2.3 million and in 2006 we accrued and expensed
$1.0 million.
Restricted Stock Awards. Restricted stock awards also have been granted under the LTIP. A restricted stock
award was granted in 2004 consisting of 5,000 shares that will vest ratably over the period 2005-09, and a restricted
stock award was granted in 2006 consisting of 6,500 shares that will vest ratably over the period 2007-09. A total of
8,334 restricted stock award shares were vested at December 31, 2008. Compensation expense is recognized ratably
over the vesting period.
Restated Stock Option Plan. A total of 2,400,000 shares of common stock were reserved for issuance under the
Restated SOP. Options under the Restated SOP may be granted only to officers and key employees designated by a
committee of our Board of Directors. All options are granted at an option price not less than the market value on the date
of grant and may be exercised for a period not exceeding 10 years and 7 days from the date of grant. Option holders
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may exchange shares they have owned for at least six months, at the current market price, to purchase shares at the
option price. We use original issue shares upon exercise of options under the plan.
The fair value of each stock option is estimated on the grant date using the Black-Scholes option pricing model with the
following weighted average assumptions and outcomes:
February
2008
2.8%
4.7
18.4%
3.5%
3.8%
$5.34
$37.95
Risk-free interest rate
Expected life (in years)
Expected market price volatility factor
Expected dividend yield
Forfeiture rate
Weighted average grant date fair value
Present value of options granted
September
2008
3.0%
4.7
18.4%
2.9%
3.9%
$7.05
$44.50
2007
4.7%
6.2
17.2%
3.2%
4.4%
$7.66
$33.38
2006
4.5%
6.2
22.8%
4.0%
3.3%
$6.29
$26.00
The expected life of the 2008 grants was calculated based on our actual experience with previously exercised option
grants. The simplified formula for “plain vanilla” options was used in 2007 and 2006 to determine the expected life as
defined and permitted by Staff Accounting Bulletin No. 107. The risk-free interest rate was based on the implied yield
currently available on U.S. Treasury zero-coupon issues with a life equal to the expected life of the options. Historical data
was employed in order to estimate the volatility factor, measured on a daily basis, for a period equal to the duration of the
expected life of the option awards. The dividend yield was based on management’s current estimate for dividend payout
at the time of grant. We expense the total cost of stock option awards granted to retirement eligible employees at the date
of grant in accordance with SFAS No. 123R and the retirement vesting provisions of our option agreements.
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Information regarding the Restated SOP activity for the three years ended December 31, 2008 is summarized as follows:
Balance outstanding, Dec. 31, 2005
Granted
Exercised
Forfeited
Balance outstanding, Dec. 31, 2006
Granted
Exercised
Forfeited
Balance outstanding, Dec. 31, 2007
Granted
Exercised
Forfeited
Balance outstanding, Dec. 31, 2008
Shares available for grant
Dec. 31, 2006
Dec. 31, 2007
Dec. 31, 2008
Option
Shares
308,500
97,800
(69,300)
(3,000)
334,000
100,600
(75,850)
(1,000)
357,750
119,050
(74,340)
(6,050)
396,410
Price per Share
Weighted Average
Range
Exercise Price
$20.25 - 38.30
$
29.26
34.29
34.29
20.25 - 31.34
27.15
31.34 - 34.29
32.52
20.25 - 38.30
31.14
44.48
44.48
20.25 - 34.95
28.73
44.48
44.48
20.25 - 44.48
35.36
43.29 - 51.09
43.62
20.25 - 44.48
30.70
26.30 - 44.48
41.56
$20.25 - 51.09
$
38.62
Intrinsic
Value
(In millions)
n/a
n/a
$
0.8
n/a
n/a
n/a
1.4
n/a
4.8
n/a
1.3
n/a
$
2.3
1,135,000
1,035,400
922,400
In the year ended December 31, 2008, cash of $2.3 million was received for option shares exercised and a $0.3 million
related tax benefit was realized. For the 12 months ended December 31, 2008, 2007 and 2006, the total fair value of
options that vested was $0.3 million, $0.2 million and $0.4 million, respectively.
The following table summarizes additional information about stock options outstanding and exercisable at December 31,
2008:
Range of Exercise Prices
$20.25 - 51.09
Outstanding
WeightedAverage
Stock
Remaining
Options
Life in Years
396,410
7.47
Stock
Options
167,410
Exercisable
(In millions)
WeightedAggregate
Average
Intrinsic
Exercise
Value
Price
$
1.8
$
33.77
WeightedAverage
Remaining
Life in Years
6.04
As of December 31, 2008, there was $0.7 million of unrecognized compensation cost related to the unvested portion of
outstanding stock option awards expected to be recognized over a period extending through 2011.
Employee Stock Purchase Plan. The ESPP allows employees to purchase common stock at 85 percent of the closing
price on the trading day immediately preceding the initial offering date, which is set annually. Each eligible employee may
purchase up to $24,000 worth of stock through payroll deductions over a 12-month period. We use original issue shares
for shares purchased under the plan.
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In accordance with SFAS No. 123R, stock-based compensation expense is recognized as operations and maintenance
expense or is capitalized as part of construction overhead. The following table summarizes the allocations of stock-based
compensation grants under our LTIP, Restated SOP and ESPP:
Thousands
Operations and maintenance expense, for stock-based compensation
Income tax effect
Net stock-based compensation effect on net income
2008
$1,598
(623)
$ 975
2007
$ 2,986
(1,165)
$ 1,821
2006
$2,304
(898)
$1,406
Amounts capitalized
$ 282
$
$ 407
479
Non-Employee Directors Stock Compensation Plan. In February 2004, the NEDSCP was amended to permit nonemployee directors to receive stock awards either in cash or in stock. As a result of modifications to the directors’
compensation arrangements, the NEDSCP was further amended in September 2004 to eliminate any further awards,
either in cash or stock, on and after January 1, 2005.
Prior to the September 2004 amendment to the NEDSCP, if non-employee directors elected to receive their awards in
stock, approximately $100,000 worth of common stock was awarded upon joining the Board. These stock awards were
subject to vesting and to restrictions on sale and transferability. The shares vested in monthly installments over the five
calendar years following the award. On January 1 of each year following the initial award, non-employee directors who
elected to receive their awards in stock were awarded an additional $20,000 worth of restricted stock, which vested in
monthly installments in the fifth year following the award (after the previous award had fully vested). We hold the
certificates for the restricted shares until the non-employee director ceases to be a director. Participants receive all
dividends and have full voting rights on both vested and unvested shares. All awards vest immediately upon the death of a
director or upon a change in control of the Company. Any unvested shares are considered to be unearned compensation,
and thus are forfeited if the recipient ceases to be a director. The shares were purchased in the open market at the time of
the award. At December 31, 2008, all shares were fully vested.
5.
COST AND FAIR VALUE BASIS OF LONG-TERM DEBT:
The issuance of first mortgage debt, including secured medium-term notes, under the Mortgage and Deed of Trust
(Mortgage), is limited by eligible property, including property additions, adjusted net earnings and other provisions of the
Mortgage. The Mortgage constitutes a first mortgage lien on substantially all of our utility property.
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The maturities on the long-term debt outstanding for each of the 12-month periods through December 31, 2013 amount
to: none in 2009; $35 million in 2010; $10 million in 2011; $40 million in 2012; and none in 2013. Holders of certain
long-term debt have put options that, if exercised, would accelerate the maturities by $20 million in 2009.
Thousands (December 31)
Medium-Term Notes
First Mortgage Bonds:
6.31 % Series B due 2007(1)
6.80 % Series B due 2007(2)
6.50% Series B due 2008(3)
4.11% Series B due 2010
7.45% Series B due 2010
6.665% Series B due 2011
7.13% Series B due 2012
8.26% Series B due 2014
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
9.05% Series A due 2021
5.62% Series B due 2023
7.72% Series B due 2025
6.52% Series B due 2025
7.05% Series B due 2026
7.00% Series B due 2027
6.65% Series B due 2027
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
2008
$
Less long-term debt due within one year
Total long-term debt
$
10,000
25,000
10,000
40,000
10,000
40,000
25,000
40,000
22,000
10,000
20,000
10,000
40,000
20,000
10,000
20,000
20,000
20,000
10,000
20,000
10,000
30,000
40,000
10,000
512,000
512,000
2007
$
$
5,000
10,000
25,000
10,000
40,000
10,000
40,000
25,000
40,000
22,000
10,000
20,000
10,000
40,000
20,000
10,000
20,000
20,000
20,000
10,000
20,000
10,000
30,000
40,000
10,000
517,000
5,000
512,000
2006
$
$
20,000
9,500
5,000
10,000
25,000
10,000
40,000
10,000
40,000
25,000
40,000
22,000
10,000
20,000
10,000
40,000
20,000
10,000
20,000
20,000
20,000
10,000
20,000
10,000
30,000
40,000
10,000
546,500
29,500
517,000
(1)
Redeemed at maturity in March 2007.
Redeemed at maturity in May 2007.
(3) Redeemed at maturity in July 2008.
(2)
No long-term debt was issued during 2008 and 2007. In 2006, we issued and sold $25 million of 5.15 percent Series B
secured medium term notes due 2016. Proceeds from this sale were used, in part, to repay short-term debt and fund our
ongoing utility construction program.
Because we elected not to implement SFAS No. 159, we do not adjust our long-term debt balance to fair value. The
following table provides an estimate of the fair value of our long-term debt, using market prices in effect on the valuation
date. Interest rates for debt with similar
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credit ratings, terms and remaining maturities were used to estimate fair value for long-term debt issues.
Dec. 31, 2008
Estimated
Carrying
Fair Value(1)
Amount
$ 512,000
$
505,828
Thousands
Long-term debt including amounts due within one year
(1)
6.
Dec. 31, 2007
Estimated
Carrying
Fair Value(1)
Amount
$ 517,000
$
557,916
This estimate is calculated net of commission fees.
NOTES PAYABLE AND CREDIT FACILITIES:
Our primary source of short-term funds is from the sale of commercial paper notes payable. In addition to issuing
commercial paper to meet seasonal working capital requirements, including the financing of gas purchases, gas inventories
and accounts receivable, short-term debt is used temporarily to fund capital requirements. Commercial paper is
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, 2008 and 2007, the amounts and average interest
rates of commercial paper debt outstanding were $248.0 million and 1.6 percent and $143.1 million and 4.4 percent,
respectively.
We have a multi-year $250 million syndicated credit agreement, pursuant to which we may extend commitments for
additional one-year periods subject to lender approval. We extended commitments with six of the seven lenders under this
credit agreement, with commitments totaling $210 million, to May 31, 2013. The credit agreement also allows us to
request increases in the total commitment amount from time to time, up to a maximum amount of $400 million, and to
replace any lenders who decline to extend the terms of the credit agreement. The credit agreement also permits the
issuance of letters of credit in an aggregate amount up to the applicable total borrowing commitment. Any principal and
unpaid interest owed on borrowings under the credit agreement are due and payable on or before the expiration date,
which is May 31, 2013 for all except one lender, which has a commitment amount totaling $40 million that is due and
payable on or before May 31, 2012. Additionally, we entered into two committed bilateral bank lines of credit totaling
$30 million in November 2008, of which $15 million expired December 31, 2008 and $15 million expired February 27,
2009. There were no outstanding balances under this credit agreement and no letters of credit issued or outstanding at
December 31, 2008 and 2007.
The syndicated 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 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 syndicated credit agreement also requires us to maintain a consolidated indebtedness to total capitalization ratio of 70
percent or less. Failure to comply with this covenant would entitle the lenders to terminate their lending commitments and
accelerate the maturity of all amounts outstanding. We were in compliance with this covenant at December 31, 2008 and
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2007, with a consolidated indebtedness to total capitalization ratio of 54.7 percent, and 52.7 percent, respectively.
7.
PENSION AND OTHER POSTRETIREMENT BENEFITS:
We maintain two qualified non-contributory defined benefit pension plans, several non-qualified supplemental pension
plans for eligible executive officers and certain key employees, and other postretirement benefit plans for certain
employees. Only the two qualified defined benefit pension plans have plan assets, which are held in a qualified trust to fund
retirement benefits. Effective January 1, 2007, the qualified defined benefit plan and the postretirement welfare plans for
non-bargaining unit employees were closed to new employees. Instead, non-bargaining unit employees hired or re-hired
after December 31, 2006 are currently provided an enhanced Retirement K Savings Plan (RKSP) benefit. Benefits
provided to bargaining unit employees under the Retirement Plan for Bargaining Unit Employees are not affected by these
changes.
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 over the three-year period ended December 31, 2008,
and a summary of the funded status and amounts recognized in the consolidated balance sheets using measurement dates
of December 31, 2008, 2007 and 2006:
Postretirement Benefits
Pension Benefits
Other Benefits
2008
2007
2006
2008
2007
2006
Thousands
Reconciliation of change in benefit obligation:
Obligation at January 1
Service cost
Interest cost
Benefits paid
Plan amendments
Change in assumptions
Net actuarial (gain) or loss
Liability transfer
Obligation at December 31
$ 260,561
6,141
17,373
(16,247)
5
9,146
4,291
(143)
$ 281,127
$269,410
8,708
16,057
(15,924)
3,887
(23,916)
2,339
$260,561
$267,854
7,745
14,901
(13,183)
(9,208)
1,301
$269,410
$ 22,186
521
1,403
(1,259)
839
173
$ 23,863
$ 22,436
505
1,293
(1,299)
(645)
(104)
$ 22,186
$ 20,398
555
1,184
(1,015)
15
133
1,166
$ 22,436
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
$ 241,417
(63,267)
1,211
(16,247)
$ 163,114
$236,518
19,658
1,166
(15,924)
$241,418
$218,555
30,088
1,058
(13,183)
$236,518
$
1,259
(1,259)
$
-
$
1,298
(1,298)
$
-
$
Funded status:
Funded status at December 31
Unrecognized transition obligation
Unrecognized prior service cost
Unrecognized net actuarial loss
Net amount recognized
$(118,013)
6,963
116,239
$ 5,189
$ (19,143)
8,212
20,995
$ 10,064
$ (32,892)
5,512
45,862
$ 18,482
$(23,863)
1,646
1,669
2,525
$(18,023)
$(22,186)
2,058
1,866
1,514
$(16,748)
$(22,436)
2,469
2,063
2,288
$(15,616)
96
1,015
(1,015)
$
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We adopted SFAS No. 158 effective December 31, 2006. Under SFAS No. 158, any actuarial gains and losses, prior
service costs and transition assets or obligations that were not recognized under previous accounting standards must be
recognized in accumulated other comprehensive income (AOCI) under common stock equity, net of tax, until they are
amortized as a component of net periodic benefit cost. We consider the recognition of the underfunded status of the
qualified defined benefit plans and postretirement benefit plans to be subject to regulatory deferral under SFAS No. 71.
The unrecognized net gains and losses, prior service costs and transition obligations relating to our qualified defined benefit
pension and postretirement benefit plans are recognized as regulatory assets. An estimated $8.1 million for the qualified
plans, consisting of $6.2 million of actuarial losses, $1.5 million of prior service costs and transition obligations of $0.4
million, will be amortized from the regulatory asset account to net periodic benefit cost in 2009. The gains and losses,
prior service costs and transition obligations related to our non-qualified supplemental pension plans are recognized in
AOCI, net of tax, under common stock equity because these expenses are not the basis for regulatory recovery;
however, these amounts are not material. In 2008, an estimated $0.4 million consisting of actuarial losses of $0.4 million
and negligible prior service costs for the non-qualified plans were amortized from AOCI to net periodic benefit cost.
Our qualified defined benefit pension plans had an aggregate projected benefit obligation of $261.5 million, $243.1 million
and $255.5 million at December 31, 2008, 2007 and 2006, respectively, and the fair value of plan assets was $163.1
million, $241.4 million and $236.5 million, respectively. Changes in valuation assumptions impact our projected benefit
obligations. Benefit obligations at December 31, 2008 increased $7.4 million due to a decrease in our discount rate
assumptions and increased by $5.0 million due to updating our mortality tables. The projected benefit obligations at
December 31, 2007 decreased $23.9 million due to an increase in the discount rate assumptions and increased by $3.4
million due to an increase in the benefit payments for certain retirees. The combination of investment returns and future
cash contributions by the company is expected to provide sufficient funds to cover all future benefit obligations of the
plans.
An assumed discount rate was determined independently for each pension plan and other postretirement benefit plan
based on the Citigroup Above Median Curve (discount rate curve) using high quality bonds (i.e. rated AA- or higher by
Standard & Poor’s or Aa3 or higher by Moody’s Investors Service). The discount rate curve was then applied to match
the estimated cash flows to reflect the timing and amount of expected future benefit payments for these plans.
The expected long-term rate of return on plan assets was developed as a weighted average of the expected earnings for
the target asset portfolio. In developing the expected long-term rate of return assumption, consideration was given to the
historical performance of each asset class in which the plans’ assets are invested and the target asset allocation for plan
assets.
Our investment strategy and policies for the qualified pension plan assets held in the Retirement Trust Fund were
approved by our retirement committee, which is composed of senior management employees. The policies set forth the
guidelines and objectives governing the investment of plan assets. Plan assets are invested for total return with appropriate
consideration for liquidity and portfolio risk. All investments are expected to satisfy the requirements of the rule of prudent
investments as set forth under the Employee Retirement Income Security Act of 1974. The approved asset classes are
cash and short-term investments,
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fixed income, common stock and convertible securities, absolute and real return strategies, real estate and investments in
our common stock. Plan assets may be invested in separately managed accounts or in commingled or mutual funds. Rebalancing will take place periodically as needed, or when significant cash flows occur, in order to maintain the allocation of
assets within the stated target ranges. Our expected long-term rate of return is based upon historical index returns by asset
class, adjusted by a factor based on our historical return experience and active portfolio management by professional
investment managers. The Retirement Trust Fund is not currently invested in any NW Natural securities.
Our pension plan asset allocation at December 31, 2008 and 2007, and the target allocation and expected long-term rate
of return by asset category, are as follows:
Percentage of
Plan Assets
Dec. 31,
2008
2007
14.3%
18.1%
9.6%
13.1%
17.9%
24.9%
21.2%
13.3%
11.3%
8.9%
18.9%
16.3%
6.8%
5.4%
Asset Category
US Large Cap Equity
US Small/Mid Cap Equity
Non-US Equity
Fixed Income
Real Estate
Absolute Return Strategy
Real Return Strategy
Weighted Average
Target
Allocation
20%
15%
20%
15%
8%
15%
7%
Expected Longterm
Rate of Return
8.50%
9.50%
8.75%
5.50%
7.75%
9.00%
7.75%
8.25%
Our non-qualified supplemental defined benefit pension plans’ benefit obligations were $19.6 million, $17.5 million and
$13.9 million at December 31, 2008, 2007 and 2006, respectively. These plans are not subject to regulatory deferral and
the changes in actuarial gains and losses, prior service costs and transition assets or obligations are recognized in AOCI
under common stock equity, net of tax, until they are amortized as a component of net periodic benefit cost. Although the
plans are unfunded plans with no plan assets due to their nature as non-qualified plans, we indirectly fund our obligations
with company- and trust-owned life insurance.
Our plans for providing postretirement benefits other than pensions also are unfunded plans, but are subject to regulatory
deferral. The gains and losses, prior service costs and transition assets or obligations for these plans were recognized as a
regulatory asset. The accumulated postretirement benefit obligation for those plans was $23.9 million, $22.2 million and
$22.4 million at December 31, 2008, 2007 and 2006, respectively.
Net periodic benefit cost consists of service costs, interest costs, the amortization of actuarial gains and losses, the
expected returns on plan assets and, in part, on a market-related valuation of assets. The market-related valuation reflects
differences between expected returns and actual investment returns, which are recognized over a three-year period from
the year in which they occur, thereby reducing year-to-year net periodic benefit cost volatility.
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The following tables provide the components of net periodic benefit cost for the qualified and non-qualified pension and
other postretirement benefit plans for the years ended December 31, 2008, 2007 and 2006 and the assumptions used in
measuring these costs and benefit obligations:
Thousands
Service cost
Interest cost
Expected return on plan assets
Amortization of transition obligations
Amortization of prior service costs
Amortization of net loss
Net periodic benefit cost
Assumptions for net periodic benefit cost:
Discount rate
Rate of increase in compensation
Expected long-term rate of return
Assumptions for funded status:
Discount rate
Rate of increase in compensation
Expected long-term rate of return
$
$
Pension Benefits
2008
2007
6,141
$
8,708
17,373
16,057
(19,087)
(18,490)
19
1,253
1,188
385
2,123
6,084
$
9,586
2006
7,745
14,901
(17,611)
979
3,520
9,534
$
$
Other Postretirement
Benefits
2008
2007
2006
$ 521
$ 505
$ 556
1,403
1,293
1,184
411
411
411
197
197
195
25
1
$ 2,532
$ 2,431
$ 2,347
6.76%-6.87%
3.5%-5.0%
8.25%
6.0%-6.05%
4.0%-5.0%
8.25%
5.75%
4.0%-5.0%
8.25%
6.56%
n/a
n/a
5.91%
n/a
n/a
5.75%
n/a
n/a
6.44%-6.72%
3.5%-5.0%
8.25%
6.76%-6.87%
4.0%-5.0%
8.25%
6.0%-6.05%
4.0%-5.0%
8.25%
7.12%
n/a
n/a
6.56%
n/a
n/a
5.91%
n/a
n/a
The assumed annual increase in trend rates used in measuring other postretirement benefits as of December 31, 2008
were 9.5 percent for medical and 11.5 percent for prescription drugs. Medical costs were assumed to decrease gradually
each year to a rate of 5.0 percent by 2017, while prescription drug costs were assumed to decrease gradually each year
to a rate of 5.0 percent by 2022.
Assumed health care cost trend rates can have a significant effect on the amounts reported for the health care plans. A one
percentage point change in assumed health care cost trend rates would have the following effects:
Thousands
Effect on total of service and interest cost components of net periodic postretirement health
care benefit cost
Effect on health care cost component of the accumulated postretirement benefit obligation
99
1%
Increase
1%
Decrease
$
$
$
$
51
732
(45)
(646)
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The following table provides information regarding employer contributions and benefit payments for the two qualified
pension plans, the non-qualified pension plans and the other postretirement benefit plans for the years ended
December 31, 2008 and 2007, and estimated future payments:
Thousands
Employer Contributions by Plan Year
2007
2008
2009 (estimated)
Benefit Payments
2006
2007
2008
Estimated Future Payments
2009
2010
2011
2012
2013
2014-2018
$
Pension Benefits
1,606
1,645
10,391
$
Other Benefits
1,298
1,259
2,063
$
13,183
15,924
16,247
$
1,015
1,298
1,259
$
16,476
17,030
17,385
18,293
18,761
106,004
$
2,063
2,096
2,171
2,101
2,810
10,384
We make contributions to our qualified defined benefit pension plans based on actuarial assumptions and estimates, tax
regulations and funding requirements under federal law. The Pension Protection Act of 2006 (the Act) established new
funding requirements for defined benefit plans. The Act establishes a 100 percent funding target for plan years beginning
after December 31, 2008. However, a delayed effective date of 2011 may apply if the pension plan meets the funding
targets of 92 percent in 2008, 94 percent in 2009 and 96 percent in 2010. Our qualified defined benefit pension plans are
currently underfunded by $98 million at December 31, 2008, and we expect to make at least the minimum contribution
required pursuant to the Act, which is currently estimated at $8 million. We plan to make an additional contribution during
2009, which could bring the total contribution in 2009 up to $40 million. We would need to make a total contribution in
2009 of at least $17 million to avoid any restrictions on benefit payments.
Our RKSP is a qualified defined contribution plan under Internal Revenue Code Section 401(k). We also have nonqualified deferred compensation plans for eligible officers and senior managers. These plans are designed to enhance the
retirement program of employees and to assist them in strengthening their financial security by providing an incentive to
save and invest regularly. Our matching contributions to these plans totaled $2.1 million in 2008, $1.9 million in 2007, and
$1.8 million in 2006. The RKSP includes an Employee Stock Ownership Plan. In addition, we make contributions on
behalf of each union employee to the Western States Office and Professional Employees Pension Fund, a multi-employer
plan. Our contributions totaled $0.4 million in 2008 and 2007 and $0.5 million in 2006.
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8.
INCOME TAXES:
A reconciliation between income taxes calculated at the statutory federal tax rate and the provision for income taxes
reflected in the consolidated financial statements is as follows:
Thousands, except percentages
Income taxes at federal statutory rate
Increase (decrease):
Current state income tax, net of federal tax benefit
Amortization of investment and energy tax credits
Differences required to be flowed-through by regulatory commissions
Gains on company and trust-owned life insurance
Other - net
Total provision for income taxes
2008
$38,571
2007
$41,495
2006
$34,877
4,100
(646)
(704)
(767)
124
$40,678
4,566
(881)
(704)
(679)
263
$44,060
3,655
(994)
(704)
(913)
313
$36,234
Federal statutory tax rate
Increase (decrease):
Current state income tax, net of federal tax benefit
Amortization of investment and energy tax credits
Differences required to be flowed-through by regulatory commissions
Gains on company and trust-owned life insurance
Other - net
Effective tax rate
35.0%
35.0%
35.0%
3.7%
-0.6%
-0.6%
-0.7%
0.1%
36.9%
3.9%
-0.7%
-0.6%
-0.6%
0.2%
37.2%
3.7%
-1.0%
-0.7%
-0.9%
0.3%
36.4%
The provision for income taxes consists of the following:
Thousands
Current
Federal
State
2008
2007
2006
$ (7,970)
(437)
(8,407)
$41,086
7,764
48,850
$ 44,785
7,836
52,621
Total provision for income taxes
42,862
6,223
49,085
$40,678
(4,107)
(683)
(4,790)
$44,060
(14,180)
(2,207)
(16,387)
$ 36,234
Total income taxes paid
$12,300
$56,215
$ 31,270
Deferred
Federal
State
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The following table summarizes the total provision (benefit) for income taxes for the regulated utility and other non-utility
business segments for the three years ended December 31, 2007:
Thousands
Regulated utility:
Current
Deferred
Deferred investment and energy tax credits
Non-utility business segments:
Current
Deferred
Deferred investment and energy tax credits
Total provision for income taxes
2008
2007
2006
$(13,034)
48,790
(646)
35,110
$43,587
(3,856)
(713)
39,018
$ 48,469
(14,810)
(756)
32,903
4,627
941
0
5,568
$ 40,678
5,263
(53)
(168)
5,042
$44,060
4,152
(583)
(238)
3,331
$ 36,234
The following table summarizes the tax effect of significant items comprising our deferred income tax accounts for the two
years ended December 31:
Thousands
Deferred tax liabilities:
Plant and property
Regulatory adjustment for income taxes paid
Regulatory income tax assets
Regulatory liabilities
Non-regulated deferred tax liabilities
Total
Deferred tax assets:
Regulatory assets
Unfunded pension and postretirement obligations
Non-regulated deferred tax assets
Loss and credit carryforwards
Total
Deferred income tax liabilities - net
Deferred investment tax credits
Deferred income taxes and investment tax credits
2008
2007
$ 183,462
2,374
69,948
8,145
426
264,355
$ 159,506
2,356
68,649
478
249
231,238
(4,335)
(2,709)
(471)
(1,557)
(9,072)
255,283
2,548
$ 257,831
(25,973)
(2,118)
(28,091)
203,147
3,193
$ 206,340
We have determined that we are more likely than not to realize all recorded deferred tax assets as of December 31,
2008.
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The following is a reconciliation of the change in our deferred tax balance for the year ended December 31:
Thousands
Deferred tax expense, above
Increase in differences required to be flowed-through
Decrease in minimum pension liability included in AOCI
Decrease in deferred taxes associated with asset held for sale
Decrease in deferred investment tax credits
Change in deferred income tax accounts
2008
$49,731
1,299
(591)
1,698
(646)
$51,491
We calculate our deferred tax assets and liabilities under SFAS No. 109, whereby deferred income taxes are generally
determined based on the difference between the financial statement and tax basis of assets and liabilities using enacted tax
rates in effect in the years in which the differences are expected to reverse. Deferred tax provisions are not recorded in the
income statement for certain temporary differences where regulators require that we flow through deferred income tax
benefits or expenses in the utility ratemaking process.
On February 13, 2008, the Economic Stimulus Act (ESA) was enacted providing an additional first-year tax deduction
for depreciation equal to 50 percent of the adjusted basis of “qualified property.” The extra 50 percent depreciation
deduction in the first year is an acceleration of depreciation deductions that otherwise would have been taken in the later
years of an asset’s recovery period. The accelerated depreciation provisions provided by the ESA is expected to expire
at December 31, 2008. During 2008, we reduced income taxes currently payable by an estimated $13.6 million.
For the year ended December 31, 2008, we had an estimated net operating loss (NOL) for federal and Oregon income
tax purposes of $19.2 million and $23.8 million, respectively, primarily due to the effects of accelerated tax depreciation
provided by the ESA. The federal NOL will be carried back to 2006 for a refund of taxes paid in prior years and the
Oregon NOL will be carried forward to reduce future taxable income. We anticipate that we will be able to use all loss
carryforwards in future years. The 2008 Oregon NOL will expire in 2023.
In July 2006, FASB issued Interpretation No. 48, “Accounting for Uncertainty in Income Taxes, an Interpretation of
FASB Statement No. 109” (FIN 48), which clarifies the accounting for uncertainty in income taxes recognized in the
financial statements in accordance with SFAS No. 109. FIN 48 requires the use of a two-step approach for recognizing
and measuring tax positions taken or expected to be taken in a tax return. First, a tax position should only be recognized
when it is more likely than not, based on technical merits, that the position will be sustained upon examination by the taxing
authority. Second, a tax position that meets the recognition threshold should be measured at the largest amount that has a
greater than 50 percent likelihood of being sustained. We adopted FIN 48 as of January 1, 2007, and had no material
unrecognized tax benefits upon adoption or for the years ended December 31, 2008 and 2007. As a result, no interest or
penalties were accrued for unrecognized tax benefits during the year. The IRS has completed and closed its examination
of the Company’s 2002, 2003 and 2004 tax years. The years after 2004 remain open to further examination by the IRS.
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9.
PROPERTY AND INVESTMENTS:
The following table sets forth the major classifications of our utility plant and accumulated depreciation at December 31:
2008
Thousands, except percentages
Transmission and distribution
Utility storage
General
Intangible and other
Gas stored long-term
Utility plant in service
Construction work in progress
Total utility plant
Less accumulated depreciation
Utility plant-net
Amount
$1,810,747
116,035
100,838
77,650
14,133
2,119,403
23,585
2,142,988
(659,123)
$1,483,865
2007
Weighted
Average
Depreciation
Rate
3.3%
2.5%
3.2%
9.0%
0.0%
3.4%
Weighted
Average
Depreciation
Rate
3.3%
2.6%
3.0%
8.8%
0.0%
3.4%
Amount
$1,735,934
112,984
96,612
71,044
14,232
2,030,806
21,355
2,052,161
(615,533)
$1,436,628
Accumulated depreciation does not include the accumulated provision for asset removal costs of $223.7 million and
$204.9 million at December 31, 2008 and 2007, respectively. These accrued asset removal costs are reflected on the
balance sheets as regulatory liabilities (see Note 1, “Plant and Property and Accrued Asset Removal Costs”).
The following table summarizes our investments in non-utility plant at December 31:
2008
Thousands, except percentages
Non-utility storage
Other
Non-utility plant in service
Construction work in progress
Total non-utility plant
Less accumulated depreciation
Non-utility plant - net
Amount
$ 60,515
4,886
65,401
9,105
74,506
(9,314)
$ 65,192
104
2007
Weighted
Average
Depreciation
Rate
2.5%
Amount
$ 54,083
4,881
58,964
8,185
67,149
(7,904)
$ 59,245
Weighted
Average
Depreciation
Rate
2.1%
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The following table summarizes other long-term investments, including financial investments in life insurance policies
accounted for at fair value and equity investments in certain partnerships and joint ventures accounted for under the equity
or cost methods, at December 31:
Thousands
Life insurance investments
Note receivable
Investment in gas pipeline joint venture
Other
Total other investments
2008
$ 35,427
518
15,214
2,973
$ 54,132
2007
$ 46,294
518
7,258
$ 54,070
Life Insurance Investment. We have invested in key person life insurance contracts to provide an indirect funding
vehicle for certain long-term employee benefit plan liabilities. The amount in the above table is reported as cash surrender
value, net of policy loans.
Investment in Gas Pipeline Joint Venture. A wholly-owned subsidiary of Financial Corporation, KB Pipeline
Company, owns a 10 percent interest in an 18-mile interstate natural gas pipeline. Also, in 2007, we entered into an
agreement with TransCanada’s Gas Transmission Northwest (GTN) for the purpose of designing, permitting, constructing
and owning a pipeline that would connect GTN’s interstate transmission pipeline to our local gas distribution system to
serve markets in Oregon and the western United States. As of December 31, 2008, our investment balance in Palomar
was $14.2 million, primarily related to planning and permitting.
Variable Interest Entities. FASB Interpretation No. 46(R), “Consolidation of Variable Interest Entities,” provides
guidance for determining whether consolidation is required for entities known as variable interest entities over which
control is achieved through means other than voting rights or entities that do not have sufficient equity investment at risk to
permit financing its activities without additional financial support. We currently have a variable interest in Palomar, which is
accounted for as an equity investment and not consolidated as we are not the primary beneficiary. See Note 2.
10.
FAIR VALUE OF FINANCIAL INSTRUMENTS:
We use fair value measurements to record fair value adjustments to certain financial instruments and to determine fair value
disclosures. As of December 31, 2008, we recorded our derivatives at fair value according to SFAS No. 157. As we
elected not to implement SFAS No. 159, we did not measure our long-term debt at fair value (see Note 1).
In accordance with SFAS No. 157, we use the following fair value hierarchy for determining our derivative fair value
measurements:
•
•
Level 1: Valuation is based upon quoted prices for identical instruments traded in active markets;
Level 2: Valuation is based upon quoted prices for similar instruments in active markets, quoted prices for identical or
similar instruments in markets that are not active, and model-based valuation techniques for which all significant
assumptions are observable in the market; and
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•
Level 3: Valuation is generated from model-based techniques that use significant assumptions not observable in the
market. These unobservable assumptions reflect our own estimates of assumptions that market participants would use
in valuing the asset or liability.
When developing fair value measurements, it is our policy to use quoted market prices whenever available, or to maximize
the use of observable inputs and minimize the use of unobservable inputs when quoted market prices are not available.
Derivative contracts outstanding at December 31, 2008 were measured at fair value using models or other marketaccepted valuation methodologies derived from observable market data. These quoted prices are primarily industrystandard models that consider various inputs including: (a) quoted future prices for commodities; (b) forward currency
prices; (c) time value; (d) volatility factors; (e) current market and contractual prices for underlying instruments; (f) market
interest rates and yield curves; and (g) credit spreads, as well as other relevant economic measures.
In accordance with SFAS No. 157, we include nonperformance risk in calculating fair value adjustments. This includes a
credit risk adjustment based on the credit spreads of our counterparties when we are in an unrealized gain position, or on
our own credit spread when we are in an unrealized loss position. Our assessment of nonperformance 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, 2008.
The following table provides the fair value hierarchy of our derivative assets and liabilities as of December 31, 2008:
Thousands
Hierarchy
Level 1
Level 2
Level 3
11.
Fair Value Measurements
Description of Derivative Inputs
Quoted prices in active markets
Significant other observable inputs
Significant unobservable inputs
Fair Value, net
$
(153,643)
$(153,643)
USE OF FINANCIAL DERIVATIVES:
We have entered into swaps, options and combinations of options for the purchase of natural gas and for the forecasted
issuance of fixed-rate debt that qualify as derivative instruments under SFAS No. 133. We primarily use derivative
financial instruments to manage commodity prices related to our natural gas requirements and to manage interest rate risk
exposure related to our long-term debt issuances.
In the normal course of business, we enter into indexed-price physical forward natural gas commodity purchase (gas
supply) contracts to meet the requirements of core utility customers. We also enter into financial derivatives, up to
prescribed limits, to hedge price variability related to the physical contracts. Derivatives entered into prudently for future
gas years prior to our annual PGA filing receive SFAS No. 71 regulatory deferral treatment. Derivatives contracts entered
into for core utility customer requirements after the annual PGA rate has been set are subject to the PGA incentive sharing
mechanism, whereby 80 percent of the changes in fair value are deferred as regulatory assets or liabilities and the
remaining 20 percent is recorded to
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the income statement for contracts not qualifying for hedge accounting and to Other Comprehensive Income for contracts
qualifying for hedge accounting.
Certain natural gas purchases from Canadian suppliers are payable in Canadian dollars, including both commodity and
demand charges, which expose us to adverse changes in foreign currency rates. Foreign currency forward contracts are
used to hedge the fluctuation in foreign currency exchange rates for our commodity and commodity-related demand
charges paid in Canadian dollars. Foreign currency contracts for commodity costs are purchased on a month-to-month
basis because the Canadian cost is priced at the average noon-day exchange rate for each month. Foreign currency
contracts for demand costs have terms ranging up to 12 months. The gains and losses on the shorter-term currency
contracts for commodity costs are recognized immediately in cost of gas. The gains and losses on the currency contracts
for demand charges are not recognized in current income but are subject to a regulatory deferral tariff and, as such, are
recorded as a regulatory asset or liability. These forward contracts qualify for cash flow hedge accounting treatment under
SFAS No. 133. The mark-to-market adjustment at December 31, 2008 was an unrealized loss of $0.4 million. This
unrealized loss is subject to regulatory deferral and, as such, was recorded as a derivative liability, which is offset by
recording a corresponding amount to a regulatory asset account.
In 2007, we entered into a 10-year, $50 million fixed-price forward starting interest rate swap contract to hedge the
interest rate exposure related to the forecasted issuance of long-term debt. This interest rate swap is an effective cash flow
hedge under SFAS No. 133.
The unrealized mark-to-market value at December 31, 2008 for all derivative contracts outstanding was a total loss of
$153.6 million consisting of the following: a $141.3 million unrealized loss on natural gas commodity hedge and derivative
contracts, a $11.9 million unrealized loss on the interest rate swap contract and a $0.4 million unrealized loss on the
foreign exchange forward contracts.
Derivative hedge contracts are subject to a hedge effectiveness test to determine the financial statement treatment of each
specific derivative. As of December 31, 2008, all of our derivatives were effective economic hedges and either qualified
or were expected to qualify for regulatory deferral, or hedge accounting treatment. We use the hypothetical derivative
method under SFAS No. 133 to determine the hedge effectiveness of our interest rate swap which qualifies as a cash flow
hedge. We extended the effective date of our interest rate swap from December 1, 2008 to April 1, 2009 which resulted
in an ineffectiveness of $1.5 million. In accordance with SFAS No. 71, we have reclassified this amount from AOCI to
regulatory assets. The ineffectiveness for all other derivative contracts is determined using the dollar offset method under
SFAS No. 133. The effectiveness test applied to financial derivatives is dependent on the type of derivative and its use.
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At December 31, 2008 and 2007, the unrealized gains or losses from mark-to-market valuations of our derivative
instruments were primarily recorded as regulatory liabilities or regulatory assets because the realized gains or losses at
settlement are either included, or are expected to be included, in utility rates pursuant to regulatory deferral mechanisms.
The estimated fair values of unrealized gains and losses on derivative instruments outstanding, determined using a
discounted cash flow model for swaps and a Black-Scholes model for options, were as follows:
Fair Value Gains (Losses)
Dec. 31, 2008
Dec. 31, 2007
NonNonCurrent
Current
Current
Current
Thousands
Natural gas commodity-based derivative instruments:
Natural gas commodity hedge contracts
Interest rate hedge contract
Foreign currency forward purchase contracts
Total
$(131,698)
(445)
$(132,143)
$ (9,588)
(11,912)
$(21,500)
$(12,099)
173
$(11,926)
$ (2,104)
(1,330)
$ (3,434)
In 2008 and 2007, we realized net gains of $35.1 million and net losses of $42.0 million, respectively, from the settlement
of fixed-price natural gas financial swap contracts which were recorded as decreases and increases to the cost of gas,
respectively. Realized losses in 2007 were offset by lower gas purchase costs from the underlying hedged item, which
were floating rate physical supply contracts. The currency exchange rate in all foreign currency forward purchase
contracts is included in our cost of gas at settlement; therefore, no gain or loss was recorded from the settlement of those
contracts. There were no realized gains or losses on the interest rate swap during 2008.
As of December 31, 2008, all of our natural gas financial hedge contracts mature on or before October 2010. The
maturity date on our interest rate swap contract is in April 2019.
12.
COMMITMENTS AND CONTINGENCIES:
Lease Commitments
We lease land, buildings and equipment under agreements that expire in various years through 2095. Rental expense
under operating leases was $4.7 million, $4.6 million and $4.4 million for the years ended December 31, 2008, 2007 and
2006, respectively. The table below reflects the future minimum lease payments due under non-cancelable leases at
December 31, 2008. Such payments total $47.3 million for operating leases. The net present value of payments on capital
leases less imputed interest was $1.2 million. These commitments relate principally to the lease of our office headquarters,
underground gas storage facilities, vehicles and computer equipment.
Thousands
Operating leases
Capital leases
Minimum lease payments
2009
$ 4,129
599
$ 4,728
108
2010
$ 4,127
461
$ 4,588
2011
$ 4,080
163
$ 4,243
2012
$ 4,230
21
$ 4,251
2013
$ 4,268
$ 4,268
Later
years
$ 26,501
$ 26,501
Table of Contents
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, 2008:
Gas
Purchase
Agreements
$
229,804
89,079
34,835
21,277
21,277
17,731
414,003
7,698
$
406,305
Thousands
2009
2010
2011
2012
2013
2014 through 2028
Total
Less: Amount representing interest
Total at present value
Pipeline
Capacity
Purchase
Agreements
$
84,798
64,554
64,175
49,067
41,602
87,826
392,022
27,861
$
364,161
Pipeline
Capacity
Release
Agreements
$
4,128
3,440
7,568
56
$
7,512
Our total payments of fixed charges under capacity purchase agreements in 2008, 2007 and 2006 were $85.7 million,
$90.1 million and $69.2 million, respectively. Included in the amounts were reductions for capacity release sales of $5.0
million for 2008, $5.3 million for 2007 and $3.7 million for 2006. In addition, per-unit charges are required to be paid
based on the actual quantities shipped under the agreements. In certain take-or-pay purchase commitments, annual
deficiencies may be offset by prepayments subject to recovery over a longer term if future purchases exceed the minimum
annual requirements.
Environmental Matters
We own, or previously owned, properties that may require environmental remediation or action. We accrue all material
loss contingencies relating to these properties that we believe to be probable of assertion and reasonably estimable. We
continue to study the extent of our potential environmental liabilities, but due to the numerous uncertainties surrounding the
course of environmental remediation and the preliminary nature of several environmental site investigations, the range of
potential loss beyond the amounts currently accrued, and the probabilities thereof, cannot be reasonably estimated. We
regularly review our remediation liability for each site where we may be exposed to remediation responsibilities. The costs
of environmental remediation are difficult to estimate. A number of steps are involved in each environmental remediation
effort, including site investigations, remediation, operations and maintenance, monitoring and site closure. Each of these
steps may, over time, involve a number of alternative actions, each of which can change the course of the effort. In certain
cases, in addition to us, there are a number of other potentially responsible parties, each of which, in proceedings and
negotiations with other potentially responsible parties and regulators, may influence the course of the remediation effort.
The allocation of liabilities among the potentially responsible parties is often subject to dispute and can be highly uncertain.
The events giving
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rise to environmental liabilities often occurred many decades ago, which complicates the determination of allocating
liabilities among potentially responsible parties. Site investigations and remediation efforts often develop slowly over many
years. In addition, disputes may arise between potentially responsible parties and regulators as to the severity of particular
environmental matters and what remediation efforts are appropriate. These disputes could lead to adversarial
administrative proceedings or litigation, with uncertain outcomes.
To the extent reasonably estimable, we estimate the costs of environmental liabilities using current technology, enacted
laws and regulations, industry experience gained at similar sites and an assessment of the probable level of involvement
and financial condition of other potentially responsible parties. Unless there is a better estimate within this range of
probable cost, we record the liability at the lower end of this range. It is likely that changes in these estimates will occur
throughout the remediation process for each of these sites due to uncertainty concerning our responsibility, the complexity
of environmental laws and regulations and the selection of compliance alternatives. The status of each of the sites currently
under investigation is provided below.
Gasco site. We own property in Multnomah County, Oregon that is the site of a former gas manufacturing plant that was
closed in 1956 (the Gasco site). The Gasco site has been under investigation by us for environmental contamination under
the Oregon Department of Environmental Quality’s (ODEQ) Voluntary Clean-Up Program. In June 2003, we filed a
Feasibility Scoping Plan and an Ecological and Human Health Risk Assessment with the ODEQ, which outlined a range of
remedial alternatives for the most contaminated portion of the Gasco site. In May 2007, we completed a revised Upland
Remediation Investigation Report and submitted it to the ODEQ for review. In November 2007 we submitted a Focused
Feasiblity Study to DEQ for groundwater source control. We have a net liability accrued of $20.1 million at
December 31, 2008 for the Gasco site, which is estimated at the low end of the range of potential liability because no
amount within the range is considered to be more likely than another and the high end of the range cannot reasonably be
estimated.
Siltronic site. We previously owned property adjacent to the Gasco site that now is the location of a manufacturing plant
owned by Siltronic Corporation (the Siltronic site). We are currently implementing an investigation of manufactured gas
plant wastes on the uplands at this site for the DEQ. The net liability accrued at December 31, 2008 for the Siltronic site is
$1.0 million, which is at the low end of the range of potential liability because no amount within the range is considered to
be more likely than another and the high end of the range cannot reasonably be estimated.
Portland Harbor site. In 1998, the ODEQ and the U.S. Environmental Protection Agency (EPA) completed a study of
sediments in a 5.5-mile segment of the Willamette River (Portland Harbor) that includes the area adjacent to the Gasco
and Siltronic sites. The Portland Harbor was listed by the EPA as a Superfund site in 2000 and we were notified that we
are a potentially responsible party. We then joined with other potentially responsible parties, referred to as the Lower
Willamette Group, to fund environmental studies in the Portland Harbor. Subsequently, the EPA approved a
Programmatic Work Plan, Field Sampling Plan and Quality Assurance Project Plan for the Portland Harbor Remedial
Investigation/Feasibility Study (RI/FS), completion of which is currently expected in 2010. The EPA and the Lower
Willamette Group are conducting focused studies on approximately nine miles of the lower Willamette River, including the
5.5-mile segment previously studied by the EPA. In 2008, we received a
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revised estimate and updated our estimate for additional expenditures related to RI/FS development and environmental
remediation. In August 2008, we signed a cooperative agreement to participate in a phased natural resource damage
assessment, with the intent to identify what, if any, additional information is necessary to estimate further liabilities sufficient
to support an early restoration-based settlement of natural resource damage claims. As of December 31, 2008, we have a
net liability accrued of $13.2 million for this site, which is at the low end of the range of the potential liability because no
amount within the range is considered to be more likely than another and the high end of the range cannot reasonably be
estimated.
In April 2004, we entered into an Administrative Order on Consent providing for early action removal of a deposit of tar
in the river sediments adjacent to the Gasco site. We completed the removal of the tar deposit in the Portland Harbor in
October 2005, and on November 5, 2005 the EPA approved the completed project. The total cost of removal, including
technical work, oversight, consultant fees, legal fees and ongoing monitoring, was about $10.8 million. To date, we have
paid $10.1 million on work related to the removal of the tar deposit. As of December 31, 2008, we have a net liability
accrued of $0.7 million for our estimate of ongoing costs related to the tar deposit removal.
Central Service Center site. In 2006, we received notice from the ODEQ that our Central Service Center in southeast
Portland (the Central Service Center site) was assigned a high priority for further environmental investigation. Previously
there were three manufactured gas storage tanks on the premises. The ODEQ believes there could be site contamination
associated with releases of condensate from stored manufactured gas as a result of historic gas handling practices. In the
early 1990s, we excavated waste piles and much of the contaminated surface soils and removed accessible waste from
some of the abandoned piping. In early 2007, we received notice that this site was added to the ODEQ’s list of sites
where releases of hazardous substances have been confirmed and its list where additional investigation or cleanup is
necessary. We are currently performing an environmental investigation of the property with the ODEQ’s Independent
Cleanup Pathway. As of December 31, 2008, we have recorded an estimated liability of $0.5 million for investigation at
this site. The estimate is at the low end of the range of potential liability because no amount within the range is considered
to be more likely than another and the high end of the range cannot reasonably be estimated.
Front Street site. The Front Street site was the former location of a gas manufacturing plant we operated. Although it is
outside the geographic scope of the current Portland Harbor site sediment studies, the EPA directed the Lower
Willamette Group to collect a series of surface and subsurface sediment samples off the river bank adjacent to where that
facility was located. Based on the results of that sampling, the EPA notified the Lower Willamette Group that additional
sampling would be required. As the Front Street site is upstream from the Portland Harbor site, the EPA agreed that it
could be managed separately from the Portland Harbor site under ODEQ authority. As of December 31, 2008, we
accrued an estimated liability of $0.3 million for the study of the site, which will include investigation of sediments and
provide a report of historical upland activities. The estimate is at the low end of the range of potential liability because no
amount within the range is considered to be more likely than another and the high end of the range cannot reasonably be
estimated.
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Oregon Steel Mills site. See “Legal Proceedings,” below.
Accrued Liabilities Relating to Environmental Sites. The following table summarizes the accrued liabilities relating
to environmental sites at December 31, 2008 and 2007:
Current Liabilities
2008
2007
$
6,012
$
6,901
682
277
$
6,971
$
6,901
Thousands
Gasco
Siltronic
Portland Harbor
Central Service Center
Front Street
Other
Total
Non-Current Liabilities
2008
2007
$ 14,071
$ 14,342
332
1,540
13,642
14,821
526
529
294
2
80
165
$ 28,945
$ 31,399
Regulatory and Insurance Recovery for Environmental Costs. In May 2003, the OPUC approved our request to
defer unreimbursed environmental costs associated with certain named sites, including those described above. Beginning in
2006, the OPUC authorized us to accrue interest on deferred environmental cost balances, subject to an annual
demonstration that we have maximized our insurance recovery or made substantial progress in securing insurance
recovery for unrecovered environmental expenses. Through a series of extensions, this authorization has been extended
through January 25, 2009. We have requested another extension through January 2010, and that request is currently
pending.
On a cumulative basis, we have recognized a total of $70.9 million for environmental costs, including legal, investigation,
monitoring and remediation costs. Of this total, $35.0 million has been spent to date and $35.9 million is recorded as an
outstanding liability. At December 31, 2008, we had a regulatory asset of $66.1 million, which includes $30.1 million of
total paid expenditures to date, $30.0 million for additional environmental costs expected to be paid in the future and
accrued interest of $6.0 million. We believe the recovery of these deferred charges is probable through the regulatory
process. We intend to pursue recovery of an insurance receivable and environmental regulatory deferrals from insurance
carriers under our general liability insurance policies, and the regulatory asset will be reduced by the amount of any
corresponding insurance recoveries. We consider insurance recovery of most of our environmental costs probable based
on a combination of factors including: a review of the terms of our insurance policies; the financial condition of the
insurance companies providing coverage; a review of successful claims filed by other utilities with similar gas manufacturing
facilities; and Oregon law that allows an insured party to seek recovery of “all sums” from one insurance company. We
have initiated settlement discussions with a majority of our insurers but continue to anticipate that our overall insurance
recovery effort will extend over several years.
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As such we have classified our regulatory assets for environmental cost deferrals as non-current. The following table
summarizes the non-current regulatory assets relating to environmental sites at December 31, 2008 and 2007:
Thousands
Gasco
Siltronic
Portland Harbor
Central Service Center
Front Street
Other
Total
$
$
Non-Current Regulatory Assets
2008
2007
30,707
$
29,042
2,327
2,227
31,791
30,869
545
545
338
1
396
370
66,104
$
63,054
Legal Proceedings
We are subject to claims and litigation arising in the ordinary course of business. Although the final outcome of any of
these legal proceedings, including the matter described below, cannot be predicted with certainty, we do not expect that
the ultimate disposition of any of these matters will have a material adverse effect on our financial condition, results of
operations or cash flows.
Oregon Steel Mills site. In 2004, NW Natural was served with a third-party complaint by the Port of Portland (Port) in
a Multnomah County Circuit Court case, Oregon Steel Mills, Inc. v. The Port of Portland. The Port alleges that in the
1940s and 1950s petroleum wastes generated by our predecessor, Portland Gas & Coke Company, and 10 other thirdparty defendants were disposed of in a waste oil disposal facility operated by the United States or Shaver Transportation
Company on property then owned by the Port and now owned by Oregon Steel Mills. The complaint seeks contribution
for unspecified past remedial action costs incurred by the Port regarding the former waste oil disposal facility as well as a
declaratory judgment allocating liability for future remedial action costs. No date has been set for trial and discovery is
ongoing. We do not expect that the ultimate disposition of this matter will have a material adverse effect on our financial
condition, results of operations or cash flows.
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NORTHWEST NATURAL GAS COMPANY
QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
(1)
Thousands, except per share amounts
2008
Operating revenues
Net operating revenues
Net income (loss)
Basic earnings (loss) per share
Diluted earnings (loss) per share
March 31
Quarter ended
June 30
Sept. 30
$ 387,694
132,423
43,168
1.63
1.63
$ 191,254
62,572
3,297
0.12
0.12
$ 109,702
43,549
(10,120)
(0.38)
(0.38)
$ 349,205
117,671
33,180
1.25
1.25
$ 1,037,855
356,215
69,525
2.63(1)
2.61(1)
2007
Operating revenues
Net operating revenues
Net income (loss)
Basic earnings (loss) per share
Diluted earnings (loss) per share
$ 394,091
139,008
48,075
1.77
1.76
$ 183,249
64,118
2,617
0.10
0.10
$ 124,245
49,663
(5,908)
(0.22)
(0.22)
$ 331,608
116,253
29,713
1.12
1.11
$ 1,033,193
369,042
74,497
2.78(1)
2.76(1)
Dec. 31
Total
Quarterly earnings (loss) per share are based upon the average number of common shares outstanding during each
quarter. Because the average number of shares outstanding has changed in each quarter shown, the sum of quarterly
earnings (loss) per share may not equal earnings per share for the year. Variations in earnings between quarterly periods
are due primarily to the seasonal nature of our business.
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NORTHWEST NATURAL GAS COMPANY
SCHEDULE II – VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
COLUMN A
Thousands (year ended Dec. 31)
2008
Reserves deducted in balance
sheet from assets to which they apply:
Allowance for uncollectible accounts
2007
Reserves deducted in balance
sheet from assets to which they apply:
Allowance for uncollectible accounts
2006
Reserves deducted in balance
sheet from assets to which they apply:
Allowance for uncollectible accounts
COLUMN B
Balance at
beginning
of
period
COLUMN C
Additions
Charged to
Charged to
costs
other
and expenses
accounts
COLUMN D
Deductions
$
2,890
$
3,145
$
-
$
3,108
$
2,927
$
3,033
$
2,978
$
-
$
3,121
$
2,890
$
3,067
$
3,036
$
-
$
3,070
$
3,033
115
Net
Write-offs
COLUMN E
Balance
at end
of
period
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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 December 31, 2008, our disclosure
controls and procedures were effective to ensure that information required to be disclosed by us and included in our reports filed or
submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the
Securities and Exchange Commission rules and forms and that such information is accumulated and communicated to management,
including the Chief Executive Officer and Chief Financial Officer as appropriate to allow timely decisions regarding required
disclosure.
(b) Changes in Internal Control Over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is
defined in the Exchange Act Rule 13a-15(f).
There have been no changes in our internal control over financial reporting that occurred during the quarter ended December 31,
2008 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 9A.
Management’s Report on Internal Control Over Financial Reporting and the Report of Independent Registered Public Accounting
Firm appear under Item 8.
ITEM 9B. OTHER INFORMATION
None.
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PART III
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Information concerning our Board of Directors, its Committees and the Audit Committee financial expert contained in
NW Natural’s definitive Proxy Statement for the May 28, 2009 Annual Meeting of Shareholders is hereby incorporated by
reference. The information concerning “Section 16(a) Beneficial Ownership Reporting Compliance” and “Corporate Governance”
contained in our definitive Proxy Statement for the May 28, 2009 Annual Meeting of Shareholders is hereby incorporated by
reference.
Name
Age at
Dec. 31, 2008
Positions held during last five years
Mark S. Dodson
63
Chief Executive Officer (2007-2008); President and Chief Executive Officer (2003-2007).
Gregg S. Kantor
51
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).
David H. Anderson
47
Senior Vice President and Chief Financial Officer (2004- ); Senior Vice President and
Chief Financial Officer, TXU Gas Company (2004); Senior Vice President, Principal
Accounting Officer and Controller TXU Corp. (2003-2004).
Margaret D. Kirkpatrick
54
Vice President and General Counsel (2005- ); Partner, Stoel Rives LLP (1991- 2005).
Lea Anne Doolittle
53
Senior Vice President (2008- ); Vice President, Human Resources (2000-2007).
J. Keith White
55
Vice President, Business Development and Energy Supply (2007- ); Managing
Director, Gas Operations and Wholesale Services (2005-2006); Managing Director
and Chief Strategic Officer (2003-2005).
David R. Williams
55
Vice President, Utility Services (2007- ); Director, Acquire Customers (2006); Director,
Gas Operations (2005-2006); General Manager, Utility Operations (1999-2004).
Grant M. Yoshihara
53
Vice President, Utility Operations (2007- ); Managing Director, Utility Services (20052006); General Manager, Consumer Services (2003-2004).
C. Alex Miller
51
Vice President, Finance and Regulation (2009Regulatory Affairs (2002-2009).
Stephen P. Feltz
53
Treasurer and Controller (1999- ).
MardiLyn Saathoff
52
Chief Governance Officer and Corporate Secretary (2008- ); Chief Compliance Officer
and Assistant General Counsel, Tektronix, Inc. (2005-2008); General Counsel to
Oregon Governor Kulongoski and Business and Economic Development Advisor
(2003-2005).
); General Manager of Rates and
Each executive officer serves successive annual terms; present terms end on May 28, 2009. There are no family
relationships among our executive officers, directors or any person chosen to become one of our officers or directors.
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NW Natural has adopted a Code of Ethics applicable to all employees, including our chief executive officer, chief financial
officer and principal accounting officer, and a Financial Code of Ethics that applies to senior financial employees, both of which are
available on our website at www.nwnatural.com. We intend to disclose on our website at www.nwnatural.com any amendments
to or waivers of our Code of Ethics for executive officers.
ITEM 11. EXECUTIVE COMPENSATION
The information concerning “Executive Compensation” and “Report of the Organization and Executive Compensation
Committee on Executive Management Compensation” contained in our definitive Proxy Statement for the May 28, 2009 Annual
Meeting of Shareholders is hereby incorporated by reference. Information related to Executive Officers as of December 31, 2008
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, 2008 (see Note 4 to the Consolidated Financial Statements):
Plan Category
Equity compensation plans approved by security holders:
Long-Term Incentive Plan (LTIP) (Target Award)1
Restated Stock Option Plan
Employee Stock Purchase Plan
(a)
(b)
Number of securities
to be issued upon
exercise of
outstanding
options,
warrants and rights
Weighted-average
exercise price of
outstanding options,
warrants and rights
(c)
Number of securities
remaining available for
future issuance under
equity compensation
plans (excluding
securities reflected in
column (a))
n/a
38.62
43.25
247,898
922,400
188,414
6,300
72,767
n/a
n/a
n/a
n/a
47,617
n/a
613,213
n/a
n/a
n/a
n/a
1,358,712
75,000
396,410
15,119
Equity compensation plans not approved by security holders:
Executive Deferred Compensation Plan (EDCP)2
Directors Deferred Compensation Plan (DDCP)2
Deferred Compensation Plan for Directors and
Executives (DCP)3
Non-Employee Directors Stock Compensation Plan4
Total
$
$
The information captioned “Beneficial Ownership of Common Stock by Directors and Executive Officers” contained in
our definitive Proxy Statement for the May 28, 2009 Annual Meeting of Shareholders is incorporated herein by reference.
118
Table of Contents
1
2
3
4
Shares issued pursuant to the LTIP do not include an exercise price, but are payable when the award criteria are satisfied. If
the maximum awards were paid pursuant to the performance-based awards outstanding at December 31, 2008, the number
of shares shown in column (a) would increase by 71,834 shares and the number of shares shown in column (c) would
decrease by 71,834 shares.
Prior to January 1, 2005, deferred amounts were credited, at the participant’s election, to either a “cash account” or a “stock
account.” If deferred amounts were credited to stock accounts, such accounts were credited with a number of shares of NW
Natural common stock based on the purchase price of the common stock on the next purchase date under our Dividend
Reinvestment and Direct Stock Purchase Plan, and such accounts were credited with additional shares based on the deemed
reinvestment of dividends. Cash accounts are credited quarterly with interest at a rate equal to Moody’s Average Corporate
Bond Yield plus two percentage points, subject to a six percent minimum rate. At the election of the participant, deferred
balances in the stock accounts are payable after termination of Board service or employment in a lump sum, in installments
over a period not to exceed 10 years in the case of the DDCP, or 15 years in the case of the EDCP, or in a combination of
lump sum and installments. We have contributed common stock to the trustee of the Umbrella Trusts such that the Umbrella
Trusts hold approximately the number of shares of common stock equal to the number of shares credited to all participants’
stock accounts.
Effective January 1, 2005, the EDCP and DDCP were replaced by the Deferred Compensation Plan for Directors and
Executives (DCP). The DCP continues the basic provisions of the EDCP and DDCP under which deferred amounts are
credited to either a “cash account” or a “stock account.” Stock accounts represent a right to receive shares of NW Natural
common stock on a deferred basis, and such accounts are credited with additional shares based on the deemed reinvestment
of dividends. Effective January 1, 2007, cash accounts are credited quarterly with interest at a rate equal to Moody’s Average
Corporate Bond Yield. Our obligation to pay deferred compensation in accordance with the terms of the DCP will generally
become due on retirement, death, or other termination of service, and will be paid in a lump sum or in installments of five or 10
years as elected by the participant in accordance with the terms of the DCP. We have contributed common stock to the
trustee of the Supplemental Trust such that this trust holds approximately the number of common shares equal to the number
of shares credited to all participates’ stock accounts. The right of each participant in the DCP is that of a general, unsecured
creditor of the Company.
The material features of this plan are more particularly described in Note 4 to the Consolidated Financial Statements included
in this report.
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, 2009 Annual Meeting of Shareholders is hereby incorporated by reference.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
The information captioned “2008 and 2007 Audit Firm Fees” in the Company’s definitive Proxy Statement for the
May 28, 2009 Annual Meeting of Shareholders is hereby incorporated by reference.
119
Table of Contents
PART IV
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
(a)
The following documents are filed as part of this report:
1.
A list of all Financial Statements and Supplemental Schedules is incorporated by reference to Item 8.
2.
List of Exhibits filed:
Reference is made to the Exhibit Index commencing on page 123.
120
Table of Contents
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
Date: February 27, 2009
By:
/s/ Gregg S. Kantor
Gregg S. Kantor,
President and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following
persons on behalf of the registrant and in the capacities and on the date indicated.
SIGNATURE
/s/ Gregg S. Kantor
Gregg S. Kantor
President and Chief Executive Officer
TITLE
Principal Executive Officer and Director
DATE
February 27, 2009
/s/ David H. Anderson
David H. Anderson
Senior Vice President
and Chief Financial Officer
Principal Financial Officer
February 27, 2009
/s/ Stephen P. Feltz
Stephen P. Feltz
Treasurer and Controller
Principal Accounting Officer
February 27, 2009
/s/ Timothy P. Boyle
Timothy P. Boyle
Director
)
)
)
/s/ Martha L. Byorum
Martha L. Byorum
Director
)
)
)
/s/ John D. Carter
John D. Carter
Director
)
)
)
/s/ Mark S. Dodson
Mark S. Dodson
Director
)
)
)
/s/ C. Scott Gibson
C. Scott Gibson
Director
)
)
)
/s/ Tod R. Hamachek
Tod R. Hamachek
Director
)
)
)
/s/ Jane L. Peverett
Jane L. Peverett
Director
)
)
)
/s/ George J. Puentes
George J. Puentes
Director
)
)
)
/s/ Kenneth Thrasher
Kenneth Thrasher
Director
)
)
)
/s/ Russell F. Tromley
Russell F. Tromley
Director
)
)
February 27, 2009
121
Table of Contents
EXHIBIT INDEX
To
Annual Report on Form 10-K
For Fiscal Year Ended
December 31, 2008
Exhibit Number
Document
*3a.
Restated Articles of Incorporation, as filed and effective May 31, 2006 and amended
June 3, 2008 (incorporated herein by reference to Exhibit 3a. to Form 10-K for 2006,
File No. 1-15973).
*3b.
Bylaws as amended May 24, 2007 (incorporated herein by reference to Exhibit 3.1 to
Form 8-K dated May 29, 2007, File No. 1-15973).
*4a.
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).
*4d.
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).
*4e.
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).
*4f.
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).
*4f.(1)
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).
122
Table of Contents
*4i.
Form of Credit Agreement between Northwest Natural Gas Company and the banks that are
party thereto, with JPMorgan Chase Bank, N.A., as administrative agent and Bank of
America, N.A., as syndication agent, dated as of May 31, 2007, including Form of Note
(incorporated herein by reference to Exhibit 10.1 to Form 8-K dated June 1, 2007,
File No. 1-15973).
4i.(1)
Form of Letter Agreement, between each of JPMorgan Chase Bank, N.A., Bank of America,
N.A., U.S. Bank National Association, UBS Loan Finance LLC, Wells Fargo Bank, N.A.,
Merrill Lynch Bank USA, dated as of April 29, 2008, extending the Credit Agreement
between Northwest Natural Gas Company and each financial institutions with JPMorgan
Chase Bank, N.A., as Administrative Agent.
*4k.
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).
*4m.
Distribution Agreement, dated September 28, 2004, as amended and restated on December 7,
2006, among the Company, Merrill Lynch, Pierce Fenner & Smith Incorporated, UBS
Securities LLC, J.P. Morgan Securities, Inc. and Piper Jaffray & Co. (Incorporated herein by
reference to Exhibit 4j. to Form 10-K for 2006, File No. 1-5973).
*4l.
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).
*10j.(1)
Replacement Firm Transportation Agreement, dated July 31, 1991, between the Company and
Northwest Pipeline GP (incorporated herein by reference to Exhibit 10j.(2) to Form 10-K for
1992, File No. 0-994).
*10j.(2)
Firm Transportation Service Agreement, dated November 10, 1993, between the Company
and Pacific Gas Transmission Company (incorporated herein by reference to Exhibit 10j.(2) to
Form 10-K for 1993, File No. 0-994).
*10j.(3)
Service Agreement, dated June 17, 1993, between Northwest Pipeline GP and the Company
(incorporated herein by reference to Exhibit 10j.(3) to Form 10-K for 1994, File No. 0-994).
*10j.(5)
Firm Transportation Service Agreement, dated June 22, 1994, between Pacific Gas
Transmission Company and the Company (incorporated herein by reference to Exhibit 10j.(5)
to Form 10-K for 1995, File No. 0-994).
*10j.(6)
Firm Service Agreement between the Company and Westcoast Energy Inc., dated as of April
1, 2003 (incorporated herein by reference to Exhibit 10 to Form 10-Q for quarter ended
March 31, 2003, File No. 0-994).
*10j.(7)
Service Agreement Amendment, dated February 12, 2008, between the Company and
Northwest Pipeline GP (incorporated herein by reference to Exhibit 10j.(7) to Form 10-K for
2007, File No. 1-15973).
123
Table of Contents
*10j.(8)
Service Agreement, dated February 8, 2008, between the Company and Northwest Pipeline GP
(incorporated herein by reference to Exhibit 10j.(8) to Form 10-K for 2007, File No. 1-15973).
*10j.(9)
Agreement between the Company and March Point Cogeneration Company, dated February 8,
2008 (incorporated herein by reference to Exhibit 10j.(9) to Form 10-K for 2007, File No. 115973).
10j.(10)
Firm Transportation Service Agreement, dated October 22, 1993, between the Company and
Pacific Gas Transmission Company.
10j.(11)
Service Agreement (100310), dated January 21, 2008, between the Company and Northwest
Pipeline GP.
10j.(12)
Service Agreement, dated January 21, 2008, between the Company and Northwest Pipeline GP.
10j.(13)
Service Agreement (Gas Storage Service), dated January 12, 1994, between the Company and
Northwest Pipeline Corporation.
10j.(14)
Service Agreement (100309), dated January 21, 2008, between the Company and Northwest
Pipeline GP.
10j.(15)
Service Agreement (100308), dated January 12, 1994, between the Company and Northwest
Pipeline GP.
10j.(16)
Service Agreement, dated January 20, 1995, between the Company and NOVA Gas
Transmission Ltd.
10j.(17)
Service Agreement, dated November 1, 2004, between the Company and TransCanada
PipeLines Limited.
10j.(18)
Service Agreement, dated October 24, 2008, between Foothills Pipe Lines Ltd. and the
Company.
10j.(19)
Amendment and Restatement of Firm Transportation Service Agreement, dated November 1,
2004, between Terasen Gas Inc. and the Company.
12
Statement re computation of ratios of earnings to fixed charges.
23
Consent of PricewaterhouseCoopers LLP.
31.1
Certification of Principal Executive Officer Pursuant to Rule 13a-14(a)/15-d-14(a), Section 302
of the Sarbanes-Oxley Act of 2002.
31.2
Certification of Principal Financial Officer Pursuant to Rule 13a-14(a)/15-d-14(a), Section 302
of the Sarbanes-Oxley Act of 2002.
32.1
Certification of Principal Executive Officer and Principal Financial Officer Pursuant to Section
906 of the Sarbanes-Oxley Act of 2002.
Executive Compensation Plans and Arrangements:
*10b.
Executive Supplemental Retirement Income Plan (2007 Restatement) (incorporated herein by
reference to Exhibit 10b to Form 10-K for 2007, File No. 1-15973).
*10b.(1)
Supplemental Executive Retirement Plan, effective September 1, 2004 restated December 20,
2007 (incorporated herein by reference to Exhibit 10b.(1) to Form 10-K for 2007, File No. 115973).
124
Table of Contents
*10b.(2)
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).
*10b.(3)
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 8K dated December 16, 2005,
File No. 1-15973).
*10b.(4)
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 8K dated December 16, 2005,
File No. 1-15973).
*10c.
Restated Stock Option Plan, as amended effective December 14, 2006 (incorporated herein by
reference to Exhibit 10c. to From 10-K for 2006, File No. 1-15973).
*10c.(1)
Form of Restated Stock Option Plan Agreement (incorporated herein by reference to Exhibit
10.3 to Form 10-Q dated November 3, 2005,
File No. 1-15973).
10e.
Executive Deferred Compensation Plan, effective as of January 1, 1987, restated as of February
26, 2009.
10f.
Directors Deferred Compensation Plan, effective June 1, 1981, restated as of February 26,
2009.
*10f.(1)
Deferred Compensation Plan for Directors and Executives effective January 1, 2005, restated
February 28, 2008 (incorporated herein by reference to Exhibit 10f.(1) to Form 10-K for 2007,
File No. 1-15973).
*10g.
Form of Indemnity Agreement as entered into between the Company and each director and
executive officer (incorporated herein by reference to Exhibit 10g. to Form 10-K for 1988, File
No. 0-994).
*10i.
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).
*10k.
Executive Annual Incentive Plan, effective January 1, 2003
(incorporated herein by reference to Exhibit 10 k. to Form 10-K for 2002, File No. 0-994).
10o.
Form of Change in Control Severance Agreement between the Company and each executive
officer.
*10o.-1
Severance agreement dated December 19, 2008 between the Company and Gregg S. Kantor
(incorporated herein by reference to Exhibit 10.1 to Form 8-K dated December 23, 2008, File
No. 1-15973).
*10p.-3
Employment Agreement dated December 20, 2002, between the Company and an executive
officer (incorporated herein by reference to Exhibit 10p.-3 to Form 10-K for 2002, File No. 0994).
125
Table of Contents
*10p.-4
Amendment dated December 14, 2006 to employment agreement dated December 20, 2002
between the Company and Mark S. Dodson (incorporated herein by reference to Exhibit 10.8 to
Form 8-K dated December 19, 2006, File No. 1-15973).
*10v.
Northwest Natural Gas Company Long-Term Incentive Plan, as amended and restated effective
July 26, 2001 (incorporated herein by reference to Exhibit 10(c) to Form 10-Q for the quarter
ended June 30, 2001,
File No. 0-994).
*10w.
Form of Long-Term Incentive Award Agreement under the Long-Term Incentive Plan
(incorporated herein by reference to Exhibit 10.8 to Form 8-K dated December 16, 2005, File
No. 1-15973).
*10w.(1)
Form of Long-Term Incentive Award Agreement under the Long-Term Incentive Plan
(incorporated herein by reference to Exhibit 10.1 to Form 8-K dated February 21, 2007, File
No. 1-15973).
*10w.(2)
Form of Long-Term Incentive Award Agreement under the Long-Term Incentive Plan
(incorporated herein by reference to Exhibit 10w.(2) to Form 10-K for 2007, File No. 115973).
*10x.
Form of Restricted Stock Bonus Agreement under the Long-Term Incentive Plan (incorporated
herein by reference to Exhibit 10.9 to Form 8-K dated December 16, 2005, File No. 1-15973).
*10x.(1)
Restricted Stock Bonus Agreement with an executive officer dated July 26, 2006 (incorporated
by reference to Exhibit 10.1 to Form 8-K dated July 28, 2006, File No. 1-15973).
*10aa.
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).
*10bb.
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).
* Incorporated herein by reference as indicated
126
(Back To Top)
Section 2: EX-4.I(1) (FORM OF LETTER OF AGREEMENT)
Exhibit 4i.(1)
JPMorgan Chase Bank, N.A., as
Administrative Agent under the Credit
Agreement referred to below
Attention: Joyce King and Helen Davis
Ladies/Gentlemen:
Please refer to the letter dated April 29, 2008 from Northwest Natural Gas Company (the “Company”) requesting an extension of the scheduled
Maturity Date under and as defined in the Credit Agreement dated as of May 31, 2007 among the Company, various financial institutions and
JPMorgan Chase Bank, N.A., as Administrative Agent (the “Credit Agreement”). Subject to satisfaction of the conditions set forth in Section 2.14(a)
and (c)-(g) of the Credit Agreement, the undersigned consents to the extension of the scheduled Maturity Date from May 31, 2012 to May 31, 2013.
This agreement may be executed in any number of counterparts, each of which shall be deemed to bean original instrument and all of which together
shall constitute a single agreement.
[Print or type full legal name of Lender]
By:
Name:
Title:
Date:
Acknowledged and Agreed to by:
Northwest Natural Gas Company
By:
Name:
Title:
Date:
(Back To Top)
Section 3: EX-10.E (EXECUTIVE DEFERRED COMPENSATION PLAN,
EFFECTIVE AS OF JANUARY 1, 1987 RESTATED)
Exhibit 10.e
NORTHWEST NATURAL GAS COMPANY
EXECUTIVE DEFERRED COMPENSATION PLAN
2009 RESTATEMENT
Effective January 1, 1987
Restated as of February 26, 2009
TABLE OF CONTENTS
PAGE
ARTICLE I
1.1
1.2
ARTICLE II
2.1
2.2
2.3
2.4
2.5
2.6
2.7
2.8
2.9
2.10
2.11
2.12
2.13
2.14
2.15
2.16
2.17
2.18
2.19
2.20
2.21
2.22
2.23
2.24
2.25
2.26
2.27
2.28
2.29
2.30
ARTICLE III
3.1
3.2
PURPOSE
1
Restatement
Purpose
1
1
DEFINITIONS
1
Account
Acquiror Stock
Base Annual Salary
Beneficiary
Board
Bonus
Cash Compensation
Change in Control
Committee
Common Stock
Compensation
Corporate Transaction
Corporation
Deferral Commitment
Deferral Deadline
Deferred Cash Compensation
Deferred Compensation Account Benefit
Determination Date
Disability
Executive
Financial Hardship
Interest
LTIP Compensation
Matching Contribution
Participation Agreement
Plan Benefits
Retirement
Retirement Plan
Supplemental Retirement Benefit
Trust
1
1
1
1
2
2
2
2
2
2
2
3
3
3
3
3
3
4
4
4
4
4
4
5
5
5
5
5
5
5
DEFERRAL COMMITMENTS
5
Participation
Deferral Election
5
5
i
TABLE OF CONTENTS
(Continued)
PAGE
ARTICLE IV
4.1
4.2
4.3
4.4
4.5
4.6
ARTICLE V
5.1
5.2
5.3
5.4
5.5
5.6
5.7
5.8
5.9
5.10
ARTICLE VI
6.1
6.2
6.3
6.4
ARTICLE VII
7.1
7.2
7.3
7.4
ARTICLE VIII
8.1
8.2
8.3
8.4
DEFERRED COMPENSATION ACCOUNTS
6
Accounts
Matching Contribution
Stock Account
Cash Account
Effect of Corporate Transaction on Stock Accounts
Statement of Account
6
6
7
7
7
8
PLAN BENEFITS
8
Plan Benefit
Commencement of Payments
Lump Sum or Installment Payments
Form of Benefit Payment
Hardship Distributions
Death Benefit
Supplemental Retirement Benefit
Withholding; Payroll Taxes
Payment to Guardian
Accelerated Distribution
8
8
9
9
9
9
10
11
11
11
BENEFICIARY DESIGNATION
11
Beneficiary Designation
Amendments
No Beneficiary Designation
Effect of Payment
11
11
11
12
ADMINISTRATION
12
Committee; Duties
Agents
Binding Effect of Decisions
Indemnity of Committee
12
12
12
12
CLAIMS PROCEDURE
12
Claim
Denial of Claim
Review of Claim
Final Decision
12
12
13
13
ii
TABLE OF CONTENTS
(Continued)
PAGE
ARTICLE IX
9.1
9.2
ARTICLE X
10.1
10.2
10.3
10.4
10.5
10.6
10.7
10.8
10.9
10.10
AMENDMENT AND TERMINATION OF THE PLAN
13
Amendment
Corporation’s Right to Terminate
13
13
MISCELLANEOUS
14
Unfunded Plan
Unsecured General Creditor
Trust Fund
Nonassignability
Not a Contract of Employment
Protective Provision
Governing Law
Validity
Notice
Successors
14
14
15
15
15
15
15
15
15
15
iii
NORTHWEST NATURAL GAS COMPANY
EXECUTIVE DEFERRED COMPENSATION PLAN
Effective as of January 1, 1987
Restated as of February 26, 2009
ARTICLE I
PURPOSE
1.1 Restatement. Northwest Natural Gas Company adopted an Executive Deferred Compensation Plan (the “Plan”) effective January 1, 1987,
which was previously restated effective as of January 1, 2001, January 1, 2003, December 15, 2005, January 1, 2007 and February 28, 2008. The Plan
was partially terminated in accordance with Paragraph 9(b)(i) effective December 31, 2004, so deferrals of compensation are no longer being made
under the Plan. The Plan is now amended and restated by this 2009 Restatement, effective as of February 26, 2009.
1.2 Purpose. The purpose of this Executive Deferred Compensation Plan is to provide an unfunded deferred compensation plan for a select
group of top management personnel.
ARTICLE II
DEFINITIONS
For purposes of this Plan, the following words and phrases shall have the meanings indicated, unless the context clearly indicates otherwise:
2.1 Account. “Account” means the record or records maintained by the Corporation for each Executive in accordance with Article IV with
respect to any deferral of Compensation pursuant to this Plan. An Account shall be either a “Stock Account” as described in Section 4.3 or a “Cash
Account” as described in Section 4.4.
2.2 Acquiror Stock. “Acquiror Stock” is defined in Section 4.5.
2.3 Base Annual Salary. “Base Annual Salary” means the annual compensation payable to an Executive, excluding bonuses, commissions,
LTIP Compensation and other noncash compensation.
2.4 Beneficiary. “Beneficiary” means the person, persons or entity designated under Article VI to receive any Plan Benefits payable after an
Executive’s death.
PAGE 1 – EXECUTIVE DEFERRED COMPENSATION PLAN
2.5 Board. “Board” means the Board of Directors of Northwest Natural Gas Company or any successor thereto.
2.6 Bonus. “Bonus” means the compensation derived under the Corporation’s Executive Annual Incentive Plan or other similar incentive plan
and payable in any year in a lump sum to an Executive.
2.7 Cash Compensation. “Cash Compensation” means the total Base Annual Salary and Bonus remuneration payable by the Corporation to
the Executive for services.
2.8 Change in Control. “Change in Control” means the occurrence of any of the following events:
(a) The consummation of:
(i) any consolidation, merger or plan of share exchange involving the Corporation (a “Merger”) as a result of which the holders of
outstanding securities of the Corporation ordinarily having the right to vote for the election of directors (“Voting Securities”)
immediately prior to the Merger do not continue to hold at least 50% of the combined voting power of the outstanding Voting Securities
of the surviving corporation or a parent corporation of the surviving corporation immediately after the Merger, disregarding any Voting
Securities issued to or retained by such holders in respect of securities of any other party to the Merger; or
(ii) any sale, lease, exchange or other transfer (in one transaction or a series of related transactions) of all, or substantially all, the
assets of the Corporation;
(b) At any time during a period of two consecutive years, individuals who at the beginning of such period constituted the board of
directors of the Corporation (“Incumbent Directors”) shall cease for any reason to constitute at least a majority thereof; provided, however,
that the term “Incumbent Director” shall also include each new director elected during such two-year period whose nomination or election was
approved by two-thirds of the Incumbent Directors then in office; or
(c) Any person (as such term is used in Section 14(d) of the Securities Exchange Act of 1934, other than the Corporation or any
employee benefit plan sponsored by the Corporation) shall, as a result of a tender or exchange offer, open market purchases or privately
negotiated purchases from anyone other than the Corporation, have become the beneficial owner (within the meaning of Rule 13d-3 under the
Securities Exchange Act of 1934), directly or indirectly, of Voting Securities representing twenty percent (20%) or more of the combined voting
power of the then outstanding Voting Securities.
2.9 Committee. “Committee” means the Organization and Executive Compensation Committee, or such other Committee as may be designated
by the Board.
2.10 Common Stock. “Common Stock” means common stock of the Corporation.
2.11 Compensation. “Compensation” means Cash Compensation and LTIP Compensation.
PAGE 2 – EXECUTIVE DEFERRED COMPENSATION PLAN
2.12 Corporate Transaction. “Corporate Transaction” means any of the following:
(a) any consolidation, merger or plan of share exchange involving the Corporation pursuant to which shares of Common Stock would be
converted into cash, securities or other property; or
(b) any sale, lease, exchange or other transfer (in one transaction or a series of related transactions) of all, or substantially all, the assets
of the Corporation.
2.13 Corporation. “Corporation” means Northwest Natural Gas Company, an Oregon corporation, or any successor thereto, and any
corporations or other entities affiliated with or subsidiary to it that may be selected by the Board from time to time and which take action to adopt
and implement this Plan.
2.14 Deferral Commitment. “Deferral Commitment” means a Deferral Commitment made by an Executive pursuant to Article III and for which a
Participation Agreement has been submitted by the Executive to the Committee.
2.15 Deferral Deadline. “Deferral Deadline” means, for any Compensation payable to an Executive, the last day on which the Executive can
submit a Participation Agreement to make a Deferral Commitment with respect to such Compensation. The Deferral Deadlines for various forms of
Compensation shall be as follows:
(a) For Base Annual Salary payable in any calendar year, the Deferral Deadline shall be the last day of the previous calendar year;
provided, however, that for a person who becomes an eligible Executive during a year, the Deferral Deadline for Base Annual Salary payable
for the remainder of the year shall be 30 days after the person becomes an Executive and the Deferral Commitment shall only apply to Base
Annual Salary payable after the Participation Agreement is submitted.
(b) For Bonus payable in any calendar year, including Bonus payable with respect to the Executive’s or the Corporation’s performance
in the previous calendar year, the Deferral Deadline shall be the last day of the previous calendar year.
(c) For LTIP Compensation payable at any time, the Deferral Deadline shall be the date one year prior to the vesting date for time-based
awards and the date one year prior to the last day of the award period for performance-based awards; provided, however, that the Deferral
Deadline for any LTIP Compensation that becomes payable in any calendar year on an accelerated basis as a result of a Change in Control
shall be the last day of the previous calendar year.
2.16 Deferred Cash Compensation. “Deferred Cash Compensation” means the amount of Cash Compensation that the Executive elects to defer
pursuant to a Deferral Commitment.
2.17 Deferred Compensation Account Benefit. “Deferred Compensation Account Benefit” means the benefit payable to an Executive as
calculated pursuant to Article IV and payable under Sections 5.1 through 5.6.
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2.18 Determination Date. “Determination Date” means the last day of each calendar quarter.
2.19 Disability. “Disability” means a physical or mental condition that, in the opinion of the Committee, prevents the Executive from
satisfactorily performing the Executive’s usual duties for the Corporation. The Committee’s decision as to Disability will be based upon medical
reports and/or other evidence satisfactory to the Committee.
2.20 Executive. “Executive” means one of a select group of management or highly compensated employees of the Corporation, which shall
consist of all executive officers of the Corporation and any other employee of the Corporation designated in writing by the Chief Executive Officer of
the Corporation for participation in the benefits of the Plan.
2.21 Financial Hardship. “Financial Hardship” means a severe financial hardship to the Executive resulting from a sudden and unexpected
illness or accident of the Executive or of a dependent of the Executive, loss of the Executive’s property due to casualty, or other similar extraordinary
and unforeseeable circumstances arising as a result of events beyond the control of the Executive. Financial Hardship shall be determined by the
Committee on the basis of information supplied by the Executive in accordance with uniform guidelines promulgated from time to time by the
Committee.
2.22 Interest. “Interest” is credited to Cash Accounts under the Plan and means the quarterly equivalent of an annual yield that is two
percentage points (2%) higher than the annual yield on Moody’s Average Corporate Bond Yield for the preceding quarter, as published by
Moody’s Investors Service, Inc. (or any successor thereto), or, if such index is no longer published, a substantially similar index selected by the
Board. At no time shall such Interest rate be less than six percent (6%) annually.
Notwithstanding the foregoing provisions of this Section 2.22, effective as of January 1, 2017, the Interest rate shall equal the rate of interest
for interest credited to cash accounts under the Corporation’s Deferred Compensation Plan for Directors and Executives, as such plan may be
amended from time to time (the “DCPDE”), regardless of whether or not such rate of interest shall be more or less than six percent (6%) annually;
provided, however, that if at any time on or after January 1, 2017 there is no interest credited to cash accounts under the DCPDE because the
DCPDE shall have ceased to operate or for any other reason, then, at such time on or after January 1, 2017, the Interest rate shall equal the quarterly
equivalent of an annual yield that is equal to the annual yield on Moody’s Average Corporate Bond Yield for the preceding quarter, as published by
Moody’s Investors Service, Inc. (or any successor thereto), or, if such index is no longer published, a substantially similar index selected by the
Board, regardless of whether or not such Interest rate shall be more or less than six percent (6%) annually. Any change in the Interest rate that
occurs on January 1, 2017 or thereafter pursuant to the provisions of this paragraph shall not constitute a “change in the definition of Interest”
within the meaning of Section 9.1(b) below.
2.23 LTIP Compensation. “LTIP Compensation” means compensation paid to an Executive pursuant to an award under the Corporation’s
Long Term Incentive Plan. LTIP
PAGE 4 – EXECUTIVE DEFERRED COMPENSATION PLAN
Compensation may be payable to the Executive either in Common Stock (“Stock LTIP Compensation”) or in cash (“Cash LTIP Compensation”).
2.24 Matching Contribution. “Matching Contribution” means the contribution made by the Corporation and credited to the Executive’s
Account under Section 4.2.
2.25 Participation Agreement. “Participation Agreement” means the agreement submitted by an Executive to the Committee no later than the
applicable Deferral Deadline with respect to one or more Deferral Commitments.
2.26 Plan Benefits. “Plan Benefits” mean the Deferred Compensation Account Benefit and the Supplemental Retirement Benefit.
2.27 Retirement. “Retirement” means either early retirement, normal retirement, or disability retirement under the Retirement Plan.
2.28 Retirement Plan. “Retirement Plan” means the Corporation’s Retirement Plan for Non-Bargaining Unit Employees.
2.29 Supplemental Retirement Benefit. “Supplemental Retirement Benefit” means the benefit payable to an Executive under Section 5.7.
2.30 Trust. “Trust” means the Northwest Natural Gas Company Umbrella Trust™ For Executives established by the Corporation in connection
with this Plan.
ARTICLE III
DEFERRAL COMMITMENTS
3.1 Participation. An eligible Executive may elect to participate in the Plan by submitting a Participation Agreement to the Committee no later
than the applicable Deferral Deadline. An election to defer Compensation by the Executive shall continue from year to year and shall be irrevocable
with respect to Compensation once the Deferral Deadline for that Compensation has passed, but may be modified or terminated by written notice
from the Executive at any time on or prior to the Deferral Deadline for that Compensation.
3.2 Deferral Election.
(a) Election to Defer Cash Compensation. An Executive may, no later than the applicable Deferral Deadline, elect to defer receipt of a
certain whole percentage, up to fifty percent (50%), of the Base Annual Salary and a certain whole percentage, up to one hundred percent
(100%), of any Bonus payable to the Executive as an employee of the Corporation.
(b) Election to Defer LTIP Compensation. An Executive may, no later than the applicable Deferral Deadline, elect to defer receipt of a
certain whole percentage, up to one hundred percent (100%), of any Stock LTIP Compensation and a certain whole percentage, up to one
hundred percent (100%), of any Cash LTIP Compensation that becomes payable to the Executive.
PAGE 5 – EXECUTIVE DEFERRED COMPENSATION PLAN
(c) FICA Withholding. Under current law, all Compensation and Matching Contributions credited to an Executive’s Accounts will be
treated as wages subject to FICA tax, and the Corporation will be required to withhold FICA tax from the Executive. The amount required to be
withheld for FICA tax with respect to any amount of deferred Compensation or related Matching Contribution shall be withheld from the nondeferred portion, if any, of the same Compensation; provided, however, that if the non-deferred portion of the Compensation is insufficient to
cover the full required withholding, the Corporation shall withhold the remaining amount from other non-deferred Compensation payable to
the Executive unless the Executive otherwise pays such remaining amount to the Corporation.
(d) Financial Hardship. Termination of the Executive’s election to defer may, solely in the Committee’s discretion, become applicable as
soon as practicable after the Committee’s determination that the Executive has incurred Financial Hardship, as evidenced by the Executive to
the Committee.
ARTICLE IV
DEFERRED COMPENSATION ACCOUNTS
4.1 Accounts. The Corporation shall establish on its books one or two separate Accounts for each Executive who elects to defer
Compensation under the Plan: a Cash Account and/or a Stock Account. Compensation deferred by an Executive shall be credited to the Stock
Account or the Cash Account as elected by the Executive at the time the Executive elects to defer Compensation. Such election may be divided
between the two Accounts in increments of twenty-five percent (25%) of the deferred Compensation covered by the election. An Executive may
change the allocation of new deferrals of Compensation between the Stock Account and the Cash Account, but such change shall apply to new
deferrals only if it is submitted on or prior to the Deferral Deadline for such new deferrals. Once Compensation has been credited to the Stock
Account or the Cash Account, no transfers between the Stock Account and the Cash Account shall be permitted except as otherwise provided in
Section 4.5(d). The credit for deferred Compensation shall be entered on the Corporation’s books of account at the time that Compensation not
deferred is paid or payable to the Executive.
4.2 Matching Contribution. The Corporation shall credit a Matching Contribution to an Executive’s Account based on the amount of Deferred
Cash Compensation elected by the Executive; provided, however, that no Matching Contributions shall be made to the Account of any Executive
who is not eligible to participate in the Corporation’s Retirement K Savings Plan until such time of eligibility. The amount of the Matching
Contribution shall be equal to the excess of (a) the lesser of (i) sixty percent (60%) of the Executive’s Deferred Cash Compensation during the
calendar year, or (ii) three and six-tenths percent (3.6%) of the Executive’s Cash Compensation during such calendar year, over (b) the amount, if
any, the Corporation has contributed for such calendar year as a matching contribution for the Executive to the Retirement K Savings Plan.
Matching Contributions shall be credited to the Executive’s Account on the last day of the calendar year in which the Matching Contribution was
earned, and shall be allocated between the Executive’s Cash Account and Stock Account in the same ratio as Deferred Cash Compensation is
allocated for the year.
PAGE 6 – EXECUTIVE DEFERRED COMPENSATION PLAN
4.3 Stock Account. An Executive’s Stock Account shall be denominated in shares of Common Stock, including fractional shares. With respect
to Stock LTIP Compensation deferred to an Executive’s Stock Account, the number of deferred shares shall be credited to the Stock Account. With
respect to each amount of Cash Compensation, Cash LTIP Compensation or Matching Contribution deferred to an Executive’s Stock Account, the
amount of cash deferred shall be divided by the closing market price of the Common Stock reported for the last trading day preceding the date on
which the Stock Account is to be credited, and the resulting number of shares (including fractional shares) shall be credited to the Executive’s Stock
Account. As of each date for payment of dividends on the Common Stock, the Stock Accounts shall be credited with an additional number of
shares (including fractional shares) equal to the amount of dividends that would be paid on the number of shares recorded as the balance of the
Stock Account as of the record date for such dividend divided by closing market price of the Common Stock reported for such payment date or, if
such day is not a trading day, the next trading day.
4.4 Cash Account. An Executive’s Cash Account shall be denominated in dollars. With respect to each amount of Cash Compensation, Cash
LTIP Compensation or Matching Contribution deferred to an Executive’s Cash Account, an equal amount of dollars shall be credited to the
Executive’s Cash Account. With respect to Stock LTIP Compensation deferred to an Executive’s Cash Account, the number of deferred shares shall
be multiplied by the closing market price of the Common Stock reported for the last trading day preceding the date on which the Cash Account is to
be credited, and the resulting number of dollars shall be credited to the Executive’s Cash Account. Interest on each Cash Account shall be
calculated as of each Determination Date based upon the average daily balance of the Cash Account since the preceding Determination Date and
shall be credited to the Cash Account at that time.
4.5 Effect of Corporate Transaction on Stock Accounts. At the time of consummation of a Corporate Transaction, if any, the amount credited
to an Executive’s Stock Account shall be converted into a credit for cash or common stock of the acquiring company (“Acquiror Stock”) based on
the consideration received by shareholders of the Corporation in the Corporate Transaction, as follows:
(a) Stock Transaction. If holders of Common Stock receive Acquiror Stock in the Corporate Transaction, then (i) the amount credited to
each Executive’s Stock Account shall be converted into a credit for the number of shares of Acquiror Stock that the Executive would have
received as a result of the Corporate Transaction if the Executive had actually held the Common Stock credited to his or her Stock Account
immediately prior to the consummation of the Corporate Transaction, and (ii) Stock Accounts will thereafter be denominated in shares of
Acquiror Stock and ongoing deferrals of Compensation shall continue to be made in accordance with outstanding Deferral Commitments into
the Stock Accounts as so denominated.
(b) Cash or Other Property Transaction. If holders of Common Stock receive cash or other property in the Corporate Transaction, then
(i) the amount credited to an Executive’s Stock Account shall be transferred to the Executive’s Cash Account and converted into a cash credit
for the amount of cash or the value of the property that the Executive would have received as a result of the Corporate Transaction if the
Executive had actually held the Common Stock credited to his or her Stock Account immediately prior to the consummation of
PAGE 7 – EXECUTIVE DEFERRED COMPENSATION PLAN
the Corporate Transaction, and (ii) Stock Accounts shall no longer exist under the Plan and all ongoing deferrals shall thereafter be made into
Cash Accounts.
(c) Combination Transaction. If holders of Common Stock receive Acquiror Stock and cash or other property in the Corporate
Transaction, then (i) the amount credited to each Executive’s Stock Account shall be converted in part into a credit for Acquiror Stock under
Section 4.5(a) and in part into a credit for cash under Section 4.5(b) in the same proportion as such consideration is received by shareholders,
and (ii) ongoing deferrals into Stock Accounts pursuant to outstanding Deferral Commitments shall continue to be made into Stock Accounts
in accordance with Section 4.5(a).
(d) Election Following Stock Transaction. For a period of 12 months following the consummation of any Corporate Transaction which
results in Executives having Stock Accounts denominated in Acquiror Stock, each Executive shall have a one-time right to elect to transfer the
entire amount in the Executive’s Stock Account into the Executive’s Cash Account; provided, however, that this election shall not be
available if the Corporate Transaction results in holders of Common Stock becoming holders of all of the outstanding common stock of a
parent corporation of the Corporation. Such election shall be made by written notice to the Corporation and shall be effective on the date
received by the Corporation. If such an election is made, the amount of cash to be credited to the Executive’s Cash Account shall be
determined by multiplying the number of shares of Acquiror Stock in the Executive’s Stock Account by the closing market price of the
Acquiror Stock reported for the last trading day preceding the effective date of the election.
4.6 Statement of Account. As soon as practicable after each Determination Date, a report shall be issued by the Corporation to each
participating Executive setting forth the balances of the Executive’s Accounts under the Plan as of the immediately preceding Determination Date.
ARTICLE V
PLAN BENEFITS
5.1 Plan Benefit. The Corporation shall pay Plan Benefits to each Executive pursuant to this Article V equal to the Executive’s Accounts.
5.2 Commencement of Payments.
(a) Payment of any Deferred Compensation Account Benefits under the Plan shall commence as of the earlier of:
(i) A date elected by the Executive as specified in the applicable Participation Agreement between the Corporation and the
Executive; or
(ii) A day in January of the year following the year of the Executive’s Retirement, total Disability or other termination of
employment, with the specific day to be determined by the Corporation.
PAGE 8 – EXECUTIVE DEFERRED COMPENSATION PLAN
(b) Supplemental Retirement Benefits under Section 5.7 shall be made as of, or commence as of, the earliest date for which a monthly
payment is payable to or for the Executive under the Retirement Plan.
5.3 Lump Sum or Installment Payments.
(a) At the time the Executive elects to defer Compensation, the Executive may also elect to receive Deferred Compensation Account
Benefits either:
(i) In equal or approximately equal annual installments (the number of such installments not to exceed fifteen (15)) as designated
by the Executive, with the amount of the installments being adjusted over the installment period to reflect changes in Interest or
dividends credited to the Executive’s Accounts;
(ii) In a single sum payment; or
(iii) In a combination of partial lump sum payment, and remainder in installments.
(b) An Executive may elect to modify such election by filing a change of payment designation which shall supersede the prior form of
payment designation in the Participation Agreement for Compensation deferred in any one (1) or more calendar years. If the Executive’s most
recent change of payment designation has not been filed one (1) full calendar year prior to the year of Executive’s Retirement, Disability, other
termination of employment or earlier date selected for commencement of payments, the prior election shall be used to determine the form of
payment. For example, an Executive retiring in 2003 must file a written request with the Committee by December 31, 2001 to change the
Executive’s form of payment designation.
5.4 Form of Benefit Payment. Benefits payable to an Executive from a Stock Account shall only be paid to such Executive as a distribution of
Common Stock (or Acquiror Stock, if applicable) plus cash for fractional shares. Benefits payable to an Executive from a Cash Account shall only be
paid to such Executive in cash.
5.5 Hardship Distributions. Notwithstanding the foregoing provisions of this Article V, payment from the Executive’s Accounts may be made
to the Executive in the sole discretion of the Committee based upon a finding that an Executive has suffered a Financial Hardship. The amount of
such a withdrawal shall be limited to the amount reasonably necessary to meet the Executive’s needs resulting from the Financial Hardship. If
payment is made due to Financial Hardship under this Plan, the Executive’s deferrals shall cease for a twelve (12) month period. Any resumption of
the Executive’s deferrals under the Plan after such twelve (12) month period shall be made only at the election of the Executive in accordance with
Article III herein.
5.6 Death Benefit. Upon the death of the Executive or a former Executive prior to the receipt of the full amount of Deferred Compensation
Account Benefits, the balance of such benefits shall be paid by the Corporation to the applicable surviving designated Beneficiary or Beneficiaries
as soon as practicable in the manner elected in writing by the Executive, or, if no such election is made, by single sum payment.
PAGE 9 – EXECUTIVE DEFERRED COMPENSATION PLAN
5.7 Supplemental Retirement Benefit. Any Executive who elects to defer Compensation under this Plan and who also satisfies the eligibility
requirements for payment of any benefit under the Retirement Plan shall qualify for further payment by the Corporation of Supplemental Retirement
Benefits payable as an annuity under this Plan, as provided below:
(a) Amount. The amount payable by the Corporation each month during the time an annuity benefit is payable to the Executive or
Executive’s Beneficiary(ies) under the Retirement Plan shall be:
(i) The amount that would be payable at such time under the Retirement Plan determined under Section 5.7(c) by treating all
accrued benefits under the Retirement Plan as being payable only in the annuity form and by treating all Cash Compensation deferred
by the Executive under this Plan as though it had been “paid” to or “received” by Executive in the year when the deferral was made,
provided that all such deferred amounts shall be subject to the other applicable definitions and rules of the Retirement Plan relating to
benefit determination; plus
(ii) The reduction, if any, in the amount of the “primary Social Security Benefit” which will actually be payable to the Executive,
provided that such reduction results from the fact that Compensation deferred under this Plan causes the primary Social Security Benefit
payable to the Executive to be reduced and that such reduction is not otherwise payable under Section 5.7(a)(i) above; minus
(iii) The amount actually payable at such time under the Retirement Plan as determined under Section 5.7(c) by treating all accrued
benefits under the Retirement Plan as being payable only in the annuity form.
(b) Form and Duration. The form of Supplemental Retirement Benefit payable by the Corporation shall be the same annuity form, and
shall be paid by the Corporation for the same duration, as the annuity benefit actually payable under the Retirement Plan. Such annuity benefit
forms include (subject to any change in the Retirement Plan at the time payment begins) a standard life annuity (no survivorship benefit); a
half (50%) or full (100%) joint and survivor annuity to the Executive and surviving spouse with or without a “pop-up” if the spouse dies
before the Executive; a ten (10) year certain annuity which can provide death benefits to any surviving designated beneficiary; and a full
(100%) joint and survivor benefit for the spouse of a vested married Executive who dies before retirement; and payees include the Executive
and, if the operative form provides for payment after the Executive’s death, the Executive’s surviving spouse or other surviving designated
Beneficiary(ies) or estate.
(c) Retirement Plan Lump Sum Election Ignored. Notwithstanding any election by an Executive to receive a portion of Executive’s
Retirement Plan benefit as a lump sum, the amount of the Supplemental Retirement Benefit as determined under Section 5.7(a) and the form and
duration of the Supplemental Retirement Benefit as determined under Section 5.7(b) shall be calculated and determined as if Executive were to
receive Executive’s entire Retirement Plan accrued benefit in the same annuity form that applies to the annuity portion of Executive’s
Retirement Plan benefit.
PAGE 10 – EXECUTIVE DEFERRED COMPENSATION PLAN
5.8 Withholding; Payroll Taxes. The Corporation shall withhold from payments made hereunder any taxes required to be withheld from such
payments under federal, state or local law. However, a Beneficiary may elect in writing not to have withholding for federal income tax purposes
pursuant to Section 3405(a)(2) of the Internal Revenue Code, or any successor provision thereto.
5.9 Payment to Guardian. If a Plan Benefit is payable to a minor or a person declared incompetent or to a person incapable of handling the
disposition of his or her property, the Committee may direct payment of such Plan Benefit to the guardian, legal representative or person having the
care and custody of such minor, incompetent or person. The Committee may require proof of incompetence, minority, incapacity or guardianship as
it may deem appropriate prior to distribution of the Plan Benefit. Such distribution shall completely discharge the Committee and the Corporation
from all liability with respect to such benefit.
5.10 Accelerated Distribution. Notwithstanding any other provision of the Plan, an Executive shall be entitled to receive, upon written request
to the Committee, a lump sum distribution equal to ninety percent (90%) of the balance in the Executive’s Accounts as of the Determination Date
immediately preceding the date on which the Committee receives the written request. The remaining balance shall be forfeited by the Executive. An
Executive who receives a distribution under this section shall be suspended from participation in the Plan for twelve (12) months. The amount
payable under this section shall be paid in a lump sum within sixty-five (65) days following the receipt of the notice by the Committee from the
Executive.
ARTICLE VI
BENEFICIARY DESIGNATION
6.1 Beneficiary Designation. Each Executive shall have the right, at any time, to designate any person or persons as the Executive’s
Beneficiary or Beneficiaries (both primary as well as secondary) to whom benefits under this Plan shall be paid in the event of the Executive’s death
prior to complete distribution of the benefits due under the Plan. If greater than fifty percent (50%) of the benefit is designated to a Beneficiary other
than the Executive’s spouse, such Beneficiary designation shall be consented to by the Executive’s spouse. Each Beneficiary designation shall be
in written form prescribed by the Committee and will be effective only when filed with the Committee during the Executive’s lifetime.
6.2 Amendments. Any Beneficiary designation may be changed by the Executive without the consent of any designated Beneficiary by the
filing of a new Beneficiary designation with the Committee, subject to the spousal consent required in Section 6.1 above. The filing of a new
Beneficiary designation form will cancel all Beneficiary designations previously filed.
6.3 No Beneficiary Designation. In the absence of an effective Beneficiary designation, or if all designated Beneficiaries predecease the
Executive or die prior to complete distribution of the Executive’s benefits, then the Executive’s designated Beneficiary shall be deemed to be the
Executive’s estate.
PAGE 11 – EXECUTIVE DEFERRED COMPENSATION PLAN
6.4 Effect of Payment. The payment to the deemed Beneficiary shall completely discharge the Corporation’s obligations under this Plan.
ARTICLE VII
ADMINISTRATION
7.1 Committee; Duties. This Plan shall be administered by the Committee. The Committee shall have such powers as may be necessary to
discharge its responsibilities. These powers shall include, but not be limited to, interpretation of the Plan provisions, determination of amounts due
to any Executive, the rights of any Executive or Beneficiary under this Plan, the right to require any necessary information from any Executive,
determine the amounts credited to Executive’s Accounts and Interest earned, and any other activities deemed necessary or helpful.
7.2 Agents. The Committee may, from time to time, employ other agents and delegate to them such administrative duties as it sees fit, and may
from time to time consult with counsel who may be counsel to the Corporation.
7.3 Binding Effect of Decisions. The decision or action of the Committee with respect to any question arising out of or in connection with the
administration, interpretation and application of the Plan and the rules and regulations promulgated hereunder shall be final and conclusive and
binding upon all persons having any interest in the Plan.
7.4 Indemnity of Committee. To the extent permitted by applicable law, the Corporation shall indemnify, hold harmless and defend the members
of the Committee against any and all claims, loss, damage, expense or liability arising from any action or failure to act with respect to this Plan,
provided that the members of the Committee were acting in accordance with the applicable standard of care.
ARTICLE VIII
CLAIMS PROCEDURE
8.1 Claim. Any person claiming a benefit, requesting an interpretation or ruling under the Plan, or requesting information under the Plan shall
present the request in writing to the Committee, which shall respond in writing as soon as practicable.
8.2 Denial of Claim. If the claim or request is denied, the written notice of denial shall state:
(a) The reasons for denial, with specific reference to the Plan provisions on which the denial is based;
(b) A description of any additional material or information required and an explanation of why it is necessary; and
(c) An explanation of the Plan’s claim review procedure.
PAGE 12 – EXECUTIVE DEFERRED COMPENSATION PLAN
8.3 Review of Claim. Any person whose claim or request is denied or who has not received a response within thirty (30) days may request
review by notice given in writing to the Committee. The claim or request shall be reviewed by the Committee who may, but shall not be required to,
grant the claimant a hearing. On review, the claimant may have representation, examine pertinent documents, and submit issues and comments in
writing.
8.4 Final Decision. The decision on review shall normally be made within sixty (60) days. If an extension of time is required for a hearing or
other special circumstances, the claimant shall be notified and the time limit shall be one hundred twenty (120) days. The decision shall be in writing
and shall state the reasons and the relevant Plan provisions. All decisions on review shall be final and bind all parties concerned.
ARTICLE IX
AMENDMENT AND TERMINATION OF THE PLAN
9.1 Amendment. The Board may at any time amend the Plan in whole or in part, subject to the following:
(a) Upon a Change in Control, no amendment shall be effective to change the payout schedule in Section 9.2(b).
(b) No amendment shall be effective to decrease or restrict the amount credited to any Account maintained under the Plan as of the date
of the amendment. Changes in the definition of Interest shall be subject to the following restrictions:
(i) Notice. A change shall not become effective before the first day of the calendar year which follows the adoption of the
amendment and at least thirty (30) days written notice of the amendment to the Executive.
(ii) Change in Control. Any change in the definition of Interest after a Change in Control shall apply only to those amounts
credited to the Executive’s Account after the Change in Control.
9.2 Corporation’s Right to Terminate. The Board may at any time partially or completely terminate the Plan, if, in its judgment, the tax,
accounting, or other effects of the continuance of the Plan, or potential payments thereunder, would not be in the best interests of the Corporation.
(a) Partial Termination. The Board may partially terminate the Plan by instructing the Committee not to accept any additional Deferral
Commitments. In the event of such a partial termination, the Plan shall continue to operate and be effective with regard to Deferral
Commitments entered into prior to the effective date of such partial termination.
(b) Complete Termination. The Board may completely terminate the Plan by instructing the Committee not to accept any additional
Deferral Commitments, and terminating all ongoing Deferral Commitments. The Plan shall cease to operate and the Committee shall pay out to
each Executive the balance in the Executive’s Accounts in a lump sum or in equal annual
PAGE 13 – EXECUTIVE DEFERRED COMPENSATION PLAN
installments amortized over the period listed in the payout schedule below based on the total balance in the Executive’s Accounts at the time
of such complete termination:
PAYOUT SCHEDULE
Payout Period
Total Balance of Accounts
Less than $10,000
$10,000 but less than $50,000
More than $50,000
Lump sum
Lesser of 5 years or period elected in Participation
Agreement
Period elected in Participation Agreement
Interest earned on the unpaid balance in the Executive’s Cash Account shall be the applicable Interest rate on the Determination Date
immediately preceding the effective date of such complete termination.
ARTICLE X
MISCELLANEOUS
10.1 Unfunded Plan. This Plan is intended to be an unfunded plan maintained primarily to provide deferred compensation benefits for a select
group of “management or highly-compensated employees” within the meaning of Sections 201, 301, and 401 of the Employee Retirement Income
Security Act of 1974, as amended (“ERISA”), and therefore to be exempt from the provisions of Parts 2, 3 and 4 of Title I of ERISA. Accordingly, the
Plan shall terminate and no further benefits shall accrue hereunder in the event it is determined by a court of competent jurisdiction or by an opinion
of counsel that the Plan constitutes an employee pension benefit plan within the meaning of Section 3(2) of ERISA which is not so exempt. In the
event of a termination under this Section 10.1, all ongoing Deferral Commitments shall terminate, no additional Deferral Commitments will be
accepted by the Committee, and the amount of each Executive’s Account balance shall be distributed to such Executive at such time and in such
manner as the Committee, in its sole discretion, determines.
10.2 Unsecured General Creditor. The Accounts shall be established solely for the purpose of measuring the amounts owed to Executives or
their Beneficiaries under this Plan. Executives and their Beneficiaries, heirs, successors and assigns shall have no legal or equitable rights, interest
or claims in any property or assets of the Corporation, nor shall they be Beneficiaries of, or have any rights, claims or interests in any life insurance
policies, annuity contracts or the proceeds therefrom owned or which may be acquired by the Corporation. Except as may be provided in
Section 10.3, such policies, annuity contracts or other assets of the Corporation shall not be held under any trust for the benefit of the Executives,
their Beneficiaries, heirs, successors or assigns, or held in any way as collateral security for the fulfilling of the obligations of the Corporation under
this Plan. Any and all of the Corporation’s assets and policies shall be, and remain, the general, unpledged, unrestricted assets of the Corporation.
The Corporation’s obligation under the Plan shall be that of an unfunded and unsecured promise to pay money in the future.
PAGE 14 – EXECUTIVE DEFERRED COMPENSATION PLAN
10.3 Trust Fund. The Corporation shall be responsible for the payment of all benefits provided under the Plan. The Corporation shall establish
the Trust, with such trustee or trustees as the Board may approve, for the purpose of providing for the payment of such benefits. The Trust shall be
irrevocable, but the assets thereof shall be subject to the claims of the Corporation’s creditors. To the extent any benefits provided under the Plan
are actually paid from the Trust, the Corporation shall have no further obligation with respect thereto, but to the extent not so paid, such benefits
shall remain the obligation of, and shall be paid by, the Corporation.
10.4 Nonassignability. Neither an Executive nor any other person shall have the right to commute, sell, assign, transfer, pledge, anticipate,
mortgage or otherwise encumber, transfer, hypothecate or convey in advance of actual receipt the amounts, if any, payable hereunder, or any part
thereof, which are, and all rights to which are, expressly declared to be unassignable and nontransferable. No part of the amounts payable shall,
prior to actual payment, be subject to seizure or sequestration for the payment of any debts, judgments, alimony or separate maintenance owed by
an Executive or any other person, nor be transferable by operation of law in the event of an Executive’s or any other person’s bankruptcy or
insolvency.
10.5 Not a Contract of Employment. The terms and conditions of this Plan shall not be deemed to constitute a contract of employment between
the Corporation and the Executive, and the Executive (or the Executive’s Beneficiary) shall have no rights against the Corporation except as may
otherwise be specifically provided herein. Moreover, nothing in this Plan shall be deemed to give an Executive the right to be retained in the service
of the Corporation or to interfere with the right of the Corporation to discipline or discharge the Executive at any time.
10.6 Protective Provision. An Executive will cooperate with the Corporation by furnishing any and all information requested by the
Corporation, in order to facilitate the payment of benefits hereunder, and by taking such physical examinations as the Corporation may deem
necessary and taking such other actions as may be requested by the Corporation.
10.7 Governing Law. The provisions of this Plan shall be construed and interpreted according to the laws of the State of Oregon, except as
preempted by federal law.
10.8 Validity. In case any provision of this Plan shall be held illegal or invalid for any reason, said illegality or invalidity shall not affect the
remaining parts hereof, but this Plan shall be construed and enforced as if such illegal and invalid provisions had never been inserted herein.
10.9 Notice. Any notice or filing required or permitted to be given to the Committee under the Plan shall be sufficient if in writing and hand
delivered, or sent by registered or certified mail, to any member of the Committee or the Secretary of the Corporation. Such notice shall be deemed
given as of the date of delivery or, if delivery is made by mail, as of the date shown on the postmark on the receipt for registration or certification.
10.10 Successors. The provisions of this Plan shall bind and inure to the benefit of the Corporation and its successors and assigns. The term
successors as used herein shall include any corporate or other business entity which shall, whether by merger, consolidation, purchase or
PAGE 15 – EXECUTIVE DEFERRED COMPENSATION PLAN
otherwise, acquire all or substantially all of the business and assets of the Corporation, and successors of any such corporation or other business
entity.
NORTHWEST NATURAL GAS COMPANY
By:
Attest:
PAGE 16 – EXECUTIVE DEFERRED COMPENSATION PLAN
(Back To Top)
Section 4: EX-10.F (DIRECTORS DEFERRED COMPENSATION PLAN)
Exhibit 10.f
NORTHWEST NATURAL GAS COMPANY
DIRECTORS DEFERRED COMPENSATION PLAN
EFFECTIVE JUNE 1, 1981
RESTATED AS OF FEBRUARY 26, 2009
Table of Contents
Page
1.
Restatement
1
2.
Election by Directors
1
3.
Accounts
2
4.
Interest
4
5.
Terms of Payment
5
6.
Death of Director
6
7.
Administration
6
8.
Definitions; Change in Control; Corporate Transaction
7
9.
Amendment and Termination of the Plan
8
10.
Miscellaneous
9
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NORTHWEST NATURAL GAS COMPANY
DIRECTORS DEFERRED COMPENSATION PLAN
1. Restatement. The Board of Directors (the “Board”) of Northwest Natural Gas Company (hereinafter, the “Company”) adopted a Director’s
Deferred Compensation Plan (hereinafter, the “Plan”) effective June 1, 1981, which was previously restated effective as of January 1, 1988,
December 1, 1997, December 1, 2001, February 26, 2004, December 15, 2005, January 1, 2007 and February 28, 2008. The Plan was partially terminated
in accordance with Paragraph 9(b)(i) effective December 31, 2004, so deferrals of compensation are no longer being made under the Plan. The Plan is
now amended and restated by this Restatement, effective as of February 26, 2009.
2. Election by Directors.
(a) Eligibility. Any director of the Company or any corporation or other entity affiliated with or subsidiary to it (a “Director”) is eligible to
elect to defer receipt of all or part of (i) the fees paid to him or her as a Director or as a member of a committee of the Board (“Fees”), or (ii) the
shares (“NEDSCP Shares”) of restricted common stock of the Company (“Common Stock”) awarded to the Director under the Company’s
Non-Employee Directors Stock Compensation Plan (“NEDSCP”). In addition, a Director may elect under the NEDSCP to receive awards under
that plan as deferred cash credits (“NEDSCP Cash Credits”) rather than as NEDSCP Shares.
(b) Deferral of Fees. Any Director may elect, prior to the beginning of any calendar year, to defer receipt of fees for that calendar year,
whether or not the fees are actually payable in that calendar year; and any newly elected Director prior to assuming office may elect to defer
receipt of fees commencing after the date on which the Director assumes office. Any election under the preceding sentence shall apply only to
fees earned subsequent to the date the election is filed. Total deferrals of Fees by a Director in a calendar year must be at least $1,500.
(c) Deferral of NEDSCP Shares. Any Director may elect, prior to the beginning of any calendar year, to defer receipt of unvested
NEDSCP Shares that are scheduled to vest in that calendar year; and any newly elected Director prior to assuming office may elect to defer
receipt of NEDSCP Shares that will vest in the remainder of the calendar year after the date on which the Director assumes office. Total
deferrals of NEDSCP Shares by a Director in a calendar year must be at least 100% of the NEDSCP Shares scheduled to vest in that year. No
deferral shall be allowed of NEDSCP Shares as to which a Director has made an election under Section 83(b) of the Internal Revenue Code.
(d) Continuation and Modification. An election to defer Fees or NEDSCP Shares by a Director shall automatically continue from year to
year unless the Director terminates or modifies the election by written request. Any such termination or modification shall not become
applicable until the calendar year following the year in which such written termination or modification is filed. In the event of a termination of a
deferral election, any amounts already deferred by a Director shall not be paid until he or she ceases to serve as a Director, and then only
pursuant to the terms, conditions, limitations and restrictions of the Plan.
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3. Accounts.
(a) Accounts. The Company shall establish on its books one, two or three separate accounts (individually, an “Account” and
collectively, the “Accounts”) for each Director who participates in the Plan: a Stock Account, a Cash Account, and/or for each person who is
a Director as of January 1, 1998, a Retirement Benefit Account. The number of NEDSCP Shares deferred by a Director shall be credited to the
Stock Account. Any NEDSCP Cash Credits shall be credited to the Cash Account. Fees deferred by a Director shall be credited to the Stock
Account or the Cash Account as elected by the Director at the time the Director elects to defer Fees. Such election may be divided between
the two Accounts in increments of 25 percent of the deferred Fees covered by the election. An election between the Stock Account and the
Cash Account shall be irrevocable as to the deferred Fees covered by the election and no transfers between the Stock Account and the Cash
Account shall be permitted except as otherwise provided in Paragraph 3(f)(iv). The credit for deferred Fees shall be entered on the Company’s
books of account each month at the time that Fees are paid to other Directors who do not elect to defer the payment of such Fees. The credit
for deferred NEDSCP Shares shall be entered on the Company’s books of account as soon as practicable after January 1 of the year subject to
the deferral. The credit for an NEDSCP Cash Credit shall be entered on the Company’s books of account effective as of the award date for
such credit under the NEDSCP. No special fund shall be established nor shall any notes or securities be issued by the Company with respect
to a Director’s Accounts.
(b) Stock Account. A Director’s Stock Account shall be denominated in shares of Common Stock, including fractional shares. With
respect to each amount of Fees deferred to a Director’s Stock Account, the Stock Account shall be credited with a number of shares equal to
the deferred Fees divided by the purchase price for shares of Common Stock under the Company’s Dividend Reinvestment and Direct Stock
Purchase Plan (the “DRSPP”) on the Investment Date (as defined in the DRSPP) next succeeding the day the deferred Fees would have been
paid if not for the deferral. As of each date for payment of dividends on the Common Stock, the Stock Accounts shall be credited with an
additional number of shares (including fractional shares) equal to the amount of dividends that would be paid on the number of shares
recorded as the balance of the Stock Account as of the record date for such dividend divided by closing market price of the Common Stock
reported for such payment date or, if such day is not a trading day, the next trading day.
(c) Forfeiture of NEDSCP Shares or NEDSCP Cash Credits. If any NEDSCP Shares deferred by a Director under this Plan are forfeited
under the terms of the NEDSCP, the Director’s Stock Account shall be reduced by the number of shares so forfeited. If any NEDSCP Cash
Credits of a Director are forfeited under the terms of the NEDSCP, the Director’s Cash Account shall be reduced by the amount of NEDSCP
Cash Credits so forfeited.
(d) Retirement Benefit Account. A Director’s Retirement Benefit Account shall be denominated in shares of Common Stock, including
fractional shares. Effective as of January 1, 1998, Section 5 of Article III of the Company’s Bylaws has been amended to eliminate with respect
to all persons who are Directors as of January 1, 1998 a provision for a retirement benefit payable to Directors who retire from the Board at age
72 with at least 10 years of service. Effective as of January 1, 1998, the Retirement Benefit Account of each person who
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is a Director on that date shall be credited with a number a shares of Common Stock determined by the Company as a replacement for the prior
retirement benefit. As of each date for payment of dividends on the Common Stock, the Retirement Benefit Accounts shall be credited with an
additional number of shares (including fractional shares) equal to the amount of dividends that would be paid on the number of shares
recorded as the balance of the Retirement Benefit Account as of the record date for such dividend divided by the purchase price for shares of
Common Stock under the DRSPP for dividends reinvested on such payment date. The Retirement Benefit Account of any Director who has
not ceased to be a Director prior to February 28, 2008 shall be fully vested and noncancellable effective as of February 28, 2008.
(e) Statement of Account. At the end of each calendar quarter, a report shall be issued by the Company to each participating Director
setting forth the balances of the Director’s Accounts under the Plan. The credit entries made to a Director’s Accounts constitute merely a
general obligation of the Company to pay such Accounts to the Director, or to his or her beneficiary or estate when due under the Plan.
(f) Effect of Corporate Transaction on Stock Accounts and Retirement Benefit Accounts. At the time of consummation of a Corporate
Transaction, if any, the amount credited to a Director’s Stock Account and Retirement Benefit Account shall be converted into a credit for
cash or common stock of the acquiring company (“Acquiror Stock”) based on the consideration received by shareholders of the Company in
the Corporate Transaction, as follows:
(i) Stock Transaction. If holders of Common Stock receive Acquiror Stock in the Corporate Transaction, then (1) the amount
credited to each Director’s Stock Account and/or Retirement Benefit Account shall be converted into a credit for the number of shares
of Acquiror Stock that the Director would have received as a result of the Corporate Transaction if the Director had actually held the
Common Stock credited to his or her Stock Account and/or Retirement Benefit Account immediately prior to the consummation of the
Corporate Transaction, and (2) Stock Accounts and Retirement Benefit Accounts will thereafter be denominated in shares of Acquiror
Stock and ongoing deferrals of Fees and NEDSCP Shares, if any, shall continue to be made in accordance with outstanding deferral
elections into the Stock Accounts as so denominated.
(ii) Cash or Other Property Transaction. If holders of Common Stock receive cash or other property in the Corporate Transaction,
then (1) the amount credited to a Director’s Stock Account and/or Retirement Benefit Account shall be transferred to the Director’s
Cash Account and converted into a cash credit for the amount of cash or the value of the property that the Director would have
received as a result of the Corporate Transaction if the Director had actually held the Common Stock credited to his or her Stock
Account and/or Retirement Benefit Account immediately prior to the consummation of the Corporate Transaction, and (2) Stock
Accounts shall no longer exist under the Plan and all ongoing deferrals, if any, shall thereafter be made into Cash Accounts.
(iii) Combination Transaction. If holders of Common Stock receive Acquiror Stock and cash or other property in the Corporate
Transaction, then (1) the amount credited to each Director’s Stock Account and/or Retirement Benefit Account shall be converted in
part into a credit for Acquiror Stock under Paragraph 3(f)(i) and in part into a credit for cash
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under Paragraph 3(f)(ii) in the same proportion as such consideration is received by shareholders, and (2) ongoing deferrals of Fees and
NEDSCP Shares, if any, shall continue to be made in accordance with outstanding deferral elections into Stock Accounts in accordance
with Paragraph 3(f)(i).
(iv) Election Following Stock Transaction. For a period of 12 months following the consummation of any Corporate Transaction
which results in Directors having Stock Accounts and/or Retirement Benefit Accounts denominated in Acquiror Stock, each Director
shall have a one-time right to elect to transfer the entire amount in the Director’s Stock Account and Retirement Benefit Account into
the Director’s Cash Account; provided, however, that this election shall not be available if the Corporate Transaction results in holders
of Common Stock becoming holders of all of the outstanding common stock of a parent corporation of the Company. Such election shall
be made by written notice to the Company and shall be effective on the date received by the Company. If such an election is made, the
amount of cash to be credited to the Director’s Cash Account shall be determined by multiplying the number of shares of Acquiror
Stock in the Director’s Stock Account and Retirement Benefit Account by the closing market price of the Acquiror Stock reported for
the last trading day preceding the effective date of the election.
4. Interest. Interest shall be credited to the Cash Account balance (including both principal and interest) of each participating Director based
on the balance at the end of each calendar quarter. The rate of interest to be applied at the end of each calendar quarter is set forth below in this
Paragraph 4. The interest credit shall continue to be applied to the Cash Account of a Director, even if ceasing to serve as a Director, until all
amounts credited to his or her Cash Account have been paid. Said interest shall be calculated quarterly, based upon the average daily balance of
the Director’s Cash Account since the preceding calendar quarter, after giving effect to any reduction in the Cash Account as a result of any
payments. The remaining annual payments will be recomputed to reflect the additional interest credits.
The rate of interest to be applied at the end of each calendar quarter shall be the quarterly equivalent of an annual yield that is two percentage
points (2%) higher than the annual yield on Moody’s Average Corporate Bond Yield for the preceding quarter, as published by the Moody’s
Investors Service, Inc. (or any successor thereto), or if such index is no longer published, a substantially similar index selected by the Board. At no
time shall the rate of interest be less than six percent (6%) annually. Notwithstanding the foregoing, effective as of January 1, 2017, the rate of
interest to be applied at the end of each calendar quarter shall be the rate of interest for interest credited to cash accounts under the Company’s
Deferred Compensation Plan for Directors and Executives, as such plan may be amended from time to time (the “DCPDE”), regardless of whether or
not such rate of interest shall be more or less than six percent (6%) annually; provided, however, that if at any time on or after January 1, 2017 there
is no interest credited to cash accounts under the DCPDE because the DCPDE shall have ceased to operate or for any other reason, then, at such
time on or after January 1, 2017, the rate of interest to be applied at the end of each calendar quarter shall be the quarterly equivalent of an annual
yield that is equal to the annual yield on Moody’s Average Corporate Bond Yield for the preceding quarter, as published by Moody’s Investors
Service, Inc. (or any successor thereto), or, if such index is no longer published, a substantially similar index selected by the Board, regardless of
whether or not such rate of interest shall be more or less than six percent (6%) annually. Any
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change in the rate of interest that occurs on January 1, 2017 or thereafter pursuant to the provisions of this paragraph shall not constitute an
“amendment affecting the interest rate” within the meaning of Paragraph 9(a) below.
5. Terms of Payment.
(a) Plan Benefits. The amounts contained in a Director’s Accounts are subject to the terms of payment as set forth in this paragraph.
When a Director ceases to serve as a Director of the Company, either by retirement or otherwise, the individual shall be entitled to payment of
the amounts in his or her Accounts.
(b) Timing of Benefit Payment. At the time the Director elects to defer Fees or NEDSCP Shares or to receive NEDSCP Cash Credits in lieu
of NEDSCP Shares, and with respect to Retirement Benefit Accounts before January 1, 1998, the Director may designate the number of annual
installments, not to exceed ten, in which the applicable Account balance shall be paid, or the Director may elect to receive such Account
balance in a lump sum payment, or in a combination of a partial lump sum and the remainder in installment payments. A Director may elect to
modify such election by filing a change of payment designation which shall supersede the prior form of payment designation for any one
(1) or more deferral periods; provided, however, that a Director may not file a change of payment designation with respect to amounts credited
to his or her Retirement Benefit Account after December 31, 2008. If the Director’s most recent change of payment designation has not been
filed one (1) full calendar year prior to the year in which the Director ceases to serve as a Director of the Company, the prior election shall be
used to determine the form of payment. For example, a Director leaving the Board in 2003 must file a written request with the Committee by
December 31, 2001 to change his form of payment designation.
(c) Form of Benefit Payment. Benefits payable to a Director from a Stock Account or a Retirement Benefit Account shall only be paid to
such Director as a distribution of Common Stock plus cash for fractional shares. Benefits payable to a Director from a Cash Account shall only
be paid to such Director in cash.
(d) Commencement of Payment. Any lump sum payment or the first annual installment payment owed to a Director shall be paid on a day
in January of the year following the year in which he or she ceases to serve as a Director of the Company, with the specific day to be
determined by the Company. In the event a Director terminates the election to defer Fees or NEDSCP Shares, any Fees or NEDSCP Shares
already deferred shall not be payable to the Director until such time as he or she ceases to serve as a Director, and then only subject to the
terms and conditions contained herein. The provisions of this paragraph are subject to the terms of Paragraph 6 covering the death of a
Director and to the terms of Paragraph 8 covering a Change in Control.
(e) Payment to Guardian. If a benefit under the Plan is payable to a minor or a person declared incompetent or to a person incapable of
handling the disposition of his property, the Committee may direct payment of such Plan benefit to the guardian, legal representative or
person responsible for the care and custody of such minor, incompetent or person. The Committee may require proof of incompetence,
minority, incapacity or guardianship
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as it may deem appropriate prior to distribution of the Plan benefit. Such distribution shall completely discharge the Committee and the
Company from all liability with respect to such benefit.
(f) Withholding; Payroll Taxes. The Company shall withhold from payments made hereunder any taxes required to be withheld from such
payments under federal, state or local law.
(g) Accelerated Distribution. Notwithstanding any other provision of the Plan, a Director shall be entitled to receive, upon written
request to the Committee, a lump sum distribution equal to ninety percent (90%) of the total balance of the Director’s Cash Account and Stock
Account as of the last day of the calendar quarter immediately preceding the day on which the Committee receives the written request. The
remaining balance of the Director’s Cash Account and Stock Account shall be forfeited by the Director. No accelerated distribution under this
section shall be available for amounts in Directors’ Retirement Benefit Accounts. A Director who receives a distribution under this section
shall be suspended from participation in the Plan for 12 months, but such suspension shall not apply to crediting of NEDSCP Cash Credits.
The amount payable under this section shall be paid in a lump sum within 65 days following the receipt of the notice by the Committee from
the Director.
6. Death of Director.
(a) Plan Death Benefit. Upon the death of a Director or a former Director prior to the receipt of the full amount credited to his or her
Accounts, the balance of the Director’s Accounts shall be paid to the designated beneficiary or beneficiaries in the manner elected in writing
by the Director at the time of the deferral election, or if no such election is made, by lump sum payment.
(b) Beneficiary. At the time a Director elects to defer payment of Fees or NEDSCP Shares or to receive NEDSCP Cash Credits in lieu of
NEDSCP Shares, and with respect to Retirement Benefit Accounts before January 1, 1998, the Director may designate a beneficiary or
beneficiaries. If greater than 50% of the benefit is designated to a beneficiary other than the Director’s spouse, such beneficiary designation
shall be consented to by the Director’s spouse. Such designation may be changed by the Director at any time without the consent of a
beneficiary, subject to the spousal consent requirement above. If no designated beneficiary survives the Director or former Director, the
balance of the Director’s Accounts shall be paid to the Director’s estate.
7. Administration.
(a) Committee Duties. This Plan shall be administered by the Organization and Executive Compensation Committee of the Board (the
“Committee”). The Committee shall have responsibility for the general administration of the Plan and for carrying out its intent and provisions.
The Committee shall interpret the Plan and have such powers and duties as may be necessary to discharge its responsibilities. The Committee
may, from time to time, employ other agents and delegate to them such administrative duties as it sees fit, and may from time to time consult
with counsel who may be counsel to the Company.
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(b) Binding Effect of Decisions. The decision or action of the Committee in respect of any question arising out of or in connection with
the administration, interpretation and application of the Plan and the rules and regulations promulgated hereunder shall be final and
conclusive and binding upon all persons having any interest in the Plan.
(c) Indemnity of Committee. To the extent permitted by applicable law, the Company shall indemnify, hold harmless and defend the
members of the Committee against any and all claims, loss, damage, expense or liability arising from any action or failure to act with respect to
this Plan, provided that the members of the Committee were acting in accordance with the applicable standard of care.
8. Definitions; Change in Control; Corporate Transaction.
(a) For purposes of this Plan, a “Change in Control” of the Company shall mean the occurrence of any of the following events:
(i) The consummation of:
(A) any consolidation, merger or plan of share exchange involving the Company (a “Merger”) as a result of which the
holders of outstanding securities of the Company ordinarily having the right to vote for the election of directors (“Voting
Securities”) immediately prior to the Merger do not continue to hold at least 50% of the combined voting power of the
outstanding Voting Securities of the surviving corporation or a parent corporation of the surviving corporation immediately after
the Merger, disregarding any Voting Securities issued to or retained by such holders in respect of securities of any other party
to the Merger; or
(B) any sale, lease, exchange or other transfer (in one transaction or a series of related transactions) of all, or substantially
all, the assets of the Company;
(ii) At any time during a period of two consecutive years, individuals who at the beginning of such period constituted the board of
directors of the Company (“Incumbent Directors”) shall cease for any reason to constitute at least a majority thereof; provided,
however, that the term “Incumbent Director” shall also include each new director elected during such two-year period whose
nomination or election was approved by two-thirds of the Incumbent Directors then in office; or
(iii) Any person (as such term is used in Section 14(d) of the Securities Exchange Act of 1934, other than the Company or any
employee benefit plan sponsored by the Company) shall, as a result of a tender or exchange offer, open market purchases or privately
negotiated purchases from anyone other than the Company, have become the beneficial owner (within the meaning of Rule 13d-3 under
the Securities Exchange Act of 1934), directly or indirectly, of Voting Securities representing twenty percent (20%) or more of the
combined voting power of the then outstanding Voting Securities.
(b) For purposes of this Plan, a “Corporate Transaction” shall mean any of the following:
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(i) any consolidation, merger or plan of share exchange involving the Company pursuant to which shares of Common Stock would
be converted into cash, securities or other property; or
(ii) any sale, lease, exchange or other transfer (in one transaction or a series of related transactions) of all, or substantially all, the
assets of the Company.
9. Amendment and Termination of the Plan.
(a) Amendment. The Board may at any time amend the Plan in whole or in part; provided, however, that upon a Change in Control, no
amendment shall be effective to change the payout schedule in Paragraph 9(b)(ii), and further provided that no amendment shall decrease
or restrict the amount credited to any Account maintained under the Plan as of the date of amendment. An amendment affecting the
interest rate credited under Paragraph 4 shall not become effective before the first day of the calendar year which follows the adoption of
the amendment and at least 30 days written notice of the amendment to the Director. An amendment affecting the interest rate credited
under Paragraph 4 that is adopted after a Change in Control shall apply only to those amounts credited to Directors’ Accounts after the
Change in Control.
(b) Termination. The Board may at any time partially or completely terminate the Plan if, in its judgment, the tax, accounting, or other
effects of the continuance of the Plan, or potential payments thereunder, would not be in the best interests of the Company.
(i) Partial Termination. The Board may partially terminate the Plan by instructing the Committee not to accept any additional
deferrals. In the event of such a partial termination, the Plan shall continue to operate and be effective with regard to deferrals entered
into prior to the effective date of such partial termination.
(ii) Complete Termination. The Board may completely terminate the Plan by instructing the Committee not to accept any additional
deferrals, and terminate all ongoing deferrals. The Plan shall cease to operate and the Committee shall pay out to each Director the
balance in each of his or her Accounts in a lump sum or in equal annual installments amortized over the period listed in the payout
schedule below based on the balance in the particular Account at the time of such complete termination:
Payout Schedule
Payout Period
Appropriate Account Balance
Less than $10,000
$10,000 but less than $50,000
More than $50,000
Lump sum
Lesser of 5 years or period elected in Participation Agreement
Period elected in Participation Agreement
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Interest earned on the unpaid balance in the Director’s Cash Account shall be the applicable interest rate at the end of the calendar quarter
immediately preceding the effective date of such complete termination.
10. Miscellaneous.
(a) Unsecured General Creditor. The Accounts shall be established solely for the purpose of measuring the amounts owed to a Director
or beneficiary under the Plan. Directors and their beneficiaries, heirs, successors and assigns shall have no legal or equitable rights, interest or
claims in any property or assets of the Company, nor shall they be beneficiaries of, or have any rights, claims or interests in any life insurance
policies, annuity contracts or the proceeds therefrom owned or which may be acquired by the Company. Except as may be provided in
Paragraph 10(b), such policies, annuity contracts or other assets of the Company shall not be held under any trust for the benefit of the
Directors, their beneficiaries, heirs, successors or assigns, or held in any way as collateral security for the fulfilling of the obligations of the
Company under this Plan. Any and all of the Company’s assets and policies shall be, and remain, the general, unpledged, unrestricted assets
of the Company. The Company’s obligation under the Plan shall be that of an unfunded and unsecured promise to pay money in the future.
(b) Trust Fund. The Company shall be responsible for the payment of all benefits provided under the Plan. At its discretion, the
Company may establish one or more trusts, with such trustees as the Board may approve, for the purpose of providing for the payment of
such benefits. Such trust or trusts may be irrevocable, but the assets thereof shall be subject to the claims of the Company’s creditors. To the
extent any benefits provided under the Plan are actually paid from any such trust, the Company shall have no further obligation with respect
thereto, but to the extent not so paid, such benefits shall remain the obligation of, and shall be paid by, the Company.
(c) Nonassignability. No assignment or alienation may be made of any deferred fees or interest thereon, except in accordance with
Paragraph 6.
(d) Governing Law. The provisions of this Plan shall be construed and interpreted according to the laws of the State of Oregon.
(e) Successors. The provisions of this Plan shall bind and inure to the benefit of the Company and its successors and assigns. The term
successors as used herein shall include any corporate or other business entity which shall, whether by merger, consolidation, purchase or
otherwise acquire all or substantially all of the business and assets of the Company, and successors of any such corporation or other
business entity.
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(f) The foregoing restatement of the Plan was approved by the Board of Directors of Northwest Natural Gas Company effective as of
February 26, 2009.
NORTHWEST NATURAL GAS COMPANY
By:
Attest:
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(Back To Top)
Section 5: EX-10.J(10) (FIRM TRANSPORTATION SERVICE
AGREEMENT, DATED OCTOBER 22, 1993)
Exhibit 10j.(10)
FIRM TRANSPORTATION SERVICE AGREEMENT
THIS AGREEMENT IS made and entered into this 22nd day of October, 1993, by and between
PACIFIC GAS TRANSMISSION COMPANY, a California corporation (hereinafter referred to as “PGT”), and
NORTHWEST NATURAL GAS COMPANY, a corporation existing under the laws of the State of Oregon (hereinafter referred to as “Shipper”).
WHEREAS, PGT owns and operates a natural gas interstate pipeline transmission system which extends from a point of interconnection with the
pipeline facilities of Alberta Natural Gas Company Ltd. (ANG) at the International Boundary near Kingsgate, British Columbia, through the states of
Idaho, Washington and Oregon to a point of interconnection with Pacific Gas and Electric Company at the Oregon-California border near Malin,
Oregon; and
WHEREAS, Shipper desires PGT, on a firm basis, to transport certain quantities of natural gas from the International Boundary in the vicinity of
Kingsgate, British Columbia and/or from Stanfield, Oregon (receipt points) to various delivery points as specified in Exhibit A of this Agreement;
and
WHEREAS, since July 15, 198 I, PGT has provided firm transportation service to the Northwest Pipeline Corporation (“Northwest”) under the terms
and conditions of a firm transportation service agreement between PGT and Northwest and PGT’s Rate Schedule T-1; and
WHEREAS, the Federal Energy Regulatory Commission (“FERC”) has authorized Northwest in Docket No. CP92-79 to, among other things, convert
its gas sales service to Shipper on Northwest’s interstate pipeline transmission system to firm transportation service; and
WHEREAS, the FERC has authorized PGT in Docket No. G-173 50-012 to assign to Shipper a portion of Northwest’s firm transportation service on
PGT formerly provided under Rate Schedule T-1 and to provide such service to Shipper under Part 284 of the FERC’s regulations; and
WHEREAS, Shipper desires to accept said assignment of Northwest firm transportation services on PGT; and
WHEREAS, PGT is willing to transport certain quantities of natural gas for Shipper, on a firm basis, utilizing its pipeline facilities,
NOW, THEREFORE, the parties agree as follows:
I. GOVERNMENTAL AUTHORITY
1.1 This Firm Transportation Service Agreement (“Agreement”) is made pursuant to the regulations of the Federal Energy Regulatory Commission
(FERC) contained in 18 CFR Part 284, as amended from time to time.
1.2 This Agreement is subject to all valid legislation with respect to the subject matters hereof, either state or federal, and to all valid present and
future decisions, orders, rules, regulations and ordinances of all duly constituted governmental authorities having jurisdiction.
II. QUANTITY OF GAS
2.1 The Maximum Daily Quantity of gas, as defined in Paragraph 1 of the Transportation General Terms and Conditions of PGT’s FERC Gas Tariff
First Revised Volume No. I-A, which is the maximum quantity of gas that PGT is required to deliver for Shipper’s account to Shipper’s point(s) of
delivery is set forth in Exhibit A, attached hereto and made a part hereof.
2.2 The maximum quantity of gas which Shipper has a right to deliver to PGT at Shipper’s point(s) of receipt, as identified in Exhibit A, equals the
Maximum Daily Quantity plus an amount for fuel and line losses as set forth in PGT’s Rate Schedule FTS-l of PGT’s FERC Gas Tariff First Revised
Volume No. I-A.
2.3 PGT’s obligation to deliver Shipper’s gas from the Shipper’s point(s) of receipt to the Shipper’s point(s) of delivery is limited to the actual
quantity of gas received by PGT for Shipper’s account at Shipper’s point(s) of receipt less Shipper’s requirement to provide fuel and line losses, as
set forth in PGT’s Rate Schedule FTS-l, up to Shipper’s Maximum Daily Quantity.
III. TERM OF AGREEMENT
3.1 This Agreement shall become effective on November 1, 1993 (Effective Date) and shall continue in full force and effect until thirty (30) years from
the Effective Date (Initial Term). Thereafter, this Agreement shall continue in effect from year to year (Subsequent Term), or a longer term if agreed
to by PGT, unless Shipper gives PGT twelve (12) months prior written notice of Shipper’s desire to terminate this Agreement.
3.2 Neither party may terminate this Agreement during the Initial Term.
IV. POINTS OF RECEIPT AND DELIVERY
4,1 The point(s) of receipt of gas deliveries to PGT is/are as designated in Exhibit A, attached hereto,
4.2 The point(s) of delivery of gas is/are as designated in Exhibit A, attached hereto.
4.3 The delivery pressure, actual average atmospheric pressure, and other pertinent factors applicable to the points of receipt and delivery are also
set forth in Exhibit A
V. OPERATING PROCEDURES
5.1 Shipper shall conform to all of the operating procedures set forth in the Transportation General Terms and Conditions of PGT’s FERC Gas Tariff
First Revised Volume No, I-A
5.2 Shipper shall furnish gas for compressor fuel and line loss as set forth in PGT’s Rate Schedule FTS-l,
VI. RATE(S)
6.1 Shipper shall pay PGT each month all rates applicable to services rendered pursuant to this Agreement in accordance with PGT’s Rate Schedule
FTS-l, or superseding rate schedulers), and PGT’s current Statement of Effective Rates and Charges in PGT’s FERC Gas Tariff First Revised Volume
No. I-A, on file with and subject to the jurisdiction of the FERC. This Agreement in all respects shall be and remains subject to the applicable
provisions of PGT’s Rate Schedule FTS-1, or superseding rate schedulers), and of the Transportation General Terms and Conditions of PGT’s FERC
Gas Tariff First Revised Volume No, I-A on file with the FERC, all of which are by this reference made a part hereof
6.2 PGT shall have the right from time to time to propose, file and cause to be made effective with the FERC such changes in the rates and charges or
service obligations applicable to transportation services pursuant to this Agreement, the rate schedule under which this service is hereunder
provided, or any provisions PGT’s Transportation General Terms and Conditions applicable to such services, Shipper shall have the right to protest
any such changes proposed by PGT and to exercise any other rights that Shipper may have with respect thereto.
VII. MISCELLANEOUS
7.1 This Agreement shall be interpreted to the laws the state of California.
VII. MISCELLANEOUS (continued)
7.2 Unless herein provided to the contrary, any notice called for in this Agreement and/or PGT’s Transportation General Terms and Conditions shall
be in writing and shall be considered as having been given if delivered by facsimile or registered mail, with all postage or charges prepaid, to either
PGT or Shipper at the place designated below. Routine communications, including monthly statements and payment, shall be considered as duly
delivered when received by ordinary mail or facsimile Shipper’s daily nominations shall be considered as duly delivered when received by electronic
data interchange. Unless changed, the addresses of the parties are as follows:
“PGT” PACIFIC GAS TRANSMISSION COMPANY 160 Spear Street Room 1900 San Francisco, California 94105-1 570 Attention: President &
CEO
“SHIPPER” NORTHWEST NATURAL GAS COMPANY 220 N.W. Second Avenue Portland, Oregon 97209 Attention: Senior Vice President,
Operations
7.3 Prior to initiation of service, Shipper shall provide PGT with any information required by the FERC, as well as all information identified in PGT’s
Transportation General Terms and Conditions applicable to service under PGT’s Rate Schedule FTS-1 and this Agreement.
7.4 A waiver by either party of anyone or more defaults by the other hereunder shall not operate as a waiver of any future default or defaults,
whether of a like or of a different character.
7.5 Nothing in this Agreement shall be deemed to create any rights or obligations between the parties hereto after the expiration of the Initial or
Subsequent Term(s) set forth herein, except that expiration of this Agreement shall not relieve either party of the obligation to correct any quantity
imbalances or Shipper of the obligation to pay any amounts due to PGT to the date of expiration.
7.6 Shipper warrants for itself, its successors and assigns, that it will have at the time of delivery of the gas to PGT hereunder good title to such gas
and that all gas delivered to PGT for transportation hereunder is eligible for all requested transportation in interstate commerce under applicable
rules, regulations or orders of the FERC, or other agency having jurisdiction. Shipper will indemnify PGT and save and hold it harmless from all
suits, action, damages (including reasonable attorneys’ fees) and costs connected with regulatory or legal proceedings, arising from the breach of
this warranty.
VII. MISCELLANEOUS (Continued)
7.7 This Agreement constitutes the full agreement between Shipper and PGT and any subsequent changes to this Agreement must be made in
writing by an amendment to this Agreement. This Agreement may only be amended by an instrument in writing executed by both parties hereto.
IN WITNESS WHEREOF the parties hereto have caused this Agreement to be executed as of the day and year first above written.
PACIFIC GAS TRANSMISSION COMPANY
By:
Name: Stephen P. Reynolds
Title: President & CEO
NORTHWEST NATURAL GAS COMPANY
By:
Name: Dwayne L. Foley
Title: Senior Vice President, Operations
EXHIBIT A
To the
FIRM TRANSPORTATION SERVICE AGREEMENT
Dated
Between
PACIFIC GAS TRANSMISSION COMPANY
And
NORTHWEST NATURAL GAS COMPANY
RECEIPT
Maximum Received Quantity
(MMBtu/d)'
Receipt Point(s)
Interconnection of PGT’s system with the system of Alberta Natural Gas
Company Ltd. at the International Boundary in the vicinity of Kingsgate,
British Columbia
3,616
DELIVERY
Maximum Daily Quantity
(MMBtu/d)
Delivery Point(s)
Spokane NPC, WA
3,616
TOTAL
3,616
The total quantity of gas received by PGT from Shipper at receipt point shall not exceed 3.616 MMBtu per day plus the quantities of gas to be
furnished by Shipper for fuel and line loss in accordance with PGT’s Rate Schedule FTS-1 and the Statement of Effective Rates and Charges of
PGT’s FERC Gas Tariff First Revised Volume I-A for service under Rate Schedule FTS-1.
Pursuant 1 to Paragraph 29 of PGT’s Transportation General Terms and Conditions of its FERC Gas Tariff First Revised Volume No. I-A Shipper may
designate other receipt points as “secondary receipt points” such as Stanfield. Oregon, the interconnection of PGT’s system with the system of
Northwest Pipeline Corporation.
(Back To Top)
Section 6: EX-10.J(11) (SERVICE AGREEMENT (100310), DATED
JANUARY 21, 2008)
Exhibit 10j.(11)
Rate Schedule TFŸ 2 Service Agreement
Contract: No. 100310
THIS SERVICE AGREEMENT (Agreement) by and between Northwest Pipeline GP (Transporter) and Northwest Natural Gas Company, (Shipper)
restates the Ser vice Agreement made and entered into on January 12, 1994.
WHEREAS,
A Pursuant to Section 11.4 of the General Terms and Conditions of Transporter’s FERC Gas Tariff, Transporter-and shipper desire to restate the
Service Agreement dated January 12, 1994 (“Contract 100310”) in the format of Northwest’s, currently effective Form of Service Agreement and to
make certain additional non-substantive changes, while preserving all pre-existing, substantive contractual rights.
B The storage redelivery service here under is related to that certain Rate Schedule SGS-2F service agreement (#100502) I dated January 1, 1998.
C Significant events and previous amendments of Contract 100310 reflected in the contract restatement include:
1. Shipper originally entered into Contract #100310 pursuant to the provisions of the approved Joint Offer of Settlement in Docket No.
RP93-5-011 which unbundled the storage and redelivery transportation services, effective April 1, 1994.
2. By Amendment dated May 1, 1999, Shipper’s Contract Demand. Annual contact Quantity and Monthly Billing Quantity were
increased subordinating .3,939 Dths of primary rights south of the Jackson Prairie Receipts Point to reflect Shipper’s request of
additional storage redelivery transportation capacity related to a portion of its storage rights under SGS ~2F Storage Service Agreement
(#100502) dated January 1. 1998.
THEREFORE, in consideration of the premises and mutual covenants set forth herein, Transporter and Shipper agree as follows:
1. Tariff Incorporation. Rate Schedule TF-2’ and the General Terms and Conditions {GT&C} that apply to Rate Schedule TP~2 , as such may be
revised from time to time in Transporter’s FERC Gas Tariff (Tariff ), are incorporated by reference as part of this Agreement, except to the extent that
any previsions thereof may be modified by non-conforming provisions herein.
2. Transportation Service Subject to the terms and conditions that apply to service under this agreement, Transporter agrees to receive, transport;
and deliver natural gas for Shipper, on a firm basis. The Transportation Contract Demand, the Annual Contract Quantity, the Maximum Daily
Quantity at the Primary Receipt Point, and the Maximum Daily Delivery Obligation at each Primary Delivery Point are set forth on Exhibit; A.
3. Transportation Rates. Shipper agrees to pay Transporter for all services rendered under this Agreement at the rates set forth or referenced herein.
The Monthly Billing Quantity for reservation charges is set forth in Exhibit A. The maximum currently effective rates (Recourse Rates) for Rate
Schedule TF-2 set forth in this statement of Rates in the Tariff, as revised From time to time, will apply to service here under unless and to the extent
that discounted Recourse Rates or awarded capacity release rates apply as set forth on Exhibit A or negotiated rates apply as set forth on Exhibit D.
Additionally, if applicable under Section 21 of the GT&C; Shipper agrees to pay Transporter a facility reimbursement charge as set forth on Exhibit
C.
4. Transportation Term. This Agreement becomes effective on the date first set forth above. The primary term begin date for the transportation
service hereunder is set forth on Exhibit A. This Agreement will remain In full force and effect through the primary term end date set forth on Exhibit
A and, if Exhibit A indicates that an evergreen provision applies, through the established evergreen rollover periods therefore until terminated in
accordance with the notice requirements under the applicable evergreen provision.
5. Non-conforming Provisions. All aspects in which this Agreement deviates from the Tariff. If any are set forth as non-conforming provisions on
Exhibit B. If Exhibit B includes any material non-conforming provisions. Transporter will file the Agreement with the Federal Energy Regulatory
Commission (Commission) and the effectiveness of such non-conforming provisions will subject the Commission acceptance of Transporter’s filing
of the non-conforming Agreement.
6. Capacity Release. If Shipper is a temporary capacity release Replacement Shipper, and capacity release conditions, including recall rights, are set
forth on Exhibit A.
7. Exhibit Incorporation. Exhibit A is attached hereto and incorporated as part of this Agreement. If Exhibits B, C and/or D apply, as noted on Exhibit
A to this Agreement, then such Exhibits also are attached hereto and incorporated as part of this Agreement.
8. Regulatory Authorization. Transportation service under this Agreement is authorized pursuant to the commission regulations set forth on Exhibit
A.
9 Superseded Agreements. When this agreement takes effect, it supersedes, cancels and terminates the following agreement(s): Original Firm
Redelivery Transportation Contract dated January 12, 1994 as amended, including Amendment dated May 1, 1998.
IN WITNESS WHEREOF, Transporter and Shipper have executed this on January 21, 2008.
Northwest Natural Gas Company Northwest Pipeline GP
By:
/S/
Name: Randolph Friedman
Title: Director, Gas Supply
By:
/S/
Name: Jane F. Harrison
Title: MANAGER NWP MARKETING SERVICES
EXHIBIT A
(Dated January 21. 2002, Effective January 21. 2008
to the
Rate Schedule TF-2 Service Agreement
(Contract No. 100310)
between Northwest Pipeline
and Northwest Natural Gas Company
SERVICE DETAILS
1. Transportation Contract Demand: 13,406 Dth per day
2. Annual Contracts: Quantity: 281, 242 Dc h
3. Monthly Billing Quantity: 771 Dth
4. Primary Receipt Point:
Point ID Name
235 JACKSON PRAIRIE RECEIPT
Total
Maximum Daily
Quantities {Dth}
13406
13406
5. Primary Delivery Point{s}:
Point ID Name
334 NORTH EUGENE
336 SOUTH EUGENE
467 PORTLAND WEST/SCAPPOOSE
Total
Maximum Daily Delivery
Obligation (Dth)
Delivery
Pressure (psig)
1365
1365
9467
13406
400
400
400
6. Recourse or Discounted Recourse Transportation Rates:
a. Reservation Charge {per Dth of Monthly Billing Quantity} =
Maximum Ease Tariff Rate
b. Volumetric Charge (per Dth):
Maximum Base Tariff Rate
c. Discount Conditions Consistent with Sect ion 3.3 of Schedule TF-2:
Not Applicable
7. Transportation Term;
a. Primary Term Begin Date:
April 01, 1994
b. Primary Term End Date:
March 31, 2008
c. Evergreen Provision
Yes, grandfathered unilateral evergreen under Sect ion 14.3 of Rat. Schedule TF-2
8. Regulatory Authorization: 18 CFR 284.223
9. Additional Exhibits:
Exhibit B Yes, dated January 21, 2008
Exhibit C. NO
Exhibit B
(Dated January 21, 2008, Effective January 21, 2008)
to the
Rate Schedule TF -2 Service Agreement
(Contract No. 100308)
Between Northwest Pipeline GP
And Northwest Natural Gas Company
NON-CONFORMING PROVISIONS
The following provision, as reflected in the May 1, 1999 amendment to Contract # 100310, was accepted as non-conforming by the Commission on
December 3, 1998 in Dock No. GT00-07:
Contract 100310 was modified to condition 3.939 Dths of Shipper’s primary rights through any constraint point south of the Jackson Prairie Point on
Exhibit “A” to have a scheduling priority subordinate to the scheduling priority for any firm shipper with unconditional primary corridor rights
through such constraint.
(Back To Top)
Section 7: EX-10.J(12) (SERVICE AGREEMENT, DATED JANUARY 21,
2008)
Exhibit 10j.(12)
FORM OF RATE SCHEDULE SGS-2F SERVICE AGREEMENT
Rate Schedule 8GS-2F Service Agreement.
Contract No. 100502
THIS SERVICE AGREEMENT (Agreement by and between Northwest Pipeline GP (Transporter} and Northwest Natural Gas Company {Shipper)
restates the Service Agreement made and entered into on January 01, 1998.
A Pursuant to Section 11.4 of the General Terms and Conditions of Transporter’s FERC Gas Tariff, Transporter and Shipper desire to restate the
Service Agreement dated January 01, 1998 (“Contract, 100502”) in tile format of Northwest’s currently effective Form of Service Agreement and to
make certain additional non-substantive changes, while preserving all pre-existing, substantive contractual rights.
B Shipper originally acquired capacity by entering into a binding precedent agreement through the open season for incremental firm storage service
at Jackson Prairie; as authorized by FERC in Docket No. CT06-416.
THEREFORE, in consideration of the premise and mutual covenants set forth herein, Transporter and Shipper agree as follows:
1. Tariff Incorporation. Rate Schedule SGS-2F and the General Terms and Conditions (GT&C) that apply to Rate Schedule SGS-2F, as such may be
revised from time to time in Transporter’s FERC Gas Tariff (Tariff), are incorporated by reference as part of this Agreement, except to the extent that
any provisions thereof may be modified by non-conforming provisions herein.
2. Storage Service. Subject to the terms and conditions that apply to service under this Agreement. Transporter agrees to inject, store and with draw
natural gas for Shipper, on a firm basis. Shipper may request Transporter to withdraw volumes in excess of Shipper’s Contract Demand on a best
efforts basis as provided in Rate Schedule SGS-2F. The Contract Demand and Storage Capacity are set forth on Exhibit A.
3. Storage Rates. Shipper agrees to pay Transporter for all services rendered under this Agreement at the rates set forth or reference herein. The
maximum currently effective rates (Recourse Rates) set forth in the Statement of Rates in the Tariff, as revised from time to time, that apply to the
Rate Schedule SGS-2F customer category identified on Exhibit A will apply to service hereunder unless and to the extent that discounted Recourse
Rates or awarded capacity release rates apply as set forth on Exhibit A or negotiated rates apply as set forth on Exhibit D.
4. Service Term. This Agreement becomes effective on the date first set forth above. The primary term begin date for the storage service hereunder
is set forth on Exhibit A. This agreement will remain in full force and effect through the primary term and date set forth on Exhibit A and, if Exhibit A
indicates that an evergreen provision applies, through the established evergreen rollover periods thereafter until terminated in accordance with the
notice requirement under the applicable evergreen provision.
5. Non-Confirming Provision. All aspects in which this Agreement deviates from the Tariff, if any, are set forth as non-conforming provision on
Exhibit B. If Exhibit B includes any material non-conforming provision, Transporter will file the Agreement with the Federal Energy Regulatory
Commission (Commission) and the effectiveness of such non-conforming provisions will be subject to the Commission acceptance of Transporter’s
filing of the non-conforming Agreement.
6. Capacity Release. If Shipper is a temporary capacity release Replacement Shipper, and capacity release conditions, included recall rights and the
amount of the Releasing Shipper’s Working Gas Quantity released to Shipper for the initial Storage Cycle are set forth on Exhibit A.
7. Exhibit Incorporation. Exhibit A is attached hereto and incorporated as part of this Agreement. If Exhibit B and/or D apply, as noted on Exhibit A
to this Agreement, then such Exhibits also are attached hereto and incorporated as part of this Agreement.
8. Regulatory Authorization. Storage service under this Agreement is authorized pursuant to the Commission regulation set forth on Exhibit A.
9. Superseded Agreements. When this Agreement takes effect, it supersedes, cancels and terminates the following agreement(s): Original Service
Agreement dated January 1, 1998.
IN WITNESS WHEREOF, Transporter and Shipper have executed this Restated Agreement on January 21, 2008.
Northwest Natural Gas Company
Northwest Pipeline GP
By:
Name:
Title:
By:
Name:
Title:
FORM OF RATE SCHEDULE SGS-2F SERVICE AGREEMENT
(Continued)
EXHIBIT A
Dated January 21, 2008, Effective January 21
to the
Rate Schedule SGS-2F Service Agreement
(Contract No. 100502)
Between Northwest Pipeline GP
and Northwest Natural Gas Company
SERVICE DETAILS
1.
Customer Category: Pre-Expansion Shipper
2.
Contract Demand: 46,030 Dth per day
3.
Storage Capacity: 1,120,286 Dth
4.
Recourse or Discounted Recourse Storage Rates:
(Show Not Applicable in Exhibit D is attached.)
5.
a)
Demand Charge (per Dth of Contract Demand):
Maximum Currently Effective Tariff Rate
b)
Capacity Demand Charge (per Dth of Storage Capacity):
Maximum Currently Effective Tariff Rate
c)
Rate Discount Condition Consistent with Section 3.2 of Rate Schedule SFS-2F:
Not Applicable
Service Term:
a.
Primary Term Begin Date:
November 01, 1998
b.
Primary Term End Date:
October 31, 2004
c)
Evergreen Provision:
Yes, grandfathered unilateral evergreen under Section 15.3 of Rate Schedule SGS-2F
6.
Regulatory Authorization: 18 CFR 284.223
7.
Additional Exhibits:
Exhibit B No
Exhibit D No
(Back To Top)
Section 8: EX-10.J(13) (SERVICE AGREEMENT (GAS STORAGE
SERVICE), DATED JANUARY 12, 1994)
Exhibit 10j.(13)
SERVICE AGREEMENT (Liquefaction-Storage Gas Service under Rate Schedule LS-1)
THIS AGREEMENT, made and entered into this 12th day of January 12, 1994, by and between NORTHWEST PIPELINE CORPORATION, a
Delaware corporation, hereinafter called “Transporter”, and NORTHWEST NATURAL GAS COMPANY, hereinafter called “Shipper”.
In consideration of the mutual covenants and agreements as herein set forth, the parties hereto agree as follows:
ARTICLE I-GAS TO BE STORED AND DELIVERED
Subject to the terms, conditions, and limitations hereof and of the applicable Rate Schedule LS-1, Transporter agrees to liquefy, store in liquid
phase, vaporize and deliver to Shipper for transportation, and Shipper agrees to receive from Transporter, up to the following quantities of natural
gas:
A Storage Demand Volume of 60,100 MMBtus,
A Storage Capacity of 478,900 MMBtus.
ARTICLE II-DELIVERY OF GAS
Delivery of natural gas by Transporter to Shipper for transportation shall be at or near the point of vaporization at Transporter’s LNG facilities.
Shipper shall arrange for redelivery transportation to mainline delivery points under Transporter’s transportation rate schedules.
ARTICLE III-APPLICABLE RATE SCHEDULE
Shipper agrees to pay Transporter for all natural gas service rendered under the terms of this Agreement in accordance with Transporter’s Rate
Schedule LS-1 as filed with the Federal Energy Regulatory Commission (“FERC”), and as such rate schedule may be amended or superseded from
time to time. This Agreement shall be subject to the provisions of such rate schedule and the General Terms and Conditions applicable thereto on
file with the FERC and effective from time to time, which by this reference are incorporated herein and made a part hereof.
ARTICLE IV-TERM OF AGREEMENT.
This Agreement shall become effective on the date so designated by the FERC and shall continue in effect for a period continuing through
October 31, 2004 and year to year thereafter at Shipper’s sole option. Shipper may terminate all or any portion of service under this Agreement either
at the expiration of the primary term, or upon any anniversary thereafter by giving at least twelve (12) months in advance. Shipper also shall have
the sole option to enter into a new agreement for all or any portion of the service under this Agreement at or after the end of the primary term of this
Agreement. It is Transporter’s and Shipper’s intent that this term provision provide Shipper with a “contractual right to continue such service” and
to provide Transporter with concurrent pregranted abandonment of any volume that Shipper terminates within the meaning of 18 CFR § 284.221 (d)
(2)(i) as promulgated by Order 636 on May 8, 1992.)
ARTICLE V-CANCELLATION OF PRIOR AGREEMENTS
When this Agreement takes effect, it supersedes, cancels and terminates the following agreements:
Service Agreement (Liquefaction-Storage Gas Service) dated October 1, 1992 between Northwest Pipeline Corporation, “Seller” and Northwest
Natural Gas Company, “Buyer”.
ARTICLE VI-SUCCESSORS AND ASSIGNS
This Agreement shall be binding upon and inure to the benefit of the parties hereto and their respective successors and assigns.
IN WITNESS WHEREOF, the parties hereto have executed this Agreement as of the day and year first above set forth.
“TRANSPORTER” NORTHWEST PIPELINE
CORPORATION
By:
Joe H. Fields
Attorney-In-Fact
ATTEST:
“SHIPPER” NORTHWEST NATURAL GAS COMPANY
By:
By:
Name:
Title:
2
(Back To Top)
Section 9: EX-10.J(14) (SERVICE AGREEMENT (100309), DATED
JANUARY 21, 2008, BETWEEN THE COMPANY)
Exhibit 10j.(14)
Rate Schedule TF-2 Service Agreement
Contract No. 100309
THIS SERVICE AGREEMENT (Agreement) by and between Northwest Pipeline GP (Transporter) and Northwest Natural Gas Company, Inc.
(Shipper) Restates the Service Agreement made and entered into on January 12. 1994.
WHEREAS:
A
Pursuant to Section 11.4 of the General Terms and Conditions of Transporter’s FERC Gas Tariff, Transporter and Shipper desire to restate the
Service Agreement dated January 12, 1994 (“Contract # 100309”) in the format of Northwest’s currently effective Form of Service Agreement
and to make certain additional non-substantive changes, while preserving all pre-existing, substantive contractual rights.
B
The storage redelivery service hereunder is related to that certain Rate Schedule LS-1 service agreement (#100605), dated January 12,1994.
C
Significant events and previous amendments of Contract 100309 reflected in the contract restatement include:
THEREFORE, in consideration of the premises and mutual covenants set forth herein, Transporter and Shipper agree as follows:
Shipper originally entered into Contract #100309 pursuant to the provisions of the approved Joint Offer of Settlement in Docket No. RP93-5011 which unbundled the storage and redelivery transportation services, effective April 1, 1994.
1. Tariff Incorporation. Rate Schedule TF-2 and the General Terms and Conditions (GT&C) that apply to Rate Schedule TF-2, as such may be revised
from time to time in Transporter’s FERC Gas Tariff (Tariff), are incorporated by reference as part of this Agreement, except to the extent that any
provisions thereof may be modified by non-conforming provisions herein.
2. Transportation Service. Subject to the terms and conditions that apply to service under this Agreement, Transporter agrees to receive, transport
and deliver natural gas for Shipper, on a firm basis. The Transportation Contract Demand, the Annual Contract Quantity, the Maximum Daily
Quantity at the Primary Receipt Point, and the Maximum Daily Delivery Obligation at each Primary Delivery Point are set forth on Exhibit A.
3. Transportation Rates. Shipper agrees to pay Transporter for all services rendered under this Agreement at the rates set forth or referenced herein.
The Monthly Billing Quantity for reservation charges is set forth on Exhibit A. The maximum currently effective rates (Recourse Rates) for the Rate
Schedule TP-2 set forth in the Statement of Rates in the Tariff, as revised from time to time, will apply to service hereunder unless and to the extent
that discounted Recourse Rates or awarded capacity release rates apply as set forth on Exhibit A or negotiated rates apply as set forth on Exhibit D.
Additionally, if applicable under Section 21 of the GT&C, Shipper agrees to pay Transporter a facility reimbursement charge as set forth on Exhibit
C.
4. Transportation Term. This Agreement becomes effective on the date first set forth above. The primary term begin date for the transportation
service hereunder is set forth on Exhibit A. This Agreement will remain in full force and effect through the primary term end date set forth on Exhibit
A and, if Exhibit A indicates that an evergreen provision applies, through the established evergreen rollover periods thereafter until terminated in
accordance with the notice requirements under the applicable evergreen provision.
5. Non-Conforming Provisions. All aspects in which the Agreement deviates for the Tariff, if any, are set forth as non-conforming provisions on
Exhibit B. If Exhibit B includes any material non-conforming provisions, Transporter will file the Agreement with the Federal Energy Regulatory
Commission (Commission) and the effectiveness of such non-conforming provisions will be subject to the Commissions acceptance of
Transporter’s filing of the non-conforming Agreement.
6. Capacity Release. If Shipper is a temporary capacity release Replacement Shipper, any capacity release conditions, including recall rights, are set
forth on Exhibit A.
7. Exhibit Incorporation. Exhibit A is attached hereto and incorporated as part of this Agreement. If Exhibits B. C and/or D apply, as noted on Exhibit
A to this Agreement, then such Exhibits also are attached hereto and incorporated as part of this Agreement.
8. Regulatory Authorization. Transportation service under this Agreement is authorized pursuant to the Commission regulations set forth on Exhibit
A.
9. Superseded Agreements. When this Agreement takes effect, it supersedes, cancels and terminates the following agreement(s): Original Service
Agreement (Firm Redelivery Transportation) dated January 12, 1994.
IN WITNESS HEREOF, Transporter and Shipper have executed this on January 12, 2008.
Northwest Natural Gas Company
Northwest Pipeline GF
By:
Name:
Title:
By:
Name:
Title:
EXHIBIT A
(Dated January 21. 2008, Effective January 21, 2008;
to the
Rate Schedule TF-2 Service Agreement
(Contract No. 100309)
between Northwest Pipeline
GP and Northwest Natural Gas Company
SERVICE DETAILS
1. Transportation Contract Demand: 60,000 Dth per day
2. Annual Contract Quantity: 478,900 Dth
3. Monthly Billing Quantity: 1,312 Dth
4. Primary Receipt Pont:
Maximum Daily
Quantities (Dth)
Point ID Name
194 PLYMOUTH LNG RECEIPT
Total
60100
60100
5. Primary Delivery Point(s):
Delivery of natural gas b Transportation to Shipper shall be at or near the points whose location are described in Shipper’s currently effective
Service Agreement (Contract No. 100005) under Rate Schedule TF-1.
6. Recourse or Discounted Recourse Transportation Rates:
a.
Reservation Charge (per Dth of Monthly Billing Quantity):
Maximum Base Tariff Rate
b.
Volumetric Charge (per Dth):
Maximum Base Tariff Rate
c.
Rate Discount Conditions Consistent with Section 3.3 of Rate Schedule TF-2:
Not Applicable
7. Transportation Term:
a.
Primary Term Begin Date:
April 01, 1994
b.
Primary Term End Date:
October 31, 2004
c.
Evergreen Provision:
Yes, grandfathered unilateral evergreen under Section 14.3 of Rate Schedule TP-2
8. Regulatory Authorization: 18 CFR 284.223
9. Additional Exhibits:
Exhibit B No
Exhibit C No
Exhibit D No
(Back To Top)
Section 10: EX-10.J(15) (SERVICE AGREEMENT (100308), DATED
JANUARY 12, 1994)
Exhibit 10j.(15)
Rate Schedule TP-2 Service Agreement
Contract: No. 100308
THIS SERVICE AGREEMENT (Agreement) by and between Northwest Pipeline GP (Transporter) and Northwest Natural Gas Company, Inc.
(Shipper) restates the Service Agreement made and entered into on January 12, 1994.
Whereas:
A Pursuant to Section 11.4 of the General Terms and Conditions of Transporter’s FERC Gas Tariff, Transporter and Shipper desire to restate the
Service Agreement dated January 12, 1994 (Contract 100308) in the format of Northwest’s currently effective Form of Service Agreement and to
make certain additional non-substantive changes, while preserving all pre-existing, substantive contractual rights.
B. The storage redelivery service hereunder is related to that certain Rate Schedule SGS-2F service agreement (100502), dated January 1, 1998.
C. Significant events and previous amendments of Contract 100308 reflected in the contract restatement include:
1. Shipper originally entered into Contract #100308 pursuant to the provisions of the approved Joint Offer of Settlement in Docket No.
RP93-5-011 which unbundled the storage and redelivery transportation services, effective April 1, 1994.
2. By Amendment dated May 1, 1999, Shipper’s Contract Demand, Annual Contract Quantity and Monthly Billing Quantity were
increased subordinating 9,586 Dths of primary rights south of the Jackson prairie Receipt Point to reflect Shipper’s request of additional
storage redelivery transportation capacity related to a portion of its storage rights under SGS-2F Storage Service Agreement {#100502)
dated January 1, 1998.
Therefore, in consideration of the premises and mutual covenants set: forth herein, Transporter and Shipper agree as follows:
1. Tariff Incorporation Rate Schedule TF-2 and the General Terms and Conditions (GT&C) that apply to Rate Schedule TF-2, as such may be revised
from time to time in Transporter’s FERC Gas Tariff (Tariff), are incorporated by reference as part of this Agreement, except to the extent that any
provisions thereof may ne modified by nonconforming provisions herein.
2. Transportation Service. Subject to the terms and conditions that apply to service under this Agreement, Transporter agrees to receive, transport
and deliver natural gas for Shipper, on a firm basis. The Transportation Contract Demand, the Annual Contract Quantity, the maximum Daily
Quantity at the Primary Receipt Point, and the Maximum Daily Delivery Obligation at each Primary Delivery Point are set forth on Exhibit A.
3. Transportation Rates. Shipper agrees to pay Transporter for all services rendered under this Agreement at the rates set forth or referenced herein.
The Monthly Billing Quantity for reservation charges is set forth on Exhibit A. The maximum currently effective rates (Recourse rates) for Rate
Schedule TF-2 set forth in the Statement of Rates in the Tariff, as revised from time to time, will apply to service hereunder unless and to the extent
that discounted Recourse Rates or awarded capacity release rates apply as set forth on Exhibit A or negotiated rates apply as set forth on Exhibit D.
Additionally, if applicable under Section 21 of the GT&C, Shipper agrees to pay Transporter a facility reimbursement charge as set forth on Exhibit
C.
4. Transportation Term. This Agreement becomes effective on the date first set forth above. The primary term begin date for the transportation
service hereunder is set forth on Exhibit A. This Agreement will remain in full force and effect through the primary term end date set forth on Exhibit
A and, if Exhibit A indicates that an evergreen provision applies, through the established evergreen rollover periods thereafter until terminated in
accordance with the notice requirements under the applicable evergreen provision.
5. Non-Confirming Provisions. All aspects in which this Agreement deviates from the Tariff, if any, are set forth as non-conforming provisions on
Exhibit B. If Exhibit B includes any material non-conforming provisions, Transporter will file the Agreement with the Federal Energy Regulatory
Commission (Commission) and the effectiveness of such non-conforming provisions will be subject to the Commission acceptance of Transporter’s
filing of the nonconforming Agreement.
6. Capacity Release. If Shipper is a temporary capacity release Replacement Shipper, any capacity release conditions, including recall rights, are set
forth on Exhibit A.
7. Exhibit incorporation. Exhibit A is attached hereto and incorporated as part of this Agreement. If Exhibit B, C and/or D apply, as noted on Exhibit
A to this Agreement, then such Exhibits also are attached hereto and incorporated as part of this Agreement.
8. Regulatory Authorization. Transportation service under this Agreement is authorized pursuant to the Commission regulations set forth on Exhibit
A.
9. Superseded Agreements. When this Agreement takes effect, it supersedes, cancels and terminates the following agreement(s): Original Firm
Redelivery Transportation Contract dated January 12, 1994 as amended, including Amendment dated May 1, 1999.
IN WITNESS WHEREOF, Transporter and Shipper have executed this on January 21, 2008.
Northwest Natural Gas Company
Northwest Pipeline GP
By:
Name:
Title:
By:
Name:
Title:
EXHIBIT A
(Dated, January 21, 2008, Effective January 21, 2008)
To the
Rate Schedule TF-2 Service Agreement
(Contract No. 100308)
between Northwest Pipeline GP and Northwest Natural Gas Company
SERVICE DETAILS
1. Transportation Contract Demand: 32,624 Dth per day
2. Annual Contract Quantity: 835,046 Dth
3. Monthly Billing Quantity: 2,299 Dth
4. Primary Receipt Point :
Point ID Name
Maximum Daily Quantities (Dth)
235 Jackson Prairie receipt
Total
32,624
32,624
5. Primary Delivery Points
Point ID Name
Maximum Daily Delivery Obligation (Dth)
217 Camas
219 Battleground
301 Washougal
303 Portland Northeast
307 Portland Southeast
312 Molalla
313 Monitor
315 McMinnville Amity
319 Salem
322 Marion
324 Jefferson/Scio
327 Albany
332 Coburg
334 North Eugene
336 South Eugene
339 Creswell
342 Cottage Grove
447 White Salmon/bingen
448 Hood River
467 Portland West/Scappoose
470 Deer Island
474 The Dalles
TOTAL
2000
10
500
8000
5000
100
10
920
921
20
150
2071
100
920
576
100
300
300
1100
7536
8000
1500
40,134
6. Recourse of Discounted Recourse Transportation Rates:
a. Reservation charge (per Dth of Monthly Billing Quantity):
Maximum Base Tariff Rate
b. Volumetric Charge (per Dth):
Maximum Base Tariff Rate
c. Rate Discount Condition Consistent with Section 3.3 of Rate Schedule TF-2:
Not Applicable
7. Transportation Term:
a. Primary Term Begin Date: April 1, 1994
b. Primary Term End Date: October 31, 2004
c. Evergreen Provision: Yes, grandfathered unilateral evergreen under Section 14.3 of Rate Schedule TF-2
8. Regulatory Authorization: 18 CFR 284.223
9. Additional Exhibits:
Exhibit B – Yes, dated January 21, 2008
Exhibit C – No
Exhibit D – No
Delivery Pressure (psig)
300
250
300
400
400
400
150
400
400
150
400
400
400
400
400
150
400
225
225
400
510
150
EXHIBIT B
(Dated January 21, 2008, Effective January 21, 2008)
to the
Rate Schedule TF -2 Service Agreement
(Contract No. 100308)
Between Northwest Pipeline GP
And Northwest Natural Gas Company
NON-CONFORMING PROVISIONS
The following provision, as reflected in the May 1, 1999 amendment to contract 100308, was accepted as non-conforming by the Commission on
December 3, 1999 in Docket No. GT00-07;
Contract 100308 was modified to condition 9,586 Dths of Shipper’s primary rights through any constraint point south of the Jackson Prairie Receipt
Point on Exhibit A to have a scheduling subordinate to the scheduling priority for any firm shipper with unconditional primary corridor rights
through such constraint.
(Back To Top)
Section 11: EX-10.J(16) (SERVICE AGREEMENT , DATED JANUARY 20,
2008)
Exhibit 10j.(16)
SERVICE AGREEMENT
RATE SCHEDULE FS
BETWEEN:
NOVA Gas Transmission Ltd., a body corporate having an office in the City of Calgary, in the Province of Alberta (hereinafter referred
to as “Company”)
-and
Northwest Natural Gas Company, a body corporate having an office in the City of Portland, in the State of Oregon (hereinafter referred
to as “Customer”)
IN CONSIDERATION of the premises and the covenants and agreements herein contained, the parties hereto covenant and agree as follows:
1 Customer acknowledges receipt of a current copy of Company’s Gas Transportation Tariff (the “Tariff’).
2 The terms used herein shall have the same meanings as are ascribed to corresponding terms in the General Terms and Conditions contained in the
Tariff, unless otherwise defined herein.
3 Customer hereby requests, and Company agrees to provide, Service pursuant to Rate Schedule FS in accordance with the attached Schedules of
Service, such Service to commence on the Billing Commencement Date and to terminate, subject to the provisions hereof, on the Service
Termination Date. Company shall include on Customer’s Index of Service for Rate Schedule FS the Service to be provided hereunder and Customer
agrees to
acknowledge such Index of Service from time to time at Company’s request.
4. Customer agrees to pay to Company each Billing Month, for all Service rendered under this Service Agreement, an amount equal to the aggregate
charge for Service described in paragraph 4.5 of Rate Schedule FS.
5. Customer shall:
(a) provide such assurances and information as Company may reasonably require respecting any Service to be provided pursuant to this Rate
Schedule FS including, without limiting the generality of the foregoing, an assurance that necessary arrangements have been made among
Customer, producers of gas for Customer, purchasers of gas from Customer and any other Person relating to such Service, including all gas
purchase, gas sale, operating, processing and common stream arrangements; and
(b) at Company’s request provide Company with an assurance that Customer has provided the Person operating facilities upstream of any
Receipt Point in respect of which Customer has the right to receive Service with all authorizations necessary to enable such Person to provide
Company with all data and information reasonably requested by Company for the purpose of allocating volumes of gas delivered to Company
among Company’s Customers and to bind Customer in respect of all such data and information provided.
If Customer fails to provide such assurances and information forthwith following request by Company, from time to time, Company may at its
option, to be exercised by notice to Customer, suspend the Service to which such assurances and information relate until such time as
Customer provides the assurances and information requested, provided however that any such suspension of Service shall not relieve
Customer from any obligation to pay any
rate, toll, charge or other amount payable to Company.
1 Customer acknowledges that the Facilities have been designed to provide for the transportation of the aggregate gas supply that is forecast to be
received at Receipt Points on the NOVA system, as described each year in NOVA’s Annual Plan, and that interruption and curtailment of Service
may occur if the aggregate gas supply actually received at such Receipt Points is greater than forecast.
2 Every notice, request, demand, statement or bill provided for in Rate Schedule FS, this Service Agreement and the General Terms and Conditions,
or any notice which either Company or Customer may desire to give to the other, shall be in writing and each of them and every payment provided
for shall be directed to the Person to whom given, made or delivered at such Person’s address as follows:
Customer:
Northwest Natural Gas Company
220 N.W. Second Avenue
Portland, Oregon
U.S.A. 97209
Attention: Mr. Randolph Friedman Manager,
Gas Supply
or Attention: (as above)
Fax: (503) 721-2475
Company: NOVA Gas Transmission Ltd.
P.O. Box 2535, Station “M”
801 Seventh Avenue S.W.
Calgary, Alberta TIP 2N6
Attention: Vice President for Customer Fax:
(403) 290-6370
Any notice may be given by personal delivery or by mailing the same, postage pre-paid, in an envelope properly addressed to the Person to
whom the notice is to be given and shall be deemed to be given four (4) business days after the mailing thereof, Saturdays, Sundays and
statutory holidays excepted. Any notice may also be given by pre-paid telegram, fax, or other telecommunication addressed to the Person to
whom such notice is to be given at such Person’s address for notice as set forth above, and any notice so given shall be deemed to have been
given twenty-four (24) hours after transmission of same, Saturdays, Sundays and statutory holidays excepted. Any notice may also be given
by telephone followed immediately by letter, fax, telegram or other telecommunication and any notice so given shall be deemed to have been
given as of the date and time of the telephone notice. In the event of disruption of regular mail every payment shall be personally delivered
and every notice, request, demand, statement or bill shall be given by one of the alternative means set out herein.
8. The terms and conditions of Rate Schedule FS and the General Terms and Conditions are by this reference incorporated into and made a part of
this Service Agreement. Notwithstanding anything contained herein, the terms and conditions hereof shall be subject to the terms and conditions
contained in Rate Schedule FS and the provisions of the General Terms and Conditions.
IN WITNESS WHEREOF the parties hereto have executed this Service Agreement by their proper signing officers duly authorized in that behalf all
as of the 20th day of January, 1995.
Northwest Natural Gas Company
NOVA Gas Transmission Ud.
Per:
Per:
Per:
Per:
(Back To Top)
Section 12: EX-10.J(17) (SERVICE AGREEMENT, DATED NOVEMBER
1, 2004)
Exhibit 10j.(17)
SERVICE AGREEMENT APPLICABLE TO FIRM
TRANSPORTATION SERVICE
UNDER RATE SCHEDULE FS-I
THIS AGREEMENT made and entered into this 1st day of November, 2004, by and between:
TransCanada PipeLines Limited, a body corporate, having an office and carrying on business in the City of Calgary, in the Province of
Alberta, (herein after referred to as “Company”),
-andNorthwest Natural Gas Company, a body corporate, having an office and carrying on business in the City of Portland, in the State of Oregon,
(herein after referred to as “Shipper”)
WHEREAS, Company’s Facilities extend from a point of interconnection with the pipeline facilities of NOVA Gas Transmission Ltd, (NGTL) at the
Alberta-British Columbia border, near the NGTL Coleman delivery point, through southeast British Columbia to a point of interconnection with the
pipeline facilities of PG&E Gas Transmission, Northwest Corporation (PG&E GTNW) at the international border near Kingsgate, British Columbia;
and
WHEREAS, Shipper desires Company, on a firm basis, to transport certain quantities of natural gas through Company’s Facilities from
Alberta/British Columbia border near Coleman, Alberta to British Columbia/U.S. international border near Kingsgate, B.C; and
WHEREAS, Company is willing to transport certain quantities of natural gas for Shipper, on a firm basis;
NOW, THEREFORE, the parties agree as follows:
1 This agreement is subject to all valid legislation with respect to the subject matters hereof, either provincial or federal, and to all valid present and
future decisions, orders, rules, and regulations of all duly constituted governmental authorities having jurisdiction
2 Shipper acknowledges receipt of a current copy of Company’s Gas Transportation Service Documents (GTSD) and Company agrees to provide
Shipper with any amendments thereto
1 The terms used herein shall have the same meanings as are ascribed to corresponding terms in the General Terms and Conditions contained in the
GTSD (General Terms and Conditions).
2 Shipper hereby requests, and Company agrees to provide Service pursuant to Service Schedule F5-1 in accordance with the attached Schedule A
which is incorporated into and forms part of this Agreement, such Service to commence on the Service Availability Date and to terminate, subject to
the provisions hereof, on the Service Termination Date.
3 Shipper agrees to make gas available for Shipper’s share of Company Use Gas, or pay for such gas, pursuant to Section 8.5 of the General Terms
and Conditions
4 Company undertakes to redeliver to Shipper, and Shipper agrees to accept, at the Delivery Point, a quantity of gas equivalent in heat content to
the quantity received by Company from Shipper, expressed in Gigajoules (G/s), at the Receipt Point, after deducting a quantity of gas, if any,
provided by Shipper for Company Use Gas.
5 Shipper agrees to make gas available for Shipper’s share of Company Use Gas, or pay for such gas, pursuant to Section 8.5 of the General Terms
and Conditions.
6 Company undertakes to redeliver to Shipper, and Shipper agrees to accept, at the Delivery Point, a quantity of gas equivalent in heat content to
the quantity received by Company from Shipper, expressed in Gigajoules (GJs), at the Receipt Point, after deducting a quantity of gas, if any,
provided by Shipper for Company Use Gas.
7 In providing service to its existing or new Shippers, Company will use the priority of service specified in Section 8.11 of Company’s General Terms
and Conditions
8 Prior to the Service Availability Date, Shipper shall provide Company with all information identified in Company’s Request for Transportation
Form
9 Shipper agrees to pay, during the period commencing from the Service Availability Date, and in accordance with Schedule FS-I, the General Terms
and Conditions, the Statement of
Effective Rates and Charges and Schedule “A” attached hereto (all as may be amended from time to time), the rates, tolls and charges fixed by
Company firm time to time, in respect of each month, and portion thereof that this Firm Service Agreement and any renewal thereof is in effect
In the event that the Service Availability Date occurs on any day other than the first day of a month, then the demand charge payable for such
month under Sub-section 4 31 of Service Schedule FS-I shall be the product resulting from multiplying the demand charge otherwise payable
for such month by a fraction, the numerator of which shall be the number of days in such month subsequent to and including the Service
Availability Date and the denominator of which is the total number of days in such month
10. Shipper covenants that it will make timely arrangements for upstream and downstream transportation, gas supply and markets and all necessary
governmental authorizations and that it will advise the up stream and downstream transporters of the receipt and delivery points under this
Agreement.
Shipper acknowledges and agrees with Company that Company is relying upon the covenant contained in this clause and agrees that if any
such arrangements or authorizations ale not in place prior to the Service Availability Date, such will not affect the Shipper’s obligation to pay
any demand charge, surcharge, or any other amount payable to Company.
11. If Shipper elects to exercise its option to terminate this Firm Service Agreement as provided for in Section 49 of Service Schedule FS-I, it shall
execute and serve upon Company a termination notice not less than 12 months prior to the Service Termination Date as such date may be extended
from time to time.
12. Shipper agrees not to make demand or bring action against Company for Company’s refusal to transport gas hereunder in the event that any
upstream or downstream transporter fails to receive or deliver gas as contemplated by this agreement provided that such failure was not directly
caused by the negligence of Company.
13. Subject to Section 8.9 of the General Terms and Conditions of this GTSD, any notice or any request, demand, statement, bid or bill (for the
purpose of this paragraph, collectively referred to as “Notice”) provided for by the Service Schedules, the Service Agreements and the General
Terms and Conditions, or any notice which either Shipper or Company may wish to give to the other, shall be in writing and shall be directed as
follows:
Shipper: Northwest Natural Gas Company
220 N.W. Second Avenue
Portland, Oregon 97209
Attention: Mr. Randolph S Friedman
Manager, Gas Supply
E-mail Address: rsf@nwnatural.com
Company: TransCanada PipeLines Limited
450-1” Street S W.
Calgary, Alberta, Canada T2P 5Hl
Attention: Leader, Customer Services
Subject to Section 89 of the General Terms and Conditions of this GTSD, any notice may be given by telecopier or other telecommunication
and any such Notice shall be deemed to be given four (4) hours after transmission Notice may also be given by personal delivery 01 by courier
and any such Notice shall be deemed to be given at the time of delivery. Any Notice may also be given by prepaid mail and any such Notice
shall be deemed to be given four (4) Business Days after mailing In the event regular mail service, courier service, telecopier or other
telecommunication shall be interrupted by a cause beyond the control of the parties hereto, then the party sending the Notice shall utilize any
service that has not been so interrupted to deliver such Notice Each party shall provide Notice to the other of any changes of address for the
purposes hereof Any Notice may also be given by telephone followed immediately by personal delivery, courier, prepaid mail, telecopier, or
other telecommunication, and any such Notice so given shall be deemed to be given as of the date and time of the telephone Notice
14. The terms and conditions of Service Schedule FS-I and the General Terms and Conditions are, by this reference, incorporated into and made part
of this Service Agreement.
15. A waiver by either party of one or more defaults by the other hereunder shall not operate as a waiver o any future default or defaults, whether of
a like or different character
16. This Agreement may be amended only by an instrument in writing executed by both parties hereto
17. Nothing in this Agreement shall be deemed to create any rights or obligations between the penalties hereto after the expiration of the term
hereof, as same may be extended from time to time, except that termination of this Agreement shall not relieve either’ party of the obligation to
correct any gas quantity imbalances or of the obligation to pay any amounts due hereunder
IN WITNESS WHEREOF the parties here to have caused this Agreement to be executed as of the day and year first written above.
Northwest Natural Gas Company
TransCanada PipeLines Limited
(signature)
(signature)
(signature)
(signature)
(signature)
(signature)
(signature)
(signature)
SCHEDULE A to the Firm Service
Agreement Dated November 1,
2004 Between
TransCanada PipeLines Limited
AND
Northwest Natural Gas Company (Shipper)
Receipt Point
Alberta/British Columbia Border near Coleman, Alberta Minimum Pressure Available 4200 kPa
Delivery Point:
British Columbial/U.S. international border near Kingsgate, B C Maximum Pressure Available 5500 kPa
3
Shipper’s Haul Distance
170 7 Km
4
Shipper’s Compression Utilization
170 7 Km
5.
Maximum Day Delivery Quantity (MDDQ)
6
Service Availability Date
November 1, 2004
7
Service Termination Date
October 31, 2016
8
Surcharge Amount
(Winter ) 50,840 GJ/d
(Summer) 50,840 GJ/d
For Special Facilities
For Other Total
Surcharge
9
Schedule A Effective Date
Dollars/Month
Dollars/Month
Dollars/Month
November 1, 2004
Northwest Natural Gas Company
TransCanada PipeLines Limited
(signature)
(signature)
(signature)
(signature)
(signature)
(signature)
(signature)
(signature)
(Back To Top)
Section 13: EX-10.J(18) (SERVICE AGREEMENT, DATED OCTOBER 24,
2008)
Exhibit 10j.(18)
Foothills Pipe Lines Ltd.
Page 1
Service Agreement FT
SERVICE AGREEMENT FIRM TRANSPORTATION SERVICE FOR
TRANSPORTATION OF GAS
This AGREEMENT made October 24, 2008
BETWEEN:
FOOTHLLS PIPE LINES LID, a body corporate having an office and carrying On business in the City of
Calgary in the Province of Alberta (herein referred to as “Company”)
OF THE FIRST PART
NORTHWEST NATURAL GAS COMPANY, a body corporate, having an office and carrying on business in
the City of Portland, in the State of Oregon, (herein referred to as “Shipper”)
OF THE SECOND PART
Foothills Pipe Lines Ltd.
Page 2
Service Agreement FT
SERVICE AGREEMENT
FIRM TRANSPORTATION SERVICE
WHEREAS, Shipper wishes to obtain service relating to the transportation of gas through Company’s transportation system; and
WHEREAS, Company is willing to provide such service;
In consideration of the premises and of the mutual covenants herein contained, the parties do covenant and agree as follows:
Page 3
Service Agreement FT
Foothills Pipe Lines Ltd.
SERVICE AGREEMENT
FIRM TRANSPORTATION SERVICE
ARTICLE 1
Scope of Agreement
1.1 Company agrees to receive from Shipper at each Receipt Point here inspecified, the quantity of gas up to the Maximum Daily Delivery Quantity.
and to transport and deliver to Shipper at each Delivery Point herein specified in the quantity from time to time nominated by Shipper up to the
Maximum Daily Delivery Quantity, and Shipper agrees to accept such gas deliveries from Company, subject to the terms and conditions of this
Service Agreement, Firm Transportation Service.
1.2 If Shipper desires to tender to Company on any day a quantity of gas in excess of Shipper’s Maximum Daily Delivery Quantity for such
Shipper’s Delivery Point for such day, it shall notify Company of such desire, If Company, in its sale judgment, determines that it has the necessary
capacity available to receive and transport all or any part of such excess quantity and make deliveries in respect thereof, and that the performance of
Company’s obligations to other Shippers under their Service Agreements will not be adversely affected thereby, Company may elect to deliver to
Shipper said excess quantity or part thereof, and so notify Shipper.
ARTICLE 2
Rate Schedule and Rates
2.1 This Service Agreement, Firm Transportation Service is subject to the provisions of Rate Schedule FT, Firm Transportation Service and Rate
Schedule OT, Overrun Transportation Service and the General Terms and Conditions of this Gas Transportation Tariff, as they may be amended or
superseded from time to time, which Rate Schedules and General Terms and Conditions of this Gas Transportation Tariff are by this reference
incorporated here in and made a part hereof.
2.2 Shipper shall pay Company for all gas transportation services during the term of this Service Agreement, Firm Transportation Service in
accordance with such Rate Schedules as are filed with the National Energy Board as the same may hereafter be amended or superseded pursuant to
the National Energy Board Act
Page 4
Service Agreement FT
Foothills Pipe Lines Ltd.
ARTICLE 3
Term of Agreement
3.1 The term of this Service Agreement shall be as set forth in Appendix A, which shall be for a minimum term of one year.
3.2 Notwithstanding the provisions of subsection 3.1, if at anytime during the term hereof Foothills PipeLines Ltd. Gas Transportation Tariff with
Shippers transporting U.S. Gas from the Prudhoe Bay area of Alaska through all or any part of the Phase I facilities takes effect, Shipper and
Company agree to forthwith execute a Gas Transportation Tariff identical in form and substance to the aforementioned Gas Transportation Tariff
which shall be identical in form and substance to that attached as Appendix B hereto. Upon execution of such new Gas Transportation Tariff this
Gas Transportation Tariff shall terminate.
ARTICLE 4
Receipt and Delivery Points and Pressures
4.1 All receipts of gas from Shipper shall be at the Receipt Point of such gas, as identified in Appendix A attached to this Service Agreement, Firm
Transportation Service, as the same may be in effect from time to time.
4.2 Should measuring equipment not be provided at either the Receipt Point or the Delivery Point, Shipper shall be responsible for measuring the
gas volume and quality as specified in the General Terms and Conditions of this Gas Transportation Tariff subject to approval by Company.
4.3 The Delivery Points for, gas to be transported hereunder shall be the points set forth in Appendix A attached to this Service Agreement, Finn
Transportation Service as the same may be in effect from time to time
4.4 The delivery pressure of the gas tendered by Shipper to Company for transportation shall be at a pressure sufficient to enter Company’s system
at the Receipt Point, up to that specified for such Receipt Point in Appendix A attached to this Service Agreement, Firm Transportation Service
4.5 The delivery pressure of the gas delivered by Company to Shipper shall be at the pressure available from Company’s system at the Delivery
Point as specified for such Delivery Point in Appendix A attached to this Service Agreement, Firm Transportation Service
Page 5
Service Agreement FT
Foothills Pipe Lines Ltd.
ARTICLE 5
Title and Custody
5.1 Although Company docs not acquire title of the gas transported under this Service Agreement, Firm Transportation Service gas received by
Company from Shipper hereunder shall be deemed to be in the custody and under the control of Company from the time such gas is accepted for
transportation at the Receipt Points until it is delivered to Shipper at the Delivery Points.
ARTICLE 6
Address of Parties
61 Any notice or any request, demand, statement, bid or bill (for the purpose of this subsection, collectively referred to as “Notice”) provided for by
the Rate Schedules, the Service Agreements and the General Terms and Conditions, or any other Notice which either Shipper 01 Company may wish
to give to the other, shall be in writing and shall be directed as follows:
Shipper:
Northwest Natural Gas Company
220 N.W.. Second Avenue
Portland, Oregon 97209
Attention:
Fax:
E-mail:
ML Randolph S. Friedman
503.220 2421
rsf@nwnaturaLcom
Company:
Foothills Pipe Lines ltd
450 First Street S.W.
Calgary, AB
T2P 5H1
Attention:
Fax:
E-mail:
Manager, Western Markets and Interconnects
403.9202341
dan_ronskj’@transcanada.com
6.2 Any Notice may be given by telecopier or other telecommunication and any such Notice shall be deemed to be given four (4) hours after
transmission, Notice may also be given by personal delivery or by courier and any such Notice shall be deemed to be given at the time of delivery
any Notice may also be given by prepaid mail and any such Notice shall be deemed to
Page 6
Service Agreement FT
Foothills Pipe Lines Ltd.
be given four (4) Banking Days after mailing, In the event regular mail service, courier service, telecopier or other telecommunication shall be
interrupted by a cause beyond the control of the parties hereto. then the party sending the Notice shall utilize any service that has not been so
interrupted to deliver such Notice, Each party shall provide Notice to the other of any changes of address for the purposes hereof: Any Notice may
also 00 given by telephone followed immediately by personal delivery, courier, prepaid mail, telecopier, or other telecommunication, and any such
Notice so given shall be deemed to be given as of the date and time of the telephone Notice.
ARTICLE 7
Miscellaneous Provisions
7.1 The Tariff shall be governed by and construed in accordance with the laws of the Province of Alberta and the applicable laws of Canada, and
Company and Customers irrevocably submit to the jurisdiction of the courts of the Province of Alberta for the interpretation and enforcement of the
Tariff
Page 7
Service Agreement FT
Foothills Pipe Lines Ltd.
ARTICLE 8
Agreements Being Superseded
8.1 This agreement supersedes as of November 1, 2008 the following agreements between parties hereto for the transportation of gas by Company
for Shipper:
NWNO·F1 dated June 12,1991
NWNG-F2 dated November 9, 1994
NWNG-F3 dated November 21, 2000
ARTICLE 9
Amendment of Appendix A
9.1 Shipper and Company may at any time and from time to time amend Appendix A to Shipper’s Service Agreement, Finn Transportation Service by
executing a new Appendix A to Shipper’s Service Agreement, Firm Transportation Service which shall be given effect as of the effective date and
shall thereupon be deemed to be incorporated in Shipper’s Service Agreement, Firm Transportation Service.
IN WITNESS WHEREOF the parties hereto have hereunto executed these presents all as of the day. month and year first above written
FOOTHILLS PIPE LINES LTD
Per:
Per:
NORTHWEST NATURAL GAS COMPANY
Per:
Per:
Page 8
Service Agreement FT
Foothills Pipe Lines Ltd.
APPENDIX A to the Service Agreement., Firm
Transportation Service Dated October 24, 2008 Between
Foothills Pipe Lines Ltd.
AND
Northwest Natural Gas Company (Shipper)
NWNG-F5
1. Receipt Point:
Alberta/British Columbia Border near Coleman, Alberta
2. Delivery Point:
British Columbia/US international border near Kingsgate, B.C
3. Shipper’s Haul Distance
1707 Km
4. Applicable Company Zone
Zone8
5. Maximum Day Delivery Quantity (MDDQ)
(Winter) 114,845 GJ/d
(Summer) 96,993 GT/d
6. Service Commencement Date
November 1, 2008
7. Service Termination Date
October 31, 2010
8. Surcharge Amount:
N/A
9. Appendix A Effective Date
November 1, 2008
Northwest Natural Gas Company
Foothills Pipe Lines Ltd.
(signature)
(signature)
(signature)
(signature)
(signature)
(signature)
(signature)
(signature)
Page 9
Service Agreement FT
Foothills Pipe Lines Ltd.
APPENDIX B
FOOTHILLS PIPE LINES LTD
PRO FORMA
GAS TRANSPORTATION TARIFF
Page 10
Service Agreement FT
Foothills Pipe Lines Ltd.
FOOTHILLS PIPE LINES LTD.
PROFORMA GAS
TRANSPORTATION TARIFF
The aforementioned Pro Forma Tariff will be applicable to the transportation of Alaska, Alberta, and Northern Canada source gas through the
completed Foothills Pipe Lines Ltd. system in Canada. This Gas Transportation Tariff is provided under separate cover.
(Back To Top)
Section 14: EX-10.J(19) (AMENDMENT AND RESTATEMENT OF FIRM
TRANSPORTATION SERVICE AGREEMENT)
Exhibit 10j.(19)
Terasen
Gas
TARIFF SUPPLEMENT NO. 1-6
AMENDMENT AND RESTATEMENT OF
FIRM TRANSPORTATION SERVICE AGREEMENT
BETWEEN NORTHWEST NATURAL GAS COMPANY
AND TERASEN GAS INC.
(Formerly Be Gas Utility Ltd.)
Effective November 1, 2004
THIS AMENDMENT AND RESTATEMENT OF FIRM TRANSPORTATION SERVICE
AGREEMENT is dated
with effect as of and from November 1, 2004.
BETWEEN:
TERASEN GAS INC., formerly BC Gas Utility Ltd., a company incorporated under the laws of British Columbia having its registered
office at 1111 West Georgia Street, Vancouver, British Columbia, Canada
(hereinafter called “Terasen Gas”)
OF THE FIRST PART
AND:
NORTHWEST NATURAL GAS COMPANY. (“NW Natural”), a company incorporated under the laws of the State of Oregon having its
registered office at 220 NW Second Avenue, Portland, Oregon, U.SA
(hereinafter called “Shipper”)
OF THE SECOND PART
WHEREAS:
A. Terasen Gas owns and operates the Southern Crossing Pipeline and other transmission assets from the Interconnection with the TransCanada
Pipelines Limited -British Columbia System located at Yahk, British Columbia to the interconnection with Duke Energy Gas Transmission Inc. near
Kingsvale, British Columbia and contracts with Duke for capacity from Kingsvale to Huntingdon, British Columbia.
B. Terasen Gas will use the capacity on its system and the contracted capacity on the Duke System to provide the Shipper with the firm
transportation service from Yahk to Huntingdon.
C. Terasen Gas holds capacity on both the British Columbia and Alberta systems of TransCanada Pipelines Limited and will permanently assign to
Shipper the capacity which is required to match the capacity contracted under this Agreement.
D. The Parties have entered into a Firm Transportation Service Agreement dated January 13, 2003 with effect as of and from November 1, 2004 filed
as Tariff Supplement No. 1-6 with the BCUC and have agreed to enter into this Amendment and Restatement of the Firm Transportation Service
Agreement effective November 1, 2004, subject to the approval of the BCUC.
NOW THEREFORE THIS AGREEMENT WITNESSES THAT in consideration of the terms, conditions and limitations contained herein, the Parties
agree as follows:
ARTICLE 1
DEFINITIONS
1.1 Except where the context requires otherwise the following terms and abbreviations, when used in this Agreement, have the meanings set out
below:
(a) “Affiliate”, when used to indicated a relationship with a Party or Person, means another Person that directly, or indirectly through one or
more intermediates or otherwise, controls, or is controlled by, or is under common control with such Party or Person. A corporation shall be
deemed to be an Affiliate of another corporation if one of them is directly or indirectly controlled by the other or if each of them is directly or
indirectly controlled by the same Party or Person.
(b) “Agreement” means this Amendment and Restatement of the Firm Transportation Service Agreement effective as of and from November 1,
2004, together with any exhibits attached hereto, as amended, supplemented or restated from time to time.
(c) “Authorized Quantity” means the Nomination pursuant to Section 6.2 or the Intra-Day Nomination pursuant to Section 6.3 as either may be
adjusted in accordance with Section 7.5.
(d) “BCUC” means the British Columbia Utilities Commission, or its successor.
(e) “Business Day” means any day except Saturday, Sunday and any Federal banking or statutory holidays observed in the State of Oregon
or the Province of British Columbia or Alberta.
(f) “Commencement Date” means the date defined in Section 3.1.
(g) “Contract Capacity” means the maximum volume of pipeline capacity defined in Section 2.1 (b) that on each Day Terasen Gas is obligated
to make available to Shipper under this Agreement and for which Shipper has agreed to pay Demand Charges specified in Exhibit A attached
hereto and in accordance with the terms of this Agreement.
(h) “Contract Term” has the meaning given that term in Section 3.2.
(i) “Contract Year” means a twelve Month period, beginning on any November 1”, which falls within the Contract Term.
(j) “Cubic Metre” means that quantity of gas, which at a temperature of fifteen degrees (15”) Celsius and at an absolute pressure of kilopascals
101.325 kPa occupies one cubic metre.
(k) “Day” means a period of 24 consecutive hours, beginning and ending at 9:00 a.m. Central Standard Time or such other lime as may be
determined by the Duke General Terms and Conditions.
(I) ‘Dth” means dekatherm which is equal to 1,000,000 Btu.
(m) “Delivery Point” means the point at which Terasen Gas delivers Shipper’s gas to Shipper or for Shipper’s account, which point is the
Huntingdon Delivery Area on the Duke pipeline system.
(n) “Demand Charge” has the meaning given that term in Section 4.2 and as further described in Exhibit A.
(o) “Duke” means Duke Energy Gas Transmission Inc., its successors or assigns, or the natural gas pipeline system of Duke Energy Gas
Transmission Inc., BC Pipeline and Field Services Division, as the subject matter or context requires.
(p) “Duke General Terms and Conditions” means the General Terms and Conditions of Duke approved by the NEB from time to time.
(q) “Export Delivery Area” means those points on the international boundary between Canada and the United States, where the Duke
transmission pipeline interconnects with pipeline facilities located in the United States of America as defined in the Duke General Terms and
Conditions as the “Export Delivery Area” as may be amended from time to time.
(r) “Fuel” has the meaning given that term in Section 5.1.
(s) “GJ” means gigajoule which is equal to one billion (1,000,000,000) Joules.
(t) “Gross Heating Value” means the number of megajoules obtainable from the combustion, at constant pressure, of one Cubic Metre of gas
at a temperature of 15 degrees Celsius, free of all water vapour, and at an absolute pressure of 101.325 kPa, with the products of combustion
cooled to the initial temperature of the gas and all water formed by the combustion reaction condensed to the liqUid state.
(u) “Huntingdon Delivery Area” means the area comprising of the Lower Mainland Delivery Area and Export Delivery Area.
(v) “Imbalance” means the difference, in GJs, between the quantity of natural gas received by Terasen Gas to the Shipper’s account at the
Receipt Point, net of Fuel, and the quantity of natural gas delivered by Terasen Gas to the Shipper’s account at the Delivery Point.
(w) “Intra-Day Nomination” means a nomination for a particular Day that is submitted after the Nomination deadline specified in Section 6.1.
(x) “Joule” means the work done when the point of application of forces of one Newton is displaced at a distance of one metre in the direction
of the force.
(y) “kPa” kilopascals of pressure gauge.
(z) “Kingsgate Daily Absolute High” means the PG&E-GTNW Kingsgate Daily Absolute High Price as set out in Gas Daily’s Daily Price
Survey of gas delivered to PG&E Gas Transmission, Northwest Corporation at Kingsgate, converted to Canadian dollars using the noon
exchange rate as quoted by the Bank of Canada one Business Day prior to gas flow date for each Day. Energy units are converted from Dth to
GJ by application of a conversion factor equal to 1.055056 GJ per Dth.
(aa) “Kingsvale” means the point near Kingsvale, British Columbia, Where the transmission facilities of Terasen Gas interconnect with the
transmission facilities of Duke.
(bb) “Lower Mainland Delivery Area” means the Terasen Gas -Lower Mainland Division delivery area as defined in the Duke General Terms
and Conditions as may be amended from time to time.
(cc) “Month” means a period extending from the beginning of the first Day in a calendar month to the beginning of the first Day in the next
succeeding calendar month or such other period as agreed upon by the Shipper and Terasen Gas.
(dd) “NEB” means National Energy Board or its successor.
(ee) “Nominate” or “Nomination” means Shipper’s notice to Terasen Gas, or its designated agent, respecting the quantities of gas which
Shipper wishes Terasen Gas to deliver to Shipper or for its account at the Delivery Point for the Day, as further described in Section 6.1.
(ff) “Party” means a party to this Agreement and “Parties’ means both of them.
(gg) “Person” means any party except the Parties to this Agreement.
(hh) “Receipt Point” means the points at which Terasen Gas receives gas from Shipper. For the purposes of this Agreement, the Receipt Point
will be at or near the point of Interconnection of the Terasen Gas system with TCPL’s pipeline system at Yahk. The Receipt Point may also be
Kingsvale subject to any restrictions imposed by Duke.
(ii) “Service Interruption” has the meaning given that term in Section 13.1.
(jj) “Sumas Daily Absolute High” means the Northwest Sumas Daily Absolute High Price as set out in Gas Daily’s Daily Price Survey for gas
delivered to Northwest Pipeline Corporation at Sumas, converted to Canadian dollars using the noon exchange rate as quoted by the Bank of
Canada one Business Day prior to gas flow date for each Day. Energy units are converted from Dth to GJ by application of a conversion factor
equal to 1.055056 GJ per Dth.
(kk) “TCPL” means TransCanada Pipelines Limited -British Columbia System, its successors and assigns.
(ll) “Terasen Gas” means Terasen Gas Inc.
(mm) “Terasen Gas Market’ means the design day demand, as it varies from time to time, of the firm natural gas sales and transport customers
along the Southern Crossing Pipeline route and north of Oliver, British Columbia served by Terasen Gas.
(nn) “Yahk” means Yahk. British Columbia, or jf the context requires, means the East Kootenay Exchange near Yahk, British Columbia, where
the existing transmission facilities of Terasen Gas interconnect with the transmission facilities of TCPL.
(oo) “103m3 means 1,000 Cubic Metres of gas as determined on the measurement basis set forth in Article 12.
1.2 Included Words: In this Agreement words importing the singular shall include the plural, and vice versa, and words importing the masculine
gender shall include the feminine gender, and vice versa. and words importing persons shall include firms and corporations, and vice versa.
1.3 Headings and Divisions: The division of this Agreement into articles and sections, the provision of an index and the insertion of headings are
for convenience of reference only and shall not affect the construction or interpretation of the Agreement.
ARTICLE 2
SERVICES
2.1 Nature of Service: Subject to the provisions of this Agreement, Terasen Gas shall provide to Shipper non-recallable daily firm natural gas
transportation service (“Firm Service”) during the term of this Agreement consisting of:
(a) Receipt, at the Receipt Point, of the Authorized Quantity plus Fuel and adjusted for any Imbalance Nominations; and
(b) Delivery to Shipper, or toJlnippers account, at the Delivery Point of a quantity of gas which shall not exceed that quantity of gas which is
thermally equivalent to a maximum volume of 1,317 103m3 per Day (the ·Contract Capacity”).
Firm Service hereunder shall not be subject to curtailment or interruption except as provided in Article 14, or for scheduled maintenance,
repair or modification of the facilities of Terasen Gas and Duke.
2.2 Shipper’s Obligations: On any Day, Shipper shall Nominate for Firm Service a quantity of gas not to exceed the thermal equivalent of the
Contract Capacity, and Shipper shall deliver to Terasen Gas at the Receipt Point a quantity of gas equal to the Authorized Quantity plus Fuel. On
the same Day, Shipper shall receive a quantity of gas which is thermally equivalent to the Authorized Quantity at the Delivery Point. Shipper shall
make all necessary arrangements with transporters upstream of the Receipt Point and downstream of the Delivery Point for such purposes. Any
failure of the Shipper to comply with this provision shall not affect the Shippers obligations to make any payments hereunder.
ARTICLE 3
TERM OF SERVICE
3.1 Commencement Date: Firm Service under this Agreement will commence on November 1, 2004 (the “Commencement Date”).
3.2 Contract Term: This Agreement shall be effective from the date hereof and shall continue in force until sixteen (16) years after the
Commencement Date (the “Contract Term”), ending October 31, 2020 subject to such extension as may be required in accordance with the
provisions of Section 6.6 of this Agreement.
3.3 Early Termination
(a) A Party may terminate this Agreement if at any time the BCUC or the NEB sets rates or terms of service which differ from those set forth in
this Agreement and which are materially adverse to that Party; provided that the Party adversely affected may not terminate this Agreement if
the other Party agrees to compensate the adversely affected Party to the extent of that adverse effect. The Party terminating this Agreement
must give ninety (90) Days’ prior notice in writing to the other Party and the termination will take effect at the end of the Day on the
October 31 following expiry of the ninety (90) Day notice period.
(b) If the Shipper fails to pay the full amount outstanding in respect of any monthly statement for a period of thirty (3D) Days after
suspension of receipt and delivery of gas by Terasen Gas pursuant to Section 9.5, Terasen Gas may, in addition to any other remedy it may
have, terminate this Agreement effective on the date of written notice by the Terasen Gas to the Shipper of such termination.
Terasen Gas Tariff
Supplement Other
(c) If the Shipper
(i) makes an assignment or any general arrangement for the benefit of its creditors;
(ii) files a petition or otherwise commences, authorizes or acquiesces in the commencement of a proceeding or cause under any
bankruptcy or similar law for the protection of creditors or has such petition filed against it and such proceeding remains undismissed
for 30 Days;
(iii) otherwise becomes bankrupt or insolvent (however evidenced); or
(iv) is unable to pay its debts as they fall due;
Terasen Gas may terminate this Agreement forthwith without notice.
(d) Notwithstanding any other provision in this Agreement, if any U.S. federal or state or Canadian federal or provincial law, rule, order,
opinion, enactment or regulation of any governmental authority having jurisdiction over Shipper, or any court renders all or substantially all of
this Agreement illegal or unenforceable, then Shipper shall have the right to terminate this Agreement upon ninety (90) Days written notice to
Terasen Gas. Shipper may not terminate this Agreement if the Parties mutually agree to amend this Agreement to conform with such law, rule,
order, opinion, enactment or regulation provided that such amendment shall be in writing and signed by both Parties.
3.4 Effect of Termination: Upon termination of this Agreement, this Agreement shall cease to have any force or effect, save as to the provisions of
Section 19.5 and any unsatisfied obligations or liabilities of either Party arising prior to the date of such termination, or arising thereafter as a result
of such termination.
ARTICLE 4
DELIVERY CHARGES
4.1 General: From the Commencement Date, Shipper shall pay to Terasen Gas each Month the amounts described below plus any and all taxes
and/or surcharges of any nature payable by or on behalf of Terasen Gas with respect to the natural gas transported under this Agreement.
4.2 Demand Charge: The Demand Charges for Contract Capacity shall be determined as provided for in Exhibit A to this Agreement.
4.3 Commodity Charges: In addition to the Demand Charge, Shipper shall pay commodity charges (“Commodity Charges”) consisting of:
(a) Amounts for tax on fuel gas consumed in operations payable by Terasen Gas under the Motor Fuel Tax Act (British Columbia), or its
successor legislation, allocated to the Shipper for the Month related to the transportation of gas for the Shipper under this Agreement, plus
(b) Any directly incurred Duke commodity tolls from Kingsvale to Huntingdon, including any motor fuel taxes, surcharges and/or adjustments
thereof, related to the firm transportation of gas for the Shipper under this Agreement.
ARTICLE 5
5.1 Nomination of Fuel: In addition to the gas that Shipper desires to be delivered for the Shipper’s account at the Delivery Point, the Shipper shall
nominate for and tender or cause to be tendered to Terasen Gas at the Receipt Point, a quantity of gas based upon an applicable monthly fuel
percentage. The fuel percentage shall be established by Terasen Gas, and calculated by dividing Terasen Gas’ reasonable estimate of compressor
fuel, line losses and unaccounted for gas, and the required operational variance in linepack for the Month (collectively, the “Fuel”) by the total
estimated Nominations for the Month (“the Fuel Percentage”).
5.2 Procedure for Fuel: Terasen Gas or its agent will advise the Shipper by fax, or other such method agreed to by Terasen Gas and Shipper, of the
applicable Fuel Percentage by no later than the twenty-fifth (25th) day of the Month for the following Month, which amount shall be expressed as a
percentage of the quantity of gas to be delivered at the Delivery Point in that Month. In the absence of such notification, the Shipper shall use the
monthly Fuel Percentage communicated by Terasen Gas for the preceding Month. In the following Month’s estimate of Fuel, Terasen Gas shall
provide an adjustment based on any differences between actual Fuel in the preceding Month and the Fuel provided by the Shipper for that Month,
as determined by Terasen Gas.
(a) The Fuel calculation mechanism as it relates to the Nomination and scheduling process will be (1 • Fuel Percentage) multiplied by the
receipt quantity =delivery quantity.
(b) The transportation priority for Fuel will be the same as the level of service as the transactions to which it applies.
5.3 Units: The Fuel will be calculated on an energy basis. The results of the Fuel reimbursement calculation for the Nomination and scheduling
process will be rounded to the nearest GJ.
Terasen Gas Tariff
Supplement -Other
ARTICLE 6
NOMINATIONS
6.1 Shipper’s Nominations: Shipper shall advise Terasen Gas, or its designated agent, at the times noted below, of the quantity of gas which it
requests Terasen Gas to deliver at the Delivery Point for the Day. Such advice, hereinafter called a Nomination, shall be provided to Terasen Gas or
its agent by facsimile or other such method agreed to by Terasen Gas and Shipper for the purpose of scheduling daily transportation of natural gas
under this Agreement. Shipper must advise Terasen Gas or its agent of Shipper’s Nomination not later than 10:30 Gentral Clock time on the Day
prior to the Day in which Terasen Gas is requested to deliver such gas.
A Nomination shall include the daily quantity requested to be transported (expressed in GJ), the beginning and end dates and the appropriate
upstream and downstream shippers. In the event that more than one Nomination is submitted, the Nomination shall include an indication of
priority. The total daily quantity requested to be transported shall not exceed the quantity of gas that is thermally equivalent to the Contract
Capacity.
All Nominations received by Terasen Gas or its agent shall remain in effect, whether or not deliveries are made, until an amended Nomination
is received by Terasen Gas or its agent pursuant to this Section 6.1.
6.2 Authorized Quantity: Terasen Gas, or its agent, shall confirm the Nomination as the Authorized Quantity to the Shipper, provided that Shipper
has arranged for delivery of the Nomination plus Fuel at the Receipt Point and that Shipper has arranged for the Nomination to be transported from
the Delivery Point. If the quantity of gas which Shipper has arranged for delivery at the Receipt Point is less than the Nomination plus Fuel or the
quantity of gas which Shipper has arranged for transportation from the Delivery Point is less than the Nomination, then the Authorized Quantity
shall be adjusted to the lesser of those two quantities taking into consideration Fuel requirements.
The confirmation shall be provided to Shipper not more than one hour after Duke confirms scheduled quantities to its shippers for each
nomination cycle.
6.3 Intra-Day Nominations: Shipper shall be entitled to make Intra-Day Nominations to the extent that Intra-Day Nominations become effective on
the pipeline systems of Duke and TCPL, subject to the operations of Terasen Gas, or its agent, being able to effectively’ accommodate the Intra-Day
Nomination. Intra-Day Nominations generally shall be in accord with Intra-Day Nominations available to shippers on the Duke system including the
effective time. The Intra-Day Nomination deadline shall be one hour prior to the deadline on the Duke system for the corresponding intra-day cycle.
Terasen Gas, or its agent, shall confirm the Intra-Day Nomination as the Authorized Quantity (adjusted in accordance with Section 6.2) not more
than one hour after Duke confirms scheduled quantities to its shippers as Intra-Day Nominations. Intra-Day Nominations shall apply only for the
specific Day nominated.
6.4 Elapsed Pro-Rata: During the Intra-Day scheduling process, Intra-Day Nominations will be subject to that portion of the scheduled quantity that
would have theoretically flowed up to the effective time of the Intra-Day Nomination being confirmed, based upon a cumulative uniform hourly
quantity for each Nomination cycle affected (Elapsed ProRata”).
6.5 Communications: All Nominations and confirmations shall be delivered to the Parties as directed below or otherwise in writing:
Terasen Gas Inc. 16705
Fraser Highway Surrey,
B.C. V3S 2X7
Attention: Marketing Services Representative
Telephone: (604) 592-7788
Facsimile: (604) 648-8751 or (403) 206-7293
Northwest Natural Gas Company 220
NW Second Avenue Portland, OR
97209
Attention: Gas Supply Department
Telephone: (503) 226-4211
Facsimile: (503) 220-2421
6.6 Term Extension: Notwithstanding the provisions of this Agreement, in the event there is a cumulative Imbalance (“Cumulative Imbalance”)
between receipts and deliveries at the end of the Contract Term, the Contract Term of the Agreement will be extended by extending deliveries or
receipts, as applicable, until such Cumulative Imbalance is eliminated or by such method as is then mutually agreed upon by the Parties hereto.
ARTICLE 7
IMBALANCES
7.1 Balancing: The Shipper shall use all reasonable efforts to at all times maintain balance, based on the best available information, between the gas
received to the Shipper’s account at the Receipt Point, net of Fuel, and the gas delivered by the Terasen Gas from the Shipper’s account at the
Delivery Point. Any difference between gas received and delivered on a given Day, will be considered an Imbalance for the Day. In the event the
gas received exceeds that delivered, then the Imbalance will be considered a pack (“Pack Imbalance”). In the event the gas delivered exceeds that
received then the Imbalance will be considered a draft (“Draft Imbalance”).
7.2 Tracking Imbalances: In the event that Terasen Gas determines that there is a Pack Imbalance or Draft Imbalance on a Day, that amount will be
accumulated with the Pack Imbalances and Draft Imbalances for previous Days and tracked as a Cumulative Imbalance.
7.3 Communication of Imbalances: Terasen Gas or its agent will communicate any Pack Imbalance, Draft Imbalance, and the Cumulative Imbalance
each Day together with the Authorized Quantity as set out in Section 6.2.
7.4 Imbalance Remedy: If Terasen Gas determines that a Shipper has a Pack Imbalance or Draft Imbalance, Terasen Gas at any point may request that
the Shipper remedy, in whole or in part, such Imbalance within the next Day or other such timeframe that is agreed on by the Parties. Shipper will
reduce Pack Imbalances by placing requests with Terasen Gas for Imbalance return (“Imbalance Return”) and will reduce Draft Imbalances by
placing requests for Imbalance payback (“Imbalance Payback”). These requests shall be considered Imbalance Nominations and are Subject to the
Nomination rules and deadlines pursuant to Article 6. Imbalance Nominations that are Shipper’s response to Terasen Gas’ request that the Shipper
remedy an Imbalance under this Section 7.4 shall be of higher priority than all other Nominations. The Cumulative Imbalance will be increased or
decreased accordingly by the Imbalance Paybacks and Imbalance Returns authorized for the Day.
7.5 Adjustment of Receipts and Deliveries: In the event the Shipper does not submit Nominations to remedy an Imbalance as requested by Terasen
Gas pursuant to Section 7.4, Terasen Gas has the right to adjust the receipts and deliveries of Shipper’s gas to the extent needed to remedy the
Imbalance.
7.6 Penalties: If Terasen Gas has requested that Shipper remedy any Imbalance pursuant to Section 7.4, and the Shipper fails to comply, then to the
extent that Terasen Gas was not successful in remedying the Imbalance, the Shipper shall pay to Terasen Gas a fee equal to the Imbalance amount
not remedied expressed in GJs, multiplied by the greater of the Sumas Daily Absolute High plus 10% or the Kingsgate Daily Absolute High plus
10% for the Day that the Imbalance was to be remedied. In the event the Shipper is assessed a penalty, the Shipper’s Cumulative Imbalance will be
adjusted accordingly by the amount of gas on which the Shipper was assessed the penalty.
7.7 Error on Terasen Gas’ Part: If an Imbalance is created as a result of an error on the part of the Terasen Gas or its designated agent during the
scheduling process, then Terasen Gas must eliminate the Imbalance the next Day unless otherwise agreed to by the Parties. If the Imbalance caused
by the Terasen Gas’ error is not eliminated the next Day, then Terasen Gas shall pay to the Shipper a fee equal to the amount of the unresolved
Imbalance multiplied by the greater of the Sumas Daily Absolute High plus 10% or the Kingsgate Daily Absolute High plus 10% for the Day the
imbalance was created. Payment of this penalty would result in the Cumulative Imbalance amount being adjusted accordingly by the amount of gas
on which the Terasen Gas was assessed a penalty.
7.8 Potential for Future Changes to Balancing Requirements: The Parties recognize that Duke may obtain NEB approval for changes to the balancing
provisions set out in the Duke General Tenns and Conditions that may result in balancing penalties beyond those currently provided for in the
current Duke General Tenns and Conditions. In this event, Terasen Gas reserves the right to recover any such penalty costs assessed to Terasen
Gas as a result of the Shipper failing to take delivery of the Authorized Quantity for a Day.
In the event that the Southern Crossing Pipeline system is expanded and the balancing requirements for shippers transporting gas on
the expansion capacity are different than the balancing requirements described under this section 7, the balancing requirements set out in this
Section 7 shall be modified to align with the balancing provisions for the expansion capacity.
ARTICLE 8
RECEIPT AND DELIVERY OF GAS
8.1 Delivery Obligation: Terasen Gas’ obligation to deliver gas to Shipper on any Day at the Delivery Point shall be subject to:
(a) Terasen Gas having authorized the transportation of gas on that Day pursuant to a Nomination; and
(b) Shipper delivering to Terasen Gas at the Receipt Point the Authorized Quantity plus Fuel and adjusted for any Imbalance Nominations.
8.2 Receipt Point Pressure: Shipper shall deliver to Terasen Gas the Authorized Quantity at such pressure at the Receipt Point as is in accordance
with the General Terms and Conditions of the applicable interconnecting pipeline, Le. TCPL or Duke or both as the circumstances require.
8.3 Energy Conversion: From time to time Terasen Gas, or its agent, shall notify Shipper of the Gross Heating Value to be used for calculating the
quantity of gas in GJs which is equivalent to Shipper’s Contract Capacity. This quantity of gas shall be used in Teresen Gas’ or its agent’s
scheduling process.
8.4 Commingled: Terasen Gas shall be deemed to be in possession of, and control of, and responsible for all gas received at the Receipt Point until
such gas is delivered by it at the Delivery Point. Terasen Gas shall have the right to commingle such gas with other gas in the Terasen Gas facilities
or in the facilities of others transporting the gas.
Terasen Gas Tariff
Supplement -Other
ARTICLE 9
STATEMENT AND PAYMENTS
9.1 Billing Period: Commencing in the Month following the Month in which the Commencement Date occurs, Terasen Gas shall, on or before the
twenty-first (21st) day of each Month, deliver to Shipper a statement of the amount payable by Shipper for all services provided by Terasen Gas to
Shipper during the preceding Month.
9.2 Payment: All payments shall be made in readily available Canadian Funds to Terasen Gas or its designate on or before the last Business Day of
the Month following the Month in which services were provided unless Shipper receives a statement from Terasen Gas after the twenty-first (21st)
day of the Month following the Month in which services were provided, in which case payment shall become due on or before the tenth (10th)
calendar day after which the Shipper receives a statement from Terasen Gas. If the payment due date falls on a day other than a Business Day,
payment will be due on the closest following Business Day.
9.3 Failure to Pay: If the Shipper fails or neglects to make any payment required under this Agreement to Terasen Gas when due, interest on the
outstanding amount will accrue, at the annual rate of interest declared by the chartered bank in Canada principally used by Terasen Gas, for loans in
Canadian dollars to its most creditworthy commercial borrowers payable on demand and commonly referred to as its ‘prime rate”, plus:
(a) 2% from the date when such payment was due for the first thirty (30) Days that such payment remains unpaid and 5% thereafter until the
same is paid when the Shipper has not, during the immediately preceding six (6) Month period, failed to make any payment when due
hereunder; or
(b) 5% from the date when such payment was due to and including the date the same is paid when the Shipper has, during the immediately
preceding six (6) Month period, failed to make any payment when due hereunder.
9.4 Billing Disputes: If the Shipper disputes any portion of any payment billed to Shipper by Terasen Gas under this Agreement, Shipper will
nonetheless pay to Terasen Gas that portion of the amount which is not in dispute on or before the specified due date. Shipper and Terasen Gas will
cooperate to resolve any billing disputes in an expeditious and timely manner. In the event that the amount in dispute is subsequently determined to
have been properly due and owing, Shipper will forthwith pay to Terasen Gas the disputed amount in full, together with interest accrued thereon
from the due date at the rate specified in Section 9.3.
9.5 Service Suspension: Terasen Gas may cease to receive and deliver gas to Shipper if Shipper fails to pay Shipper all monies due and owing in
accordance with provisions of this Article 9.
9.6 Examination of Records: Each of Terasen Gas and the Shipper shall have the right. at its own expense, at reasonable times and upon reasonable
notice to examine, audit, and to obtain copies of the books, records and charts of the other Party, only to the extent reasonably necessary to verify
accuracy of any statement, charge, payment. computation, or any claim for underpayment or overpayment. This right to examine, audit, and to
obtain copies shall not be available with respect to proprietary information not directly relevant to transactions under this Agreement. All invoices
and billings shall be conclusively presumed final and accurate and all associated claims for under or over payments shall be deemed waived unless
such invoices or billings are objected to in writing, with adequate explanation and/or documentation, within two (2) years after the month of
transportation provided under this Agreement All retroactive adjustments under this Article 9 shall be paid in full by the Party owing payment
within thirty (30) days of notice and substantiation of such inaccuracy,
ARTICLE 10
WARRANTY OF OWNERSHIP OR CONTROL AND ELIGIBILITY FOR TRANSPORTATION
10.1 Shipper’s Warranty: Shipper warrants that all gas delivered to Terasen Gas for transportation under this Agreement shall be owned by or
validly under the control of Shipper or other Persons delivering the gas on the Shipper’s behalf to Terasen Gas. Shipper will indemnify Terasen Gas
and save it, its directors, officers, agents and employees and its successors and assigns, harmless from all suits, actions, damages, costs, losses,
expenses (including reasonable legal fees) and regulatory proceedings, arising from breach of this warranty or any misrepresentation relating
thereto.
ARTICLE 11
QUALITY OF GAS
11.1 Receipt Point The gas delivered by Shipper to Terasen Gas at the Receipt Point for transportation to the Delivery Point shall meet the quality
specifications contained in Duke’s General Terms and Conditions, as amended from time to time, provided that such specifications are no more
stringent than the specifications of TCPL
11.2 Delivery Point: The gas Terasen Gas delivers to Shipper or for Shipper’s account under this Agreement shall have the constituent parts that
result from the commingling of gas from various sources in the facilities used to transport gas for Terasen Gas and shall meet Duke’s specifications.
11.3 Non Conforming Gas: If the gas delivered to Terasen Gas for transportation under this Agreement shall fail at any time to conform to any of the
specifications set forth in this Article 11, then Terasen Gas or its agent shall notify Shipper of such deficiency and may, at its option, refuse to
accept such gas pending Shipper remedying such failure to conform to the required quality specifications. However, any such refusal shall not
relieve Shipper from any obligation to pay its Demand Charge, or any other charge payable to Terasen Gas under this Agreement.
ARTICLE 12
MEASUREMENT
12.1 Volumetric Unit Except as otherwise specified in this Agreement, the unit of volume of gas for all purposes hereunder shall be one thousand
(1,000) Cubic Metres (103m3).
12.2 Energy Unit The unit of energy of gas for all purposes hereunder shall be one GJ. The volume of gas transported by Terasen Gas for each Day
shall be determined by dividing the quantity of energy transported by the average Gross Heating Value of the gas over the same period. The Gross
Heating Value shall be determined at reasonable intervals by the Party operating the measuring equipment
12.3 Measuring Equipment The volume of gas transported under this Agreement shall be determined by means of a metering device approved in
accordance with standard industry practices.
12.4 Measuring Procedures: All fundamental constants, observations, records, and procedures involved in determining and/or verifying the
quantity and other characteristics of gas delivered will, unless otherwise specified in this Agreement, be in accordance with the measurement
standards recognized as standard industry practices.
12.5 Preservation of Data: Terasen Gas shall preserve or cause to be preserved all measurement test data, measurement charts, and other similar
records pertaining to the Firm Service provided by Terasen Gas under this Agreement for a period of two (2) years from the date of their creation.
Unless otherwise challenged by a Party within that period, all such data, charts and records shall be deemed to be final and conclusive.
12.6 Rounding: The volume of gas shall be specified in 103 m3 to one decimal place and energy shall be specified in GJs rounded to the nearest GJ.
Terasen Gas Tariff
Supplement -Other
ARTICLE 13
CONTRACT DEMAND CREDITS
13.1 Service Interruption: If on any Day and for any reason, Terasen Gas is unable to take receipt of gas which was Nominated by Shipper at the
Receipt Point, or deliver gas at the Delivery Point which was Nominated by Shipper (hereafter a Service Interruption” and such volume referred to as
the “Interrupted Volume”) then, subject to paragraphs 13.2 (a) and (b), Shipper will be entitled to a credit on its next monthly bill, for that Service
Interruption. The credit shall be equal to the Demand Charge in effect during the Service Interruption, and multiplied by the Interrupted Volume.
132 Demand Charge Obligation: Shipper will not be entitled to receive a credit pursuant to Section 13.1:
(a) for any period of time during a Service Interruption when Shipper is unable to deliver gas to Terasen Gas at the Receipt Point or accept
delivery of gas at the Delivery Point, and
(b) for any period of time during a Service Interruption when Terasen Gas was unable to receive gas from or on behalf of Shipper at the
Receipt Point due to the scheduled maintenance, repair or modification of the facilities of Terasen Gas or any part thereof including
connecting facilities such as Duke or others upon which Terasen Gas may be dependent upon to effect delivery under this Agreement. To the
extent practicable, Terasen Gas will use commercially reasonable efforts to cause repairs or maintenance to be made to minimize interruption or
curtailment of transportation service to Shipper under this Agreement, and to restore service as quickly as possible.
13.3 Make-Up Gas: If Terasen Gas and Shipper agree, Terasen Gas may allow Shipper to deliver to Terasen Gas for receipt at the Receipt Point
additional volumes of gas as makeup gas for that quantity which Terasen Gas was unable to receive during a Service Interruption. In such event
Shipper will not be entitled to receive a credit in respect of any such gas so received by Terasen Gas.
(Back To Top)
Section 15: EX-10.O (FORM OF CHANGE IN CONTROL SEVERANCE
AGREEMENT)
Exhibit 10.(o)
, 2008
Re: Change in Control Severance Agreement
Dear
:
Northwest Natural Gas Company, an Oregon corporation (the “Company”), considers the establishment and maintenance of a sound and
vital management to be essential to protecting and enhancing the best interests of the Company. In this connection, the Company recognizes that,
as is the case with many publicly held corporations, the possibility of a change in control may exist and that such possibility, and the uncertainty
and questions which it may raise among management, may result in the departure or distraction of management personnel to the detriment of the
Company, its customers and its shareholders. Accordingly, the Board of Directors of the Company (the “Board”) has determined that appropriate
steps should be taken to reinforce and encourage the continued attention and dedication of members of the Company’s management to their
assigned duties without distraction in circumstances arising from the possibility of a change in control of the Company.
In order to induce you to remain in the employ of the Company, this letter agreement, which has been approved by the Board, sets forth
severance benefits which the Company agrees will be provided to you in the event your employment with the Company is terminated in connection
with a Change in Control (as defined in Section 3 hereof) under the circumstances described below. The Company and you have entered into a prior
letter agreement regarding change in control severance benefits dated December 14, 2006. Upon your signature of this letter agreement, the prior
agreement shall be amended and restated in its entirety in the form of this agreement.
1. Agreement to Provide Services; Right to Terminate.
(i) Except as otherwise provided in paragraph (ii) below, the Company or you may terminate your employment at any time,
subject to the Company’s providing the benefits hereinafter specified in accordance with the terms hereof.
(ii) In the event of a Potential Change in Control (as defined in Section 3 hereof), you agree that you will not leave the employ
of the Company (other than as a result of Disability, as such term is hereinafter defined) and will render the services contemplated in the
Page 2
recitals to this Agreement until the earliest of (a) a date which is 270 days from the occurrence of such Potential Change in Control, or (b) a
termination of your employment pursuant to which you become entitled under this Agreement to receive the benefits provided in Section 5(iii)
below.
2. Term of Agreement. This Agreement shall commence on the date hereof and shall continue in effect until December 31, 2009; provided,
however, that commencing on January 1, 2010 and each January 1 thereafter, the term of this Agreement shall automatically be extended for one
additional year unless at least 90 days prior to such January 1 date, the Company or you shall have given notice that this Agreement shall not be
extended (provided that no such notice may be given by the Company during the pendency of a Potential Change in Control); and provided,
further, that this Agreement shall continue in effect for a period of twenty-four (24) months beyond the term provided herein if a Change in Control
shall have occurred during such term. Notwithstanding anything in this Section 2 to the contrary, this Agreement shall terminate automatically if
you or the Company terminate your employment prior to the earlier of Shareholder Approval (as defined in Section 3 hereof), if applicable, or the
Change in Control. In addition, the Company may terminate this Agreement during your employment if, prior to the earlier of Shareholder Approval,
if applicable, or the Change in Control, you cease to hold your current position with the Company, except by reason of a promotion.
3. Change in Control; Potential Change in Control; Shareholder Approval; Person.
(i) For purposes of this Agreement, a “Change in Control” shall mean the occurrence of any of the following events:
(A) The consummation of:
(1) any consolidation, merger or plan of share exchange involving the Company (a “Merger”) as a result of which the
holders of outstanding securities of the Company ordinarily having the right to vote for the election of directors (“Voting
Securities”) immediately prior to the Merger do not continue to hold at least 50% of the combined voting power of the
outstanding Voting Securities of the surviving corporation or a parent corporation of the surviving corporation immediately
after the Merger, disregarding any Voting Securities issued to or retained by such holders in respect of securities of any other
party to the Merger; or
(2) any sale, lease, exchange or other transfer (in one transaction or a series of related transactions) of all, or substantially
all, the assets of the Company;
(B) At any time during a period of two consecutive years, individuals who at the beginning of such period constituted the Board
(“Incumbent Directors”) shall cease
Page 3
for any reason to constitute at least a majority thereof; provided, however, that the term “Incumbent Director” shall also include each
new director elected during such two-year period whose nomination or election was approved by two-thirds of the Incumbent
Directors then in office; or
(C) Any Person (as hereinafter defined) shall, as a result of a tender or exchange offer, open market purchases or privately
negotiated purchases from anyone other than the Company, have become the beneficial owner (within the meaning of Rule 13d-3
under the Securities Exchange Act of 1934), directly or indirectly, of Voting Securities representing twenty percent (20%) or more of the
combined voting power of the then outstanding Voting Securities.
Notwithstanding anything in the foregoing to the contrary, unless otherwise determined by the Board, no Change in Control shall be deemed to
have occurred for purposes of this Agreement if (1) you acquire (other than on the same basis as all other holders of shares of Common Stock of the
Company) an equity interest in an entity that acquires the Company in a Change in Control otherwise described under subparagraph (A) above, or
(2) you are part of a group that constitutes a Person which becomes a beneficial owner of Voting Securities in a transaction that otherwise would
have resulted in a Change in Control under subparagraph (C) above.
(ii) For purposes of this Agreement, a “Potential Change in Control” shall be deemed to have occurred if:
(A) the Company enters into an agreement, the consummation of which would result in the occurrence of a Change in Control;
(B) any Person (including the Company) publicly announces an intention to take or to consider taking actions which if
consummated would constitute a Change in Control; or
(C) the Board adopts a resolution to the effect that, for purposes of this Agreement, a Potential Change in Control has occurred.
(iii) For purposes of this Agreement, “Shareholder Approval” shall be deemed to have occurred if the shareholders of the
Company approve an agreement entered into by the Company, the consummation of which would result in the occurrence of a Change in Control.
(iv) For purposes of this Agreement, the term “Person” shall mean and include any individual, corporation, partnership, group,
association or other “person,” as such term is used in Section 14(d) of the Securities Exchange Act of 1934 (the “Exchange Act”), other than the
Company or any employee benefit plan sponsored by the Company.
4. Termination Following Shareholder Approval or Change in Control. If a Change in Control occurs, you shall be entitled to the benefits
provided in Section 5(iii) hereof in the event that (x) a Date of Termination (as defined in Section 4(v) below) of your employment with
Page 4
the Company occurred or occurs after the earlier of Shareholder Approval, if applicable, or the Change in Control and no later than twenty-four
(24) months after the Change in Control, or (y) your employment with the Company is terminated by you for Good Reason (as defined below) based
on an event occurring concurrent with or subsequent to the earlier of Shareholder Approval, if applicable, or the Change in Control and your Notice
of Termination (as defined in Section 4(iv) below) in connection therewith shall have been given no later than twenty-four (24) months after the
Change in Control; provided, however, that if any such termination is (a) because of your death, (b) by the Company for Cause (as defined below)
or Disability, or (c) by you other than for Good Reason based on an event occurring concurrent with or subsequent to the earlier of Shareholder
Approval, if applicable, or the Change in Control, then you shall not be entitled to the benefits provided in Section 5(iii) hereof.
(i) Disability. Termination by the Company of your employment based on “Disability” shall mean termination because of your
absence from your duties with the Company on a full-time basis for one hundred eighty (180) consecutive days as a result of your incapacity due to
physical or mental illness, unless within thirty (30) days after Notice of Termination is given to you following such absence you shall have returned
to the full-time performance of your duties.
(ii) Cause. Termination by the Company of your employment for “Cause” shall mean termination upon (a) the willful and
continued failure by you to perform substantially your assigned duties with the Company (other than any such failure resulting from your
incapacity due to physical or mental illness) after a demand for substantial performance is delivered to you by the Chairman of the Board or
President of the Company which specifically identifies the manner in which such executive believes that you have not substantially performed your
duties or (b) the willful engaging by you in illegal conduct which is materially and demonstrably injurious to the Company. For purposes of this
paragraph (ii), no act, or failure to act, on your part shall be considered “willful” unless done, or omitted to be done, by you in knowing bad faith
and without reasonable belief that your action or omission was in, or not opposed to, the best interests of the Company. Any act, or failure to act,
based upon authority given pursuant to a resolution duly adopted by the Board or based upon the advice of counsel for the Company shall be
conclusively presumed to be done, or omitted to be done, by you in good faith and in the best interests of the Company. Notwithstanding the
foregoing, you shall not be deemed to have been terminated for Cause unless and until there shall have been delivered to you a copy of a resolution
duly adopted by the affirmative vote of not less than three-quarters of the entire membership of the Board at a meeting of the Board called and held
for the purpose (after reasonable notice to you and an opportunity for you, together with your counsel, to be heard before the Board), finding that
in the good faith opinion of the Board you were guilty of the conduct set forth above in (a) or (b) of this paragraph (ii) and specifying the particulars
thereof in detail.
(iii) Good Reason. Termination by you of your employment with the Company for “Good Reason” shall mean termination by
you of your employment with the Company based on any of the following events provided you give Notice of Termination after
Page 5
the occurrence of any of the following events and no later than 30 days after the later of (1) notice to you of such event, or (2) the Change in
Control:
(A) a change in your status, title, position(s) or responsibilities as an officer of the Company which does not represent a
promotion from your status, title, position(s) and responsibilities as in effect immediately prior to the earlier of Shareholder Approval, if
applicable, or the Change in Control, or the assignment to you of any duties or responsibilities which are inconsistent with such
status, title or position(s), or any removal of you from or any failure to reappoint or reelect you to such position(s), except in
connection with the termination of your employment for Cause or Disability or as a result of your death or by you other than for Good
Reason;
(B) a reduction by the Company in your base salary as in effect immediately prior to the earlier of Shareholder Approval, if
applicable, or the Change in Control;
(C) the failure by the Company to continue in effect any Plan (as hereinafter defined) in which you are participating immediately
prior to the earlier of Shareholder Approval, if applicable, or the Change in Control (or Plans providing you with at least substantially
similar benefits) other than as a result of the normal expiration of any such Plan in accordance with its terms as in effect immediately
prior to the earlier of Shareholder Approval, if applicable, or the Change in Control, or the taking of any action, or the failure to act, by
the Company which would adversely affect your continued participation in any of such Plans on at least as favorable a basis to you as
is the case immediately prior to the earlier of Shareholder Approval, if applicable, or the Change in Control or which would materially
reduce your benefits in the future under any of such Plans or deprive you of any material benefit enjoyed by you immediately prior to
the earlier of Shareholder Approval, if applicable, or the Change in Control;
(D) the failure by the Company to provide and credit you with the number of paid vacation days to which you are then entitled in
accordance with the Company’s normal vacation policy as in effect immediately prior to the earlier of Shareholder Approval, if
applicable, or the Change in Control;
(E) the Company’s requiring you to be based more than 30 miles from where your office is located immediately prior to the earlier
of Shareholder Approval, if applicable, or the Change in Control except for required travel on the Company’s business to an extent
substantially consistent with the business travel obligations which you undertook on behalf of the Company prior to the earlier of
Shareholder Approval, if applicable, or the Change in Control;
(F) the failure by the Company to obtain from any Successor (as hereinafter defined) the assent to this Agreement contemplated
by Section 7 hereof;
Page 6
(G) any purported termination by the Company of your employment which is not effected pursuant to a Notice of Termination
satisfying the requirements of paragraph (iv) below (and, if applicable, paragraph (ii) above); and for purposes of this Agreement, no
such purported termination shall be effective; or
(H) the failure by the Company to pay you any portion of your current compensation, to credit your Deferred Compensation Plan
account in accordance with your previous election, or to pay you any portion of an installment of deferred compensation under any
Plan in which you participated, within seven (7) days of the date such compensation is due.
For purposes of this Agreement, “Plan” shall mean any compensation plan such as an incentive, stock option or restricted stock plan or any
employee benefit plan such as a thrift, pension, profit sharing, deferred compensation, medical, disability, accident, life insurance, or relocation plan
or policy or any other plan, program or policy of the Company intended to benefit employees.
(iv) Notice of Termination. Any purported termination by the Company or by you (other than termination due to your death,
which shall terminate your employment automatically) following the earlier of Shareholder Approval, if applicable, or a Change in Control shall be
communicated by Notice of Termination to the other party hereto. For purposes of this Agreement, a “Notice of Termination” shall mean a notice
which shall indicate the specific termination provision in this Agreement relied upon and shall set forth in reasonable detail the facts and
circumstances claimed to provide a basis for termination of your employment under the provision so indicated.
(A) With respect to any Notice of Termination given by you for Good Reason, such Notice of Termination may indicate that
such termination for Good Reason shall be conditioned upon, and postponed until, the date on which it is finally determined, either by
mutual written agreement of the parties or by the arbitrators in a proceeding as provided in Section 13 hereof, that Good Reason exists
for such termination. If a Notice of Termination given by you for Good Reason indicates that such termination shall be so conditioned
and postponed, then, if the Company disputes the existence of Good Reason, the Company shall, within thirty (30) days after the
Notice of Termination is given, notify you that a dispute exists concerning the termination, whereupon Section 13 hereof shall apply to
such dispute. If no such notice is given by the Company within such 30-day period, then a final determination that Good Reason exists
shall be deemed to have occurred on the date thirty (30) days after the Notice of Termination for Good Reason is given.
(B) Notwithstanding anything to the contrary in this Agreement:
(1) if, at any time before the Date of Termination determined pursuant to this Agreement with respect to any purported
termination by you of your employment with the Company, there exists a basis for the Company to terminate
Page 7
your employment for Cause, then the Company may, regardless of whether or not you have given Notice of Termination for
Good Reason and regardless of whether or not Good Reason exists, terminate your employment for Cause, in which event you
shall not be entitled to the benefits provided in Section 5(iii) hereof, and
(2) if you die or your employment is terminated based on Disability after you have given Notice of Termination for Good
Reason and before the Date of Termination determined under this Agreement with respect to that Notice of Termination, and it
is subsequently finally determined that Good Reason existed at the time your employment terminated, then termination of your
employment shall be deemed to have occurred for Good Reason (and not due to your death or Disability) and you shall be
entitled to the benefits provided in Section 5(iii) hereof.
(v) Date of Termination. “Date of Termination” shall mean the date your employment with the Company is terminated following
the earlier of Shareholder Approval, if applicable, or a Change in Control, which date shall be determined as follows:
(A) if your employment is to be terminated for Disability, thirty (30) days after Notice of Termination is given (provided that, if
you shall have returned to the performance of your duties on a full-time basis during such thirty (30) day period, then the termination
for Disability contemplated by the Notice of Termination shall not occur),
(B) if your employment is terminated due to your death, the date of your death,
(C) if your employment is to be terminated by the Company other than for Disability, or if your employment is to be terminated by
you without a claim of Good Reason, the date specified in the Notice of Termination, and
(D) if your employment is to be terminated by you for Good Reason, the date ninety (90) days after the date on which a Notice of
Termination is given, unless either:
(1) an earlier date has been agreed to by the Company either in advance of, or after, receiving such Notice of Termination
(in which case such earlier date shall be the Date of Termination),
(2) pursuant to and in accordance with Section 4(iv) you have indicated in your Notice of Termination that you are
conditioning your termination upon (and postponing such termination until) the date on which it is finally determined that
Good Reason exists for such termination (in which case the later of such date as determined in accordance with Section 4(iv)
above, or the date otherwise determined under this Section 4(v)(D), shall be the Date of Termination),
Page 8
(3) the Company shall not have notified you within fifteen (15) days after a Notice of Termination for Good Reason is
given that it intends to fully correct the circumstances giving rise to Good Reason (in which case the date fifteen (15) days after
the Notice of Termination shall be the Date of Termination), or
(4) if the Company gives notice as provided in Section 4(v)(D)(3) and if the circumstances giving rise to Good Reason are
fully corrected on or prior to the date that is ninety (90) days after such Notice of Termination was given, then the termination
for Good Reason contemplated by such Notice of Termination shall not occur.
(E) You shall not be obligated to perform any services after the Date of Termination that would prevent the termination of your
employment on such Date of Termination from qualifying as a “separation from service” as defined in Treasury Regulations §1.409A-1
(h).
5. Compensation Upon Termination or During Disability.
(i) During any period following the earlier of Shareholder Approval, if applicable, or a Change in Control that you fail to perform
your duties as a result of incapacity due to physical or mental illness, you shall continue to receive your full base salary at the rate then in effect and
any benefits or awards under any Plans shall continue to accrue during such period, to the extent not inconsistent with such Plans, until your
employment is terminated pursuant to and in accordance with Sections 4(i) and 4(v) hereof. Thereafter, your benefits shall be determined in
accordance with the Plans then in effect.
(ii) If your employment shall be terminated for Cause or as a result of death following the earlier of Shareholder Approval, if
applicable, or a Change in Control, the Company shall pay you your full base salary through the Date of Termination at the rate in effect just prior to
the time a Notice of Termination is given plus any benefits or awards which pursuant to the terms of any Plans have been earned or become
payable, but which have not yet been paid to you. Thereupon the Company shall have no further obligations to you under this Agreement.
(iii) If a Change in Control occurs and either (a) after the earlier of Shareholder Approval, if applicable, or the Change in Control
and no later than twenty-four (24) months after the Change in Control, a Date of Termination of your employment with the Company occurred or
occurs as a result of a termination by the Company other than for Cause or Disability, or (b) your employment with the Company is terminated by
you for Good Reason based on an event occurring concurrent with or subsequent to the earlier of Shareholder Approval, if applicable, or the
Change in Control and your Notice of Termination in connection therewith shall have been given no later than twenty-four (24) months after the
Change in Control, then, by no later than the fifth day following the later of the Date of Termination or the Change in Control (except as
Page 9
may otherwise be provided), you shall be entitled, without regard to any contrary provisions of any Plan, to a severance benefit as follows:
(A) the Company shall pay your full base salary through the Date of Termination at the rate in effect just prior to the time a
Notice of Termination is given plus any benefits or awards which pursuant to the terms of any Plans have been earned or become
payable, but which have not yet been paid to you; provided, however, that with respect to a termination of your employment for Good
Reason based on a reduction by the Company in your base salary as in effect immediately prior to the earlier of Shareholder Approval,
if applicable, or the Change in Control, the Company shall pay your full base salary through the Date of Termination at the rate in
effect just prior to such reduction plus any benefits or awards which pursuant to the terms of any Plans have been earned or become
payable, but which have not yet been paid to you;
(B) as severance pay and in lieu of any further salary for periods subsequent to the Date of Termination, the Company shall pay
to you in a single payment an amount in cash equal to
(
) times the sum of (1) the greater of (i) your annual rate of base
salary in effect on the Date of Termination or (ii) your annual rate of base salary in effect immediately prior to the earlier of Shareholder
Approval, if applicable, or the Change in Control and (2) the greater of (i) the average of the last three annual bonuses (annualized in
the case of any bonus paid with respect to a partial year) paid to you preceding the Date of Termination or (ii) the average of the last
three annual bonuses (annualized in the case of any bonus paid with respect to a partial year) paid to you preceding the earlier of
Shareholder Approval, if applicable, or the Change in Control; provided, however, that if your age on the Date of Termination (your
“Age”) is more than 61, the amount payable to you under this subparagraph (B) shall be reduced by multiplying the amount otherwise
determined as set forth above by 90% if your Age is 62, by 60% if your Age is 63, by 30% if your Age is 64, and by 0% if your Age is
65 or more; and
(C) for a
(
) month period after the Date of Termination (specifically including a Date of Termination that occurs
after Shareholder Approval and prior to a Change in Control), the Company shall arrange to provide you, your spouse and your
dependents with life, accident and health insurance benefits substantially similar to those which you were receiving immediately prior
to the earlier of Shareholder Approval, if applicable, or the Change in Control. Notwithstanding the foregoing, the Company shall not
provide any benefit otherwise receivable by you pursuant to this subparagraph (C) to the extent that a similar benefit is actually
received by you from a subsequent employer during such
(
) month period, and any such benefit actually received by
you shall be reported to the Company.
(iv) The amount of any payment provided for in this Section 5 shall not be reduced, offset or subject to recovery by the
Company by reason of any compensation earned by you as the result of employment by another employer after the Date of Termination, or
Page 10
otherwise. Your entitlements under Section 5(iii) are in addition to, and not in lieu of, any rights, benefits or entitlements you may have under the
terms or provisions of any Plan.
6. Parachute Payments. Notwithstanding any other provision in this Agreement or any other agreement or arrangement between the
Company and you with respect to compensation or benefits (each an “Other Arrangement”), in the event that the provisions of Sections 280G and
4999 of the Internal Revenue Code of 1986, as amended, or any successor provisions (the “Code”), would cause you to receive a greater after-tax
benefit from the Capped Benefit (as defined below) than from the amounts (including the monetary value of any non-cash benefits) otherwise
payable pursuant to this Agreement or any Other Arrangement (the “Specified Benefits”), the Capped Benefit shall be paid to you in lieu of the
Specified Benefits. The “Capped Benefit” shall equal the Specified Benefits, reduced by the amount necessary to prevent any portion of the
Specified Benefits from being a “parachute payment” as defined in Section 280G(b)(2) of the Code. The Capped Benefit would therefore equal 2.99
multiplied by your applicable “base amount” as defined in Section 280G(b)(3) of the Code. For purposes of determining whether you would receive a
greater after-tax benefit from the Capped Benefit than from the Specified Benefits, there shall be taken into account any excise tax that would be
imposed under Section 4999 of the Code and all federal, state and local taxes required to be paid by you in respect of the receipt of such payments.
The parties acknowledge that the application of Section 280G is uncertain in many respects and agree that the Company shall make all calculations
and determinations under this section (including application and interpretation of the Code and related regulatory, administrative and judicial
authorities) in good faith, which calculations and determinations shall be conclusive absent manifest error. The Company shall provide you with a
reasonable opportunity to review and comment on the Company’s calculations of the Capped Benefit and to request which of the Specified Benefits
shall be reduced. If, after payment of any amount under this Agreement or any Other Arrangement, it is determined that the calculation of the
Capped Benefit was calculated incorrectly, the amount of the Capped Benefit will be adjusted, the Company shall pay to you any additional amount
that should have been paid to you, and you shall repay to the Company any amount that should not have been paid to you, in each case with
interest at the discount rate applicable under Section 280G(d)(4) of the Code.
7. Successors; Binding Agreement.
(i) Upon your written request, the Company will seek to have any Successor (as hereinafter defined), by agreement in form and
substance satisfactory to you, assent to the fulfillment by the Company of its obligations under this Agreement. For purposes of this Agreement,
“Successor” shall mean any Person that succeeds to, or has the practical ability to control (either immediately or with the passage of time), the
Company’s business directly, by merger, consolidation or purchase of assets, or indirectly, by purchase of the Company’s Voting Securities or
otherwise.
(ii) This Agreement shall inure to the benefit of and be enforceable by your personal or legal representatives, executors,
administrators, successors, heirs, distributees,
Page 11
devisees and legatees. If you should die while any amount would still be payable to you hereunder if you had continued to live, all such amounts,
unless otherwise provided herein, shall be paid in accordance with the terms of this Agreement to your devisee, legatee or other designee or, if there
be no such designee, to your estate.
8. Fees and Expenses. The Company shall pay to you all legal fees and related expenses incurred by you in good faith as a result of
(i) your termination following the earlier of Shareholder Approval, if applicable, or a Change in Control (including all such fees and expenses, if any,
incurred in contesting or disputing in good faith any such termination) or (ii) your seeking to obtain or enforce in good faith any right or benefit
provided by this Agreement.
9. Survival. The respective obligations of, and benefits afforded to, the Company and you as provided in Sections 5, 6, 7(ii), 8 and 13 of
this Agreement shall survive termination of this Agreement, but only with respect to a Change in Control occurring during the term of this
Agreement.
10. Notice. For the purposes of this Agreement, notices and all other communications provided for in this Agreement shall be in writing
and shall be deemed to have been duly given when delivered or mailed by United States registered mail, return receipt requested, postage prepaid
and addressed to the address of the respective party set forth on the first page of this Agreement, provided that all notices to the Company shall be
directed to the attention of the Chairman of the Board or President of the Company, with a copy to the Secretary of the Company, or to such other
address as either party may have furnished to the other in writing in accordance herewith, except that notice of change of address shall be effective
only upon receipt.
11. Miscellaneous. No provision of this Agreement may be modified, waived or discharged unless such modification, waiver or discharge
is agreed to in a writing signed by you and the Chairman of the Board or President of the Company. No waiver by either party hereto at any time of
any breach by the other party hereto of, or of compliance with, any condition or provision of this Agreement to be performed by such other party
shall be deemed a waiver of similar or dissimilar provisions or conditions at the same or at any prior or subsequent time. No agreements or
representations, oral or otherwise, express or implied, with respect to the subject matter hereof have been made by either party which are not
expressly set forth in this Agreement. The validity, interpretation, construction and performance of this Agreement shall be governed by the laws of
the State of Oregon.
12. Validity. The invalidity or unenforceability of any provision of this Agreement shall not affect the validity or enforceability of any
other provision of this Agreement, which shall remain in full force and effect.
13. Arbitration. Any dispute or controversy arising under or in connection with this Agreement shall be settled exclusively by arbitration
in Portland, Oregon by three arbitrators in accordance with the rules of the American Arbitration Association then in effect. Judgment may be
entered on the arbitrators’ award, which award shall be a final and binding determination of
Page 12
the dispute or controversy, in any court having jurisdiction; provided, however, that you shall be entitled to seek specific performance of your right
to be paid until the Date of Termination during the pendency of any dispute or controversy arising under or in connection with this Agreement. The
Company shall bear all costs and expenses of the arbitrators arising in connection with any arbitration proceeding pursuant to this Section 13.
14. Related Agreements. To the extent that any provision of any other agreement between the Company or any of its subsidiaries and you
shall limit, qualify or be inconsistent with any provision of this Agreement, then for purposes of this Agreement, while the same shall remain in
force, the provision of this Agreement shall control and such provision of such other agreement shall be deemed to have been superseded, and to
be of no force or effect, as if such other agreement had been formally amended to the extent necessary to accomplish such purpose.
15. Counterparts. This Agreement may be executed in several counterparts, each of which shall be deemed to be an original, but all of
which together will constitute one and the same instrument.
If this letter correctly sets forth our agreement on the subject matter hereof, kindly sign and return to the Company the enclosed copy of this
letter which will then constitute our agreement on this subject.
Sincerely,
NORTHWEST NATURAL GAS COMPANY
By
Mark S. Dodson
President and CEO
Agreed to this
day
of
, 2008.
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Section 16: EX-12 (STATEMENT RE COMPUTATION OF RATIOS OF
EARNINGS TO FIXED CHARGES)
EXHIBIT 12
NORTHWEST NATURAL GAS COMPANY
Statement Re: Ratio of Earnings to Fixed Charges
Thousands, except per share amounts
(Unaudited)
2008
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
Ratio of Earnings to Fixed Charges
$
2007
33,605
4,022
700
1,551
39,878
$
69,525
40,678
39,878
$ 150,081
$
$
$
3.76
Year Ended December 31,
2006
2005
34,294
4,116
711
1,523
40,644
$
74,497
44,060
40,644
$ 159,201
$
$
34,651
4,648
716
1,465
41,480
$
63,415
36,234
41,480
$ 141,129
$
$
3.92
3.40
2004
34,330
2,665
808
1,357
39,160
$
58,149
32,720
39,160
$ 130,029
$
$
3.32
$
33,776
2,184
773
1,489
38,222
50,572
26,531
38,222
$ 115,325
3.02
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Section 17: EX-23 (CONSENT OF PRICEWATERHOUSECOOPERS LLP)
EXHIBIT 23
Consent of Independent Registered Public Accounting Firm
We hereby consent to the incorporation by reference in the Registration Statements on Form S-8 (Nos. 33-63017, 333-46430,
333-55002, 333-70218, 333-100885, 333-120955, 333-134973 and 333-139819) and in the Registration Statements on Form
S-3 (Nos. 333-148527 and 333-123898) of Northwest Natural Gas Company of our report dated February 27, 2009 relating to
the consolidated financial statements, financial statement schedule and the effectiveness of internal control over financial reporting,
which appears in this Form 10-K.
/s/ PricewaterhouseCoopers LLP
Portland, Oregon
February 27, 2009
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Section 18: EX-31.1 (CERTIFICATION OF PRINCIPAL EXECUTIVE
OFFICER)
EXHIBIT 31.1
CERTIFICATION
I, Gregg S. Kantor, certify that:
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:
5.
(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
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, 2009
/s/ Gregg S. Kantor
Gregg S. Kantor
President and Chief Executive Officer
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Section 19: EX-31.2 (CERTIFICATION OF PRINCIPAL FINANCIAL
OFFICER)
EXHIBIT 31.2
CERTIFICATION
I, David H. Anderson, certify that:
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:
5.
(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
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, 2009
/s/ David H. Anderson
David H. Anderson
Senior Vice President and Chief Financial Officer
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Section 20: EX-32.1 (CERTIFICATION OF PRINCIPAL EXECUTIVE
OFFICER AND PRINCIPAL FINANCIAL OFFICER)
EXHIBIT 32.1
NORTHWEST NATURAL GAS COMPANY
Certificate Pursuant to Section 906
of Sarbanes – Oxley Act of 2002
Each of the undersigned, GREGG S. KANTOR, the President and Chief Executive Officer, and DAVID H.
ANDERSON, the Senior Vice President and Chief Financial Officer, of NORTHWEST NATURAL GAS COMPANY (the
Company), DOES HEREBY CERTIFY that:
1.
The Company’s Annual Report on Form 10-K for the year ended December 31, 2008 (the Report) fully complies with the
requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and
2.
Information contained in the Report fairly presents, in all material respects, the financial condition and results of operation of
the Company.
IN WITNESS WHEREOF, each of the undersigned has caused this instrument to be executed this 27th day of February
2009.
/s/ Gregg S. Kantor
President and Chief Executive Officer
/s/ David H. Anderson
Senior Vice President and
Chief Financial Officer
A signed original of this written statement required by Section 906 has been provided to Northwest Natural Gas Company and will
be retained by Northwest Natural Gas Company and furnished to the Securities and Exchange Commission or its staff upon
request.
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