SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D. C. 20549
FORM 10-K
(Check 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, 2003
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 0-994
[GRAPHIC OMITTED][GRAPHIC OMITTED]
NORTHWEST NATURAL GAS COMPANY
(Exact name of registrant as specified in its charter)
OREGON 93-0256722
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) 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:
Name of each exchange
Title of each class on which registered
- ------------------- ---------------------
Common Stock, $3 1/6 par value,
and Common Share Purchase Rights New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act:
Title of each class Shares outstanding on January 1, 2004
- ------------------- -------------------------------------
Preferred Stock, without par value None
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 [ X ]
Indicate by check mark whether the registrant is an accelerated filer (as
defined in Rule 12b-2 of the Act). Yes [ X ] No [ ]
As of June 30, 2003, the registrant had 25,726,379 shares of its Common Stock,
$3 1/6 par value, 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 $695,811,500.
Indicate number of shares outstanding of each of registrant's classes of common
stock as of February 27, 2004: Common Stock, $3 1/6 par value, and Common Share
Purchase Rights 25,989,395
DOCUMENTS INCORPORATED BY REFERENCE
List documents incorporated by reference and the Part of the Form 10-K into
which the document is incorporated.
Portions of the Proxy Statement of Company, to be filed in connection with the
2004 Annual Meeting of Shareholders, are incorporated by reference in Part III.
NORTHWEST NATURAL GAS COMPANY
Annual Report to Securities and Exchange Commission
on Form 10-K
For the Fiscal Year Ended December 31, 2003
TABLE OF CONTENTS
PART I
Item 1. Business
General...................................................... 3
Subsidiaries................................................. 3
Gas Supply................................................... 4
Interstate Storage Services.................................. 7
Regulation and Rates......................................... 7
Additions to Infrastructure.................................. 9
Pipeline Safety.............................................. 9
Competition and Marketing....................................10
Environment..................................................12
Employees....................................................12
Available Information........................................12
Item 2. Properties.......................................................13
Item 3. Legal Proceedings................................................13
Item 4. Submission of Matters to a Vote of Security Holders..............14
PART II
Item 5. Market for the Registrant's Common Equity........................15
Item 6. Selected Financial Data..........................................16
Item 7. Management's Discussion and Analysis of Results of
Operations and Financial Condition...........................18
Item 7A. Quantitative and Qualitative Disclosures About Market Risk ......39
Item 8. Financial Statements and Supplementary Data......................42
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure..........................77
Item 9A. Controls and Procedures..........................................77
PART III
Item 10. Directors and Executive Officers of the Registrant...............78
Item 11. Executive Compensation...........................................79
Item 12. Security Ownership of Certain Beneficial Owners and
Management and Related Stockholder Matters...................79
Item 13. Certain Relationships and Related Transactions...................80
Item 14. Principal Accountant Fees and Services...........................80
PART IV
Item 15. Exhibits, Financial Statement Schedules and Reports
on Form 8-K .................................................80
SIGNATURES .............................................................81
2
NORTHWEST NATURAL GAS COMPANY
PART I
ITEM 1. BUSINESS
General
- -------
Northwest Natural Gas Company (NW Natural or the Company) was
incorporated under the laws of Oregon in 1910. The Company and its predecessors
have supplied gas service to the public since 1859. Since September 1997, it has
been doing business as NW Natural.
NW Natural is principally engaged in the distribution of natural gas.
The Public Utility Commission of Oregon (OPUC) has allocated to NW Natural as
its 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. NW Natural also holds certificates from the Washington
Utilities and Transportation Commission (WUTC) granting it exclusive rights to
serve portions of three southern Washington counties bordering the Columbia
River. Gas service is provided in 98 cities, together with neighboring
communities, in 15 Oregon counties, and in nine cities, together with
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.
NW Natural also is engaged in providing natural gas storage and
transportation services to interstate customers using storage capacity that has
been developed in advance of core utility customers' (residential, commercial
and industrial firm) requirements. These services began in 2001 when the Federal
Energy Regulatory Commission (FERC) granted NW Natural a limited jurisdiction
blanket certificate permitting it to provide storage and transportation services
to customers in interstate commerce. Under agreements with the OPUC and WUTC, NW
Natural retains the majority of the net income before tax from interstate
storage services and credits the balance to its core utility customers. NW
Natural has a contract with an independent energy trading company that seeks to
optimize the use of NW Natural's assets by trading temporarily unused portions
of its upstream pipeline transportation capacity and gas storage capacity.
At year-end 2003, NW Natural had 519,427 residential customers, 57,969
commercial customers and 754 industrial customers. Industries served 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.
Subsidiaries
- ------------
The Company operated only one direct, active subsidiary during 2003,
NNG Financial Corporation (Financial Corporation). Financial Corporation, a
wholly-owned subsidiary of the Company incorporated in Oregon, holds financial
investments including limited partnership interests in three solar electric
generating plants and two wind power electric generation projects, all located
in California, and in two low-income housing projects in Portland, Oregon.
Financial Corporation also has one active, wholly-owned subsidiary, KB Pipeline
Company (KB Pipeline), which owns a 10 percent interest in an 18-mile interstate
natural gas pipeline. KB Pipeline is the operator of the pipeline; however, in
December 2003 it gave notice to the pipeline co-owners that it is resigning as
pipeline operator effective in June 2004 due to increased obligations resulting
from FERC's final regulations implementing Standards of Conduct for Transmission
Providers. Those regulations govern the relationship between interstate natural
gas pipelines and their energy affiliates or marketing functions and impose
obligations previously inapplicable to KB Pipeline with regard to separation of
duties and related matters. The regulations will continue to be applicable to KB
Pipeline as a co-owner after its resignation as pipeline operator.
A second direct, wholly owned subsidiary of the Company, Northwest
Energy Corporation (Northwest Energy), also an Oregon corporation, was formed in
2001 to serve as the holding company of NW Natural and Portland General Electric
3
Company (PGE) if the proposed acquisition of PGE had been completed. The
Company's agreement to purchase PGE was terminated in 2002. Northwest Energy had
no operations in 2003 or 2002.
Gas Supply
- ----------
General
-------
NW Natural meets the needs of its core utility customers through
natural gas purchases from a variety of suppliers. NW Natural has a diverse
portfolio of short- and medium-term firm gas supply contracts that it
supplements, during periods of peak demand, with gas from storage facilities
either owned by or contractually committed to NW Natural.
NW Natural's goal in purchasing gas for its core market is to meet
customers' needs at competitive prices. NW Natural believes that gas supplies
available from suppliers in the western United States and Canada are adequate to
serve its core market customers for the foreseeable future, and that its cost of
gas generally will track market prices.
The cost to NW Natural of gas to supply its core market consists of the
purchase price paid to suppliers plus charges paid to pipelines to transport the
gas to NW Natural's distribution system. While the rates for pipeline
transportation and storage services are subject to federal regulation, the
purchase price of gas is not. Although pipeline rates have been relatively
stable in recent years, natural gas commodity prices have fluctuated
dramatically. NW Natural has sought to mitigate the effect of higher gas
commodity prices and price volatility on core utility customers through the use
of its underground storage facilities, by entering into gas commodity-based
financial hedge contracts, and by crediting gas costs with margin revenues
derived from off-system sales of commodity and released transportation capacity
in periods when core utility customers do not fully utilize firm pipeline
capacity and gas supplies.
NW Natural supplies many of its non-core customers (larger industrial
interruptible customers with full or partial dual fuel capabilities) through gas
transportation service, delivering gas purchased by these customers directly
from suppliers. (See "Gas Supply - Transportation," below.)
Core Market Basic Supply
------------------------
NW Natural purchases gas for its core market from a variety of
suppliers located in the western United States and Canada. About 80 percent of
its annual supply comes from Canada, with the balance coming primarily from the
U.S. Rocky Mountain region. At Jan. 1, 2004, NW Natural had 31 firm contracts
with 12 suppliers with remaining terms ranging from three months to five years,
which provided for a maximum of 3,070,000 therms/1/ of firm gas per day during
the peak winter season and 1,570,000 therms per day during the remainder of the
year. These contracts have a variety of pricing structures and purchase
obligations.
NW Natural's largest core market gas supply contract was a 15-year
agreement that expired in November 2003 with CanWest Gas Supply, Inc., an
aggregator for gas producers in British Columbia, Canada. That contract allowed
NW Natural to purchase up to 960,000 therms of firm gas per day. Four other
long-term firm gas supply agreements that had been entered into during the late
1980s and early 1990s with three suppliers (BP Canada, Burlington Resources
Canada and Engage Energy) also expired in 2003. All of these contracts pertained
to Canadian supplies purchased in the provinces of British Columbia and Alberta,
totaling approximately 1,300,000 therms per day on a year-round basis, with an
additional 140,000 therms per day available only during the heating season.
- -----------------
1 One therm is equivalent to 100 cubic feet of natural gas at an assumed
heat content of 1,000 British Thermal Units (Btu's) per cubic foot.
4
Over the past two years, 11 new firm year-round contracts were
negotiated with a variety of existing and new suppliers so that a seamless
transition could take place as the five older contracts expired. Considered
together, the new purchase agreements provide a similar amount of gas as the
expired contracts, with no single contract amounting to more than 200,000 therms
per day. These new firm year-round supply contracts have terms ranging from one
to five years, with a volume weighted average term of just over three years. All
of the contracts use price formulas tied to monthly index prices, primarily at
the AECO C/N.I.T. trading point within Alberta. Using financial instruments, NW
Natural hedges the index prices (see "Gas Supply-Hedge Program," below).
In addition to the year-round contracts, NW Natural continues to
contract in advance for firm gas made available only during the heating season.
During 2002 and 2003, new short-term (five-month) purchase agreements were
entered into with seven suppliers. These agreements have a variety of pricing
structures and provide for a total of up to 1,500,000 therms per day during the
2003-2004 heating season. One of these contracts, providing up to 200,000 therms
per day, also extends to the 2004-2005 and 2005-2006 heating seasons.
NW Natural intends to enter into new purchase agreements in 2004 for
equivalent volumes of gas with its existing or other similar suppliers as needed
to replace short-term and one-year contracts that will expire during 2004.
NW Natural also buys gas on the spot market (30 days or less) as needed
to meet demand. NW Natural has flexibility under the terms of some of its firm
supply contracts enabling it to purchase spot gas in lieu of firm contract
volumes, thereby allowing it to take advantage of favorable pricing on the spot
market from time to time.
NW Natural continues to purchase gas from a producer in the Mist gas
field in Oregon. The production area is situated near NW Natural's underground
gas storage facility. The price for this gas is tied to NW Natural's weighted
average cost of gas. Current production is approximately 20,000 therms per day
from about 18 wells, supplying about 1 percent of NW Natural's total annual
purchase requirements. Production from these wells varies as existing wells are
depleted and new wells are drilled.
Core Market Peaking Supply
--------------------------
NW Natural supplements its firm gas supplies with gas from
Company-owned or contracted peaking facilities in which gas is stored during
periods of low demand for use during periods of peak demand. In addition to
enabling NW Natural to meet its peak demand, these facilities make it possible
to lower the annual average cost of gas by allowing NW Natural both to minimize
its pipeline transportation contract demand and to purchase gas for storage
during the summer months when prices are generally at their lowest.
NW Natural has contracts with Williams Gas Pipeline-West (WGP),
formerly known as Northwest Pipeline, that expire in 2004 for firm gas storage
services from an underground field at Jackson Prairie near Centralia,
Washington, and a liquefied natural gas (LNG) facility at Plymouth, Washington.
Together, these facilities provide NW Natural with daily firm deliverability of
about 1.1 million therms and total seasonal capacity of about 16 million therms.
Separate contracts with WGP provide for the transportation of these storage
supplies to NW Natural's service territory. These contracts may be extended on
an annual basis after the end of their primary terms at NW Natural's option.
NW Natural owns and operates two LNG plants that liquefy gas during the
summer months for storage until the peak winter season. These two plants provide
a maximum daily deliverability of 1.8 million therms and a total seasonal
capacity of 17 million therms.
NW Natural also provides daily and seasonal peaking from the
underground gas storage facility it owns and operates in the Mist gas field.
This facility has a maximum daily deliverability of 3.2 million therms and a
total seasonal working gas capacity of 115 million therms. NW Natural completed
its latest expansion of the Mist storage facility in December 2001. This $10
million project increased the facility's total daily delivery capacity by 29
percent. The increased deliverability is used to serve the needs of NW Natural's
core utility customers as well as its interstate storage service customers (see
"Interstate Storage Services," below). As the needs of core utility customers
5
grow, existing interstate capacity will be transferred for use by core utility
customers and be replaced by newly developed interstate storage capacity. The
plan for expansion of NW Natural's storage capability includes an extension of
its South Mist Pipeline that is scheduled for completion in 2004 (see "Additions
to Infrastructure," below), and further development of existing storage
reservoirs.
NW Natural also has contracts with an electric generator, two
industrial customers, and one gas marketing company that together provide a
total of 102,000 therms per day of year-round capacity, plus 900,000 therms per
day of recallable capacity and supply. These contracts have remaining terms
ranging from two months to seven years.
Hedge Program
-------------
NW Natural has an active natural gas commodity-price hedge program that
is intended to reduce commodity price risk. Under this program, the Company
typically enters into commodity swap and call option agreements during the
spring and summer seasons, when natural gas prices may be lower. Gains (losses)
from commodity hedges are treated for accounting and rate purposes as reductions
(increases) to the cost of gas. The intended effect of this program is to lock
in prices for a large portion of NW Natural's gas supply portfolio for the
following year, at prevailing market prices at the time the swap and call option
agreements are entered into.
Transportation
--------------
Natural gas for NW Natural's core market is transported over the
interstate pipeline system of WGP. Most supplies also move over other pipelines
upstream of WGP's system in the U.S. and Canada. Rates for transportation are
established by the FERC for service under transportation agreements between NW
Natural and the U.S. interstate pipelines, and by Canadian federal or provincial
authorities for service under agreements with the Canadian pipelines over which
NW Natural ships gas.
The largest of the transportation agreements with WGP extends through
2013 and provides for firm transportation capacity of up to 2,148,890 therms per
day. This agreement provides access to natural gas supplies in British Columbia
and the U.S. Rocky Mountains.
The Company's second largest transportation agreement with WGP extends
through 2011. It provides 1,020,000 therms per day of firm transportation
capacity from the point of interconnection of the WGP and PG&E Gas Transmission
Northwest (GTN) systems in eastern Oregon to NW Natural's 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. NW
Natural's total capacity on GTN and two upstream pipelines in Canada (Alberta
Natural Gas Company and NOVA Corporation of Alberta, now both units of
TransCanada PipeLines Limited) matches this amount of WGP capacity northward
into Alberta, Canada.
NW Natural also has an agreement with WGP that extends through 2013 for
351,550 therms per day of firm transportation capacity. This agreement accesses
gas supplies in the U.S. Rocky Mountain region.
In 2002, NW Natural entered into four long-term pipeline transportation
contracts, one that commenced in November 2003 and the other three commencing in
November 2004. A contract with Duke Energy Gas Transmission (formerly Westcoast
Energy, Inc.) (Duke Energy GT) effective in November 2003 and extending through
October 2014, provides approximately 600,000 therms per day of firm gas
transportation from northern British Columbia to a connection with WGP at the
U.S.-Canadian border. A contract with Terasen Gas (formerly BC Gas) effective in
November 2004 and extending through October 2020, will provide approximately
470,000 therms per day of firm gas transportation from southeastern British
Columbia to the same connection with WGP at the U.S.-Canadian border. NW
Natural's capacity with Terasen Gas is matched with companion contracts for
pipeline capacity on systems of Alberta Natural Gas Company and NOVA Corporation
of Alberta that connect to the gas fields of Alberta, Canada.
6
Since WGP opened its system to the transportation of customer-owned gas
in the late 1980s, most of NW Natural's large industrial customers have switched
from sales service to transportation service whereby they purchase gas directly
from suppliers and ship the gas on the Company's system and those of its
pipeline suppliers for a fee. The ability of industrial customers to switch
between sales service and transportation service has made it possible for NW
Natural to retain some of these customers. Periodic switching between sales and
transportation service by these customers has had an adverse effect on NW
Natural's results of operations in certain years, and a positive effect in other
years, as industrial customers have sought to find the most economical and
reliable combination of gas supply and delivery services (see "Competition and
Marketing," below). In 2003, NW Natural redesigned its industrial rates in the
Oregon general rate case and, as a result, it expects less switching from
higher-margin to lower-margin service contracts than it has experienced in the
past (see "Regulation and Rates," below).
Interstate Storage Services
- ---------------------------
NW Natural provides gas storage services to interstate customers using
storage capacity that has been developed in advance of its core utility
customers' requirements. In 2001, the FERC authorized NW Natural to provide firm
and interruptible gas storage service and related transportation service to and
from the Mist gas storage facility to customers in interstate commerce. In 2003,
NW Natural provided storage services to nine interstate customers. The FERC
limited jurisdiction certificate enables NW Natural to make its underground gas
storage capacity available to help address the region's energy challenges, but
NW Natural retains its exemption from full FERC jurisdiction.
Regulation and Rates
- --------------------
NW Natural is subject to regulation with respect to, among other
matters, rates, systems of accounts and issuance of securities by the OPUC and
the WUTC. In 2003, 93 percent of NW Natural's utility gas deliveries and 92
percent of its utility operating revenues were derived from Oregon customers and
the balance from Washington customers. NW Natural is exempt from the provisions
of the Natural Gas Act by order of the Federal Power Commission (now the FERC),
except with respect to the terms and conditions associated with its interstate
gas storage and related transportation services (see "Interstate Storage
Services," above).
NW Natural's recent general rate increase in Oregon, which was
effective Sept. 1, 2003, authorized rates designed to produce a return on
shareholders' equity (ROE) of 10.2 percent. The OPUC approved a revenue increase
of $13.9 million per year, of which $6.2 million went into effect on Sept. 1,
2003 and $2.8 million went into effect on a deferred basis on Nov. 12, 2003 as
the first 11.7 miles of the Company's South Mist Pipeline Extension (SMPE) went
into service (see "Additions to Infrastructure," below). The remainder will go
into effect as all or portions of the SMPE project and the Company's Coos County
distribution system project are completed and go into service in 2004.
The most recent general rate increase in Washington, which was fully
effective in October 2001, authorized rates designed to produce an ROE of 10.8
percent and a revenue increase of $4.3 million per year, or 12.1 percent. On
Nov. 19, 2003, NW Natural filed a new general rate case in Washington. The
filing proposes a revenue increase of $7.9 million per year from Washington
operations through rate increases averaging 15 percent. A decision by the WUTC
is expected by the end of October 2004. See Part II, Item 7., "Results of
Operations - Regulatory Matters-General Rate Cases."
Notwithstanding authorized revenue levels approved by the OPUC or the
WUTC, actual revenues are dependent on weather, economic conditions, customer
growth, competition and other factors affecting gas usage in NW Natural's
service area.
In November 2003, NW Natural implemented a weather normalization
mechanism in Oregon that helps stabilize the Company's net operating revenues by
adjusting current customer billings based on temperature variances from average
weather. The weather normalization mechanism approved by the OPUC will be
7
applied to NW Natural's Oregon residential and commercial customers' bills
between Nov. 15 and May 15 of each heating season. The mechanism adjusts the
margin component of customers' rates to reflect "normal" weather using the
25-year average temperature for each day of the billing period. The mechanism is
intended to stabilize NW Natural's recovery of its fixed costs and to reduce
fluctuations in customers' bills due to colder- or warmer-than-average weather.
In Oregon, NW Natural has a Purchased Gas Adjustment (PGA) tariff under
which net income derived from Oregon operations may be affected within defined
limits by changes in purchased gas costs. The PGA tariff provides for periodic
revisions in rates due to changes in the Company's cost of purchased gas. Costs
included in the PGA adjustments are based on NW Natural's projected gas
requirements and negotiated gas prices for the upcoming gas supply contract
year. Under its Washington PGA, NW Natural is permitted to track 100 percent of
increases and decreases in gas commodity costs, with the result that net income
is not directly affected by changes in commodity costs. In both Oregon and
Washington, the PGA mechanism permits NW Natural to recover 100 percent of
FERC-approved pipeline transportation costs.
The Oregon PGA tariff provides that 67 percent of any difference
between actual purchased gas costs and estimated purchased gas costs
incorporated into rates will be deferred for amortization in subsequent periods.
If actual gas commodity costs exceed those incorporated in rates, NW Natural
subsequently will adjust its rates upward to recover 67 percent of the
deficiency from core market customers. Similarly, if actual gas commodity costs
are lower than those reflected in rates, rates will be adjusted downward to
distribute to core utility customers 67 percent of such gas commodity cost
savings.
In an order issued in 1999, the OPUC formalized a process that tests
for excessive earnings in connection with gas utilities' annual filings under
their PGA mechanisms. The OPUC confirmed NW Natural's ability to pass through
100 percent of its prudently incurred gas costs into rates. Under this order, NW
Natural is authorized to retain all of its earnings up to a threshold level
equal to its authorized ROE plus 300 basis points. One-third of any earnings
above that level will be refunded to customers. The excess earnings threshold is
subject to adjustment up or down each year depending on movements in interest
rates.
In 2002, the OPUC approved a settlement in a proceeding NW Natural
initiated in 2001 with a goal of stabilizing margin revenues in the face of
above- or below-normal consumption patterns. Pursuant to the settlement, the
OPUC authorized a mechanism for rate changes relating to the impact of price
elasticity, starting with small increases to residential and commercial rates
that became effective on Oct. 1, 2002.
Also under the settlement, the OPUC authorized NW Natural to implement
a partial decoupling mechanism effective Oct. 1, 2002. Decoupling mechanisms are
used to break the link between a utility's earnings and the energy consumed by
its customers so the utility does not have an incentive to discourage customers'
conservation efforts. The decoupling mechanism works by adding margin revenues
during periods when customer consumptions are lower than baseline consumption or
by deducting margin revenues when consumptions are higher than the baseline.
Under the partial decoupling mechanism, NW Natural uses a balancing account to
defer and subsequently amortize 90 percent of the margin differentials between
baseline usage by its residential and commercial customers and
weather-normalized actual usage by these customers. The deferred amounts are
treated as adjustments to be refunded or collected in future periods. Baseline
consumption is based on customer consumption patterns as determined in the
Oregon general rate case, adjusted for consumptions resulting from new
customers. The partial decoupling mechanism will expire at the end of September
2005 unless the OPUC approves an extension based on the results of an
independent study to measure the mechanism's effectiveness.
Also under the settlement, NW Natural agreed to adopt certain service
quality measures that establish the Company's performance goal for minimizing
complaints by customers where the Company is determined to be at fault. If NW
Natural exceeds the prescribed level of at-fault complaints, it will be subject
to penalties.
The OPUC and WUTC have implemented "integrated resource planning"
processes under which utilities develop plans defining alternative growth
scenarios and resource acquisition strategies. In 2000 and 2001, respectively,
the OPUC and the WUTC acknowledged and accepted NW Natural's submission of its
8
fourth Integrated Resource Plan. Elements of the plan 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. Although the
OPUC's order acknowledging an earlier Integrated Resource Plan indicated the
order did not constitute ratemaking approval of any specific resource
acquisition or expenditure, the OPUC did indicate that it would give
considerable weight in prudency reviews to utility actions that are consistent
with acknowledged plans. Elements of NW Natural's fourth Integrated Resource
Plan demonstrated that the continued development of the Mist underground gas
storage facility is the least-cost option for serving customer growth. The
OPUC's acceptance of the plan indicated to the Oregon Energy Facility Siting
Council (EFSC) that NW Natural required the South Mist Pipeline extension to
best serve its customers, thereby satisfying the requirement that NW Natural
prove the need for the facility in order to obtain the EFSC's approval to build
the pipeline extension (see "Additions to Infrastructure," below). NW Natural
will be filing a fifth Integrated Resource Plan in 2004.
Additions to Infrastructure
- ---------------------------
NW Natural expects a high level of capital expenditures for additions
to infrastructure over the next five years, reflecting projected customer
growth, system replacement, improvement and reinforcement projects and the
development of additional gas storage facilities. NW Natural's utility
construction expenditures are estimated to total between $500 million and $600
million over the five-year period 2004 through 2008, including an estimated $165
million in 2004.
NW Natural continues to be one of the fastest growing gas utilities in
the nation (see "Competition and Marketing," below). In 2003 NW Natural grew its
customer base by more than 3 percent for the 17th year in a row, and in 2004 it
expects to continue that trend with projected capital expenditures of $31
million for the addition of new customers.
NW Natural will have significant capital requirements during the next
five years for system replacement, improvement and reinforcement projects,
including an estimated $38 million in 2004. These include requirements pursuant
to new federal legislation as well as expenditures under NW Natural's ongoing
pipeline safety program (see "Pipeline Safety," below).
The extension of the pipeline from NW Natural's Mist gas storage field,
designed to move more gas into growing portions of its service area (see "Gas
Supply - Core Market Peaking Supply," "Interstate Storage Services" and
"Regulation and Rates," above) has an estimated total cost of $105 million,
including $56 million in 2004. The project has a scheduled completion date in
late 2004, but the timeline for completion will depend, in part, on obtaining
necessary rights-of-way. Following two years of review of NW Natural's
application, including extensive public involvement, the EFSC granted a permit
for the project, with conditions, in March 2003. Following denial by the Oregon
Supreme Court of a motion to stay the effect of the permit, NW Natural proceeded
with the construction and completed and placed the first 11.7 miles of the SMPE
project into service in November 2003. Also in November 2003, the Oregon Supreme
Court affirmed the issuance of the permit that had been appealed by interested
parties. NW Natural must obtain easements and rights-of-way for the construction
of the remainder of the pipeline and may need to use condemnation proceedings to
secure some of them.
Pipeline Safety
- ---------------
The Pipeline Safety Improvement Act of 2002 (Pipeline Safety Act)
requires operators of gas transmission pipelines to identify lines located in
High Consequence Areas (HCAs) and develop Integrity Management Programs (IMPs)
to periodically inspect the integrity of the pipelines and make repairs or
replacements as necessary to ensure the ongoing integrity of the pipelines. The
legislation requires NW Natural to complete inspection of the 50 percent highest
risk pipelines located in its HCAs within the first five years, and the
remaining covered pipelines within 10 years of the date of enactment. The
Pipeline Safety Act also requires re-inspections of the covered pipelines every
seven years thereafter for the life of the pipelines. In December 2003, the U.S.
Department of Transportation issued a final rule entitled "Pipeline Safety:
Pipeline Integrity Management in High Consequence Areas (Gas Transmission
Pipelines)" that specifies the detailed requirements for transmission IMPs as
9
mandated by the Pipeline Safety Act. See Part II., Item 7, "Financial
Condition-Cash Flows-Investing Activities." The Pipeline Safety Act also applies
to the 18-mile interstate natural gas pipeline that KB Pipeline operates.
NW Natural entered into a stipulation with the OPUC in 2001 for an
enhanced pipeline safety program that includes an accelerated bare steel
replacement program and a geo-hazard safety program. The bare steel replacement
program accelerates the replacement of NW Natural's bare steel piping over 20
years instead of 40 years. The geo-hazard safety program includes the
identification, assessment and remediation of risks to piping infrastructure
created by landslides, washouts, earthquakes or similar occurrences. The
stipulation allowed NW Natural to receive deferred accounting rate treatment
commencing in October 2002, for costs associated with the programs exceeding $3
million per year, expected to be approximately $1.5 million annually.
Competition and Marketing
- -------------------------
NW Natural has no direct competition in its service area from other
natural gas distributors. For residential customers' heating needs, however, NW
Natural competes with electricity, fuel oil, propane and, to a lesser extent,
wood. It also competes with electricity and fuel oil for commercial
applications. Competition among these forms of energy is based on price,
reliability, efficiency and performance.
Overall, in 2003 NW Natural maintained its competitive price advantage
compared to electricity in both the residential and commercial markets. In 2003,
although electricity prices stabilized and electricity became more competitive
primarily due to improving end use technology, natural gas retained its relative
price advantage compared to electricity provided by the investor-owned utilities
that serve approximately 75 percent of the homes in NW Natural's Oregon service
area. NW Natural expects to maintain a price advantage compared to electricity
provided by the investor-owned electric utilities in its service territory, in
part because a growing portion of the electricity sold by these utilities is
generated from natural gas. Although there was an increasing price advantage for
gas compared to oil in the latter half of 2002, there were fewer residential
conversions from heating oil to natural gas during 2003 due to weak economic
conditions, volatile gas prices, and a decline in the remaining inventory of
potential oil conversion opportunities.
The relatively low market saturation of natural gas in residential
single-family and attached dwellings in NW Natural's service territory,
estimated at 40 to 50 percent, together with the price advantage of natural gas
compared with electricity and its operating convenience over fuel oil, provides
the potential for continuing growth in the residential and commercial conversion
markets. In 2003, 16,025 net residential customers (after subtracting
disconnected or terminated services) were added, including 5,534 units of
existing residential housing that were converted from oil, electric or propane
appliances to natural gas. The net total of all new customers added in 2003 was
18,083. This constituted a growth rate of 3.2 percent, which is about twice the
national average for local gas distribution companies (LDCs) as reported by the
American Gas Association.
Due to weather that was about 7 percent warmer in 2003 than in 2002,
and a decrease in weather-sensitive customer consumption due to commodity
price-related rate increases in prior years and continuing conservation efforts,
natural gas sales volumes to residential and commercial customers in 2003 were
about 1 percent lower than in 2002. Temperatures in NW Natural's service
territory in 2003, based on heating degree-days, were about 7 percent warmer
than the 25-year average.
As a result of the deregulation and restructuring of the energy markets
during the past decade, the natural gas industry, including producers,
interstate pipelines and LDCs, has undergone many changes. Traditionally, LDCs
sold a "bundled" product that included both the natural gas commodity and
delivery to the meter. However, beginning in the late 1980s, large industrial
customers sought to achieve savings by procuring their own supplies of natural
gas from producers and contracting with pipelines and LDCs for transportation to
their facilities. These changes were intended to promote competition where it is
economically beneficial to consumers.
Competition to serve the industrial and large commercial market in the
Pacific Northwest has been relatively steady since the early 1990s in terms of
numbers and types of competitors. Competitors consist of gas marketers,
10
oil/propane sellers and electric utilities. Wood-based fuels continue to lose
market share in these markets primarily due to environmental concerns and
restrictions.
The OPUC and WUTC have approved transportation tariffs under which NW
Natural may contract with customers to deliver customer-owned gas.
Transportation tariffs available to industrial customers are priced at the
Company's cost of providing transportation service. Generally, the Company is
unaffected financially if industrial customers transport customer-owned gas
rather than purchasing gas from NW Natural, as long as they remain on a tariff
or contract with the same quality of service. However, industrial customers may
select between firm and interruptible service, among other different levels or
qualities of service, and these choices can positively or negatively affect
margin revenue from such customers. The relative level and volatility of prices
in the natural gas commodity markets, the availability of interstate pipeline
capacity to ship customer-owned gas and the cost structure embedded in NW
Natural's industrial rates are among the primary factors that have caused some
industrial customers to alternate between sales and transportation service or
between higher and lower qualities of service. NW Natural re-designed its
industrial rates in Oregon as part of its general rate case in 2003,
transferring $4.8 million of annual revenue requirement from industrial rates to
residential and commercial rates in order to better reflect relative costs of
service and to become more competitive in the industrial market.
Total industrial throughput, including both sales and transportation of
firm and interruptible gas, was 518 million therms in 2003, down 3 percent from
535 million therms in 2002. NW Natural's industrial base includes customers in
the high-tech, forest products and other industries that are sensitive to
economic conditions and were negatively affected by the weak economy in 2003. In
2003, NW Natural substantially increased deliveries to a high-volume customer
served under a new, low margin contract for gas transportation to a cogeneration
facility.
The mix within NW Natural's industrial market between sales and
transportation service was different in 2003 than in 2002. Industrial sales in
2003 were 103 million therms, representing 20 percent of total industrial
deliveries, up from 89 million therms or 17 percent of total industrial
deliveries in 2002. Most of the transfers from transportation to sales service
occurred during the second quarter of 2002, when spot prices in the gas
commodity market were higher than the weighted average cost of gas embedded in
NW Natural's sales rates for the year.
The mix within the industrial market between firm and interruptible
service also was different in 2003. Industrial deliveries under tariffs for firm
service were 39 percent of total industrial deliveries in 2003, compared to 34
percent of total industrial deliveries in 2002. Total margin from firm
industrial deliveries was down by 7 percent in 2003 and total margin from the
combination of firm and interruptible deliveries was down by 7 percent. Due to
the reclassification of some commercial customers to the industrial category and
the cost structure embedded in the industrial rate re-design, 2002 and 2003
industrial deliveries are not comparable.
NW Natural and certain of its largest industrial customers have entered
into negotiated transportation service agreements. These agreements are designed
to provide transportation rates that are competitive with the customer's
alternative capital and operating costs of installing direct connections to
WGP's interstate pipeline system, "bypassing" NW Natural's gas distribution
system. The agreements generally prohibit bypass during their terms. Due to the
cost pressures that confront a number of NW Natural's largest customers that
compete in global markets, bypass continues to be a threat. Although NW Natural
does not expect a significant number of its large customers to bypass its system
in the foreseeable future, it may experience further deterioration of margin
associated with customers' transfers to contracts with pricing designed to be
competitive with bypass.
The Pacific Northwest historically has enjoyed some of the lowest
electric rates in the nation, primarily due to the proximity of federal
hydroelectric facilities. Due to a number of environmental, economic and
political limitations on the future use of the hydroelectric infrastructure in
the Pacific Northwest, as well as the supply and price dislocations that
occurred in the electricity market in the West in 2000 and 2001, a few large
gas-fired generation projects are currently in various stages of construction or
development in the region. These projects, as well as projects for cogeneration
or distributed generation of electricity, may present opportunities for NW
Natural to serve new loads. The availability of interstate pipeline
transportation capacity, gas storage capacity and economically priced gas
supplies could play significant roles in the future development of generation
projects.
11
NW Natural is authorized by the OPUC to make off-system commodity sales
when seasonal demand is low. This often allows NW Natural to compete effectively
with independent gas marketers. Sixty-seven percent of the net revenues (gross
revenues less the actual cost of gas) generated from these sales are credited to
Oregon core utility gas costs, with the balance benefiting shareholders.
Environment
- -----------
The Company's properties and facilities are subject to federal, state
and local laws and regulations related to environmental matters. These evolving
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 level. These factors include, but are not limited to
the following:
o the complexity of the site;
o changes in environmental laws and regulations at the federal, state
and local levels;
o the number of regulatory agencies or other parties involved;
o new technology that renders previous technology obsolete or
experience with existing technology that proves ineffective;
o the ultimate selection of technology;
o the level of remediation required; and
o variations between the estimated and actual period of time that
must be dedicated to respond to an environmentally-contaminated
site.
NW Natural owns or previously owned properties currently being
investigated that may require environmental response, including property in
Multnomah County, Oregon that is the site of a former gas manufacturing plant
that was closed in 1956 (the Gasco site), property adjacent to the Gasco site
that now is the location of a manufacturing plant owned by Wacker Siltronic
Corporation (the Wacker site), and an area adjacent to the Gasco site and the
Wacker site along a segment of the Willamette River (the Portland Harbor) that
has been listed by the U.S. Environmental Protection Agency as a Superfund site
for which the Company has been identified as a potentially responsible party.
The Company does not expect that the ultimate resolution of these matters will
have a material adverse effect on its financial position, results of operations
or cash flows. See Note 12 to the accompanying Consolidated Financial Statements
for a further discussion of potential environmental responses and related costs.
Employees
- ---------
At Dec. 31, 2003, NW Natural had 1,291 employees, of which 895 were
members of the Office and Professional Employees International Union, Local No.
11. Company management and union employees are currently negotiating a new labor
agreement to replace a seven-year Joint Accord labor agreement covering wages,
benefits and working conditions that will expire on March 31, 2004.
Available Information
- ---------------------
The Company files annual, quarterly and special reports and other
information with the Securities and Exchange Commission (SEC). The Company makes
available on its website (http://www.nwnatural.com), free of charge, its annual
report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form
8-K, and amendments to those reports filed or furnished pursuant to Section
13(a) or 15(d) of the Securities Exchange Act of 1934, as soon as reasonably
practicable after it electronically files such material with, or furnishes it
to, the SEC. In addition, copies of these documents may be requested, at no
cost, by writing or calling Shareholder Services, Northwest Natural Gas Company,
One Pacific Square, 220 N.W. Second Avenue, Portland, Oregon 97209, telephone
503-226-4211.
The Company has 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 the Company's website. The Company's Corporate Governance
12
Standards and additional information about NW Natural also are available on the
website. Copies also may be obtained by request to the Corporate Secretary at
the address given above.
ITEM 2. PROPERTIES
NW Natural's natural gas distribution system consists of 12,458 miles
of distribution and transmission mains. In addition, the distribution system
includes service pipes, meters and regulators, and gas regulating and metering
stations. The mains and feeder lines 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. NW Natural also holds all necessary permits for the crossing of the
Willamette River and a number of smaller rivers by its mains.
NW Natural owns service facilities in Portland, as well as various
satellite service centers, garages, warehouses and other buildings necessary and
useful in the conduct of its business. It leases office space in Portland for
its corporate headquarters. District offices are maintained on owned or leased
premises at convenient points in the distribution system. NW Natural owns LNG
facilities in Portland and near Newport, Oregon.
NW Natural holds interests in 7,816 net acres of underground natural
gas storage and 2,444 net acres of oil and gas leases in Oregon. NW Natural owns
rights to depleted gas reservoirs near Mist, Oregon, that are continuing to be
developed as underground gas storage facilities. It also holds an option to
purchase future storage rights in certain other areas of the Mist gas field.
In order to reduce risks associated with gas leakage in older parts of
its system, NW Natural undertook an accelerated pipe replacement program in the
1980s under which it removed or replaced 100 percent of its cast iron main by
October 2000. In 2001, NW Natural initiated an accelerated pipe replacement
program under which it will reduce the amount of bare steel main in the system.
NW Natural considers all of its properties currently used in its
operations, both owned and leased, to be well maintained, in good operating
condition, and, along with currently planned additions, adequate for its present
and foreseeable future needs.
NW Natural's Mortgage and Deed of Trust constitutes a first mortgage
lien on substantially all of the real property constituting its utility plant.
ITEM 3. LEGAL PROCEEDINGS
Litigation
- ----------
In November 2001, NW Natural commenced a lawsuit, Northwest Natural Gas
Company v. Cascade Resources Corporation and Curry, et. al. (United States
District Court for the District of Oregon, Case No. CV 01-1620 HU), alleging
that the defendants violated obligations regarding the use and disclosure of
confidential information and used such information to solicit and secure
underground gas storage leases in areas of interest to the Company. Among other
remedies, the Company sought to have a constructive trust imposed on such leases
and to require the defendants to assign their interest in such leases to the
Company.
The defendants in this case asserted counterclaims against the Company
alleging that by asserting that the defendants misused confidential information,
the Company improperly interfered with the defendants' business opportunities.
The assertions included claims for violation of antitrust laws for which the
defendants sought $15 million in damages, trebled, plus punitive damages and
attorneys' fees.
In April 2003, NW Natural settled and agreed with Cascade Resources
Corporation and Al Curry (collectively, Cascade) to dismiss their respective
claims. In November 2003, the court denied the motion of Enerfin Resources
Northwest Limited Partnership (Enerfin), a former employer of Al Curry and the
13
remaining defendant in the Action, for Summary Judgment in the case. In January
2004, prior to the scheduled Jan. 20, 2004 trial date, NW Natural and Enerfin
agreed to settle their claims in this case. Although the proposed settlement is
not yet finalized, under its terms, the lawsuit has been tentatively dismissed,
subject to reinstatement should the settlement not be executed by March 15,
2004. Enerfin has agreed to pay NW Natural $465,000, and NW Natural has agreed
to transfer to Enerfin certain oil and gas production rights that were acquired
from Cascade Resources in the settlement of the original claims in this case. In
addition, NW Natural will purchase from Enerfin and its partner certain
interests in two reservoirs in the Mist gas field for $1 million. In the
settlement, Enerfin also has agreed to dismiss its counterclaims against NW
Natural in the Longview Fibre litigation described below.
On Oct. 16, 2003, Longview Fibre Company (Longview) filed suit in
Federal Court (Longview Fibre Company v. Enerfin Resources Northwest Limited
Partnership and Northwest Natural Gas Company (US District Court - Oregon
District)) seeking a declaratory judgment regarding the continuing existence of
a certain oil and gas lease in the Mist gas field between Longview and Enerfin.
NW Natural holds a gas storage lease obtained in the Cascade settlement which
covers the same area and has certain rights relative to oil and gas. In
response, Enerfin has, among other things, filed counterclaims against NW
Natural alleging that NW Natural wrongly interfered with Enerfin's attempts to
continue its oil and gas lease with Longview. Enerfin is seeking punitive
damages of $2 million. NW Natural believes Enerfin's claims are without merit
and expects to defend its rights in this proceeding should the matter not be
settled. In the tentative settlement of the Cascade case referenced above,
Enerfin has agreed to dismiss its claims against NW Natural in this litigation.
The Company is subject to other claims and litigation arising in the
ordinary course of business. Although the final outcome of any legal proceeding
cannot be predicted with certainty, the Company does not expect disposition of
these matters to have a materially adverse effect on the Company's financial
position, results of operations or cash flows.
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 fourth quarter of the year
ended Dec. 31, 2003.
14
PART II
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY
(A) NW Natural's common stock is listed and trades on the New York
Stock Exchange under the symbol "NWN."
The quarterly high and low trades for NW Natural's common stock during
the past two years were as follows:
2003 2002
------------------------- ----------------------
Quarter Ended High Low High Low
- ----------------------------------------------------------------------------
March 31 $28.47 $24.05 $28.50 $24.20
June 30 28.88 24.77 30.30 27.60
September 30 30.10 27.02 30.20 23.46
December 31 31.30 28.51 30.70 25.50
The closing quotations for the common stock on Dec. 31, 2003 and 2002
were, $30.75 and $27.06, respectively.
(B) As of Dec. 31, 2003, there were 9,695 holders of record of the
Company's common stock.
(C) NW Natural has paid quarterly dividends on its common stock in each
year since the stock first was issued to the public in 1951. Annual common
dividend payments have increased each year since 1956. Dividends per share paid
during the past two years were as follows:
Payment Date 2003 2002
------------ ------ ------
February 15 $0.315 $0.315
May 15 0.315 0.315
August 15 0.315 0.315
November 15 0.325 0.315
----- -----
Total per share $1.270 $1.260
====== ======
The amount and timing of dividends payable on the Company's common
stock are within the sole discretion of the Company's Board of Directors. It is
the intention of the Board of Directors to continue to pay cash dividends on the
Company's common stock on a quarterly basis. However, future dividends will be
dependent upon NW Natural's earnings, its financial condition and other factors.
NW Natural's Dividend Reinvestment and Stock Purchase Plan permits
registered owners of common stock to reinvest all or a portion of their
quarterly dividends in additional shares of NW Natural's common stock at the
current market price. Shareholders also may invest cash on a monthly basis, up
to $50,000 per calendar year, in additional shares at the current market price.
During 2003, dividend reinvestments and optional cash investments under the Plan
aggregated $4.9 million and resulted in the issuance of 178,714 shares of common
stock. During the 26 years the Plan has been available, the Company has issued
and sold 4,497,312 shares of common stock which produced $98.0 million in
additional capital.
The Company did not repurchase any of its stock in the fourth quarter
of 2003.
15
ITEM 6. SELECTED FINANCIAL DATA
The following table sets forth selected financial data concerning the Company's
operations and financial condition.
Thousands, except per share amounts and
ratio of earnings to fixed charges 2003 2002 2001 2000 1999
- ------------------------------------------------------------------------------------------------------------------------
Sales revenues:
Residential $ 328,464 $ 354,735 $ 329,905 $ 280,642 $ 242,952
Commercial 176,385 201,475 190,236 159,660 139,425
Industrial - firm 33,578 42,965 49,662 37,378 35,857
Industrial - interruptible 23,661 15,937 34,283 23,483 17,182
Unbilled revenues 14,474 (12,702) 13,774 12,661 (2,671)
----------- ----------- ----------- ----------- -----------
Total gas sales revenues 576,562 602,410 617,860 513,824 432,745
Transportation 17,962 26,020 20,637 21,491 21,351
Other 7,460 4,018 (2,325) (3,976) 1,194
----------- ----------- ----------- ----------- -----------
Total gross utility operating
revenues 601,984 632,448 636,172 531,339 455,290
Cost of gas sold 323,128 353,034 364,699 273,978 212,021
----------- ----------- ----------- ----------- -----------
Net utility operating revenues 278,856 279,414 271,473 257,361 243,269
Net non-utility operating revenues 9,210 8,130 4,538 589 368
----------- ----------- ----------- ----------- -----------
Net operating revenues $ 288,066 $ 287,544 $ 276,011 $ 257,950 $ 243,637
=========== =========== =========== =========== ===========
Net income $ 45,983 $ 43,792 $ 50,187 $ 50,224 $ 45,296
Redeemable preferred and preference
stock dividend requirements 294 2,280 2,401 2,456 2,515
----------- ----------- ----------- ----------- -----------
Earnings applicable to common stock $ 45,689 $ 41,512 $ 47,786 $ 47,768 $ 42,781
=========== =========== =========== =========== ===========
Average common shares outstanding:
Basic 25,741 25,431 25,159 25,183 24,976
Diluted 26,061 25,814 25,612 25,638 25,468
Earnings per share of common stock:
Basic $ 1.77 $ 1.63 $ 1.90 $ 1.90 $ 1.71
Diluted $ 1.76 $ 1.62 $ 1.88 $ 1.88 $ 1.70
Dividends per share of common stock $ 1.27 $ 1.26 $ 1.245 $ 1.24 $ 1.225
=========== =========== =========== =========== ===========
Total assets - at end of period* $ 1,591,332 $ 1,467,277 $ 1,435,022 $ 1,278,713 $ 1,244,423
=========== =========== =========== =========== ===========
Redeemable preferred stock $ - $ 8,250 $ 9,000 $ 9,750 $ 10,564
Redeemable preference stock $ - $ - $ 25,000 $ 25,000 $ 25,000
Long-term debt $ 500,319 $ 445,945 $ 378,377 $ 400,790 $ 396,379
Ratio of earnings to fixed charges** 2.83 2.74 3.01 3.00 2.97
=========== =========== =========== =========== ===========
<FN>
* Certain amounts from prior years have been reclassified to conform, for
comparison purposes, with the current financial statement presentation.
These reclassifications had no impact on prior year consolidated results
of operations.
** Computed using the Securities and Exchange Commission method. For this
purpose, earnings consist of net income before taxes plus fixed charges,
and fixed charges consist of interest on all indebtedness, dividends on
all preferred and preference stock, the amortization of debt expense and
discount or premium, and the estimated interest portion of rentals
charged to income.
</FN>
16
SELECTED FINANCIAL DATA (continued)
Thousands, except per customer and gas per
therm data 2003 2002 2001 2000 1999
- -----------------------------------------------------------------------------------------------------------------------
Capitalization - at end of period
Common stock equity $ 506,316 $ 482,392 $ 468,161 $ 452,309 $ 429,596
Redeemable preference stock - - 25,000 25,000 25,000
Redeemable preferred stock - 8,250 9,000 9,750 10,564
Long-term debt 500,319 445,945 378,377 400,790 396,379
----------- ----------- ----------- ----------- -----------
Total capitalization $ 1,006,635 $ 936,587 $ 880,538 $ 887,849 $ 861,539
=========== =========== =========== =========== ===========
Gas sales and transportation deliveries (000 therms):
Residential 343,534 357,091 350,065 356,375 352,969
Commercial 226,257 240,155 242,293 250,380 252,382
Industrial - firm 55,314 63,215 79,778 76,559 84,630
Industrial - interruptible 47,994 26,241 63,597 56,632 52,938
Unbilled therms 12,099 (6,617) 1,771 8,691 (9,343)
----------- ----------- ----------- ----------- -----------
Total gas sales 685,198 680,085 737,504 748,637 733,576
Transportation 414,554 445,999 385,783 431,136 480,570
----------- ----------- ----------- ----------- -----------
Total volumes delivered 1,099,752 1,126,084 1,123,287 1,179,773 1,214,146
=========== =========== =========== =========== ===========
Customers (average for period):
Residential 510,336 492,871 474,373 456,449 435,959
Commercial 56,504 55,416 54,628 53,617 52,029
Industrial - firm 362 350 377 375 396
Industrial - interruptible 98 74 141 118 118
Transportation 179 190 111 125 127
----------- ----------- ----------- ----------- -----------
Total customers 567,479 548,901 529,630 510,684 488,629
=========== =========== =========== =========== ===========
Customer statistics:
Heat requirements***
Actual degree days 3,952 4,232 4,325 4,418 4,256
25-year average degree days 4,238 4,257 4,267 4,274 4,274
Average annual use per customer in therms:
Residential 673 725 738 781 810
Commercial 4,004 4,334 4,435 4,670 4,851
Gas purchased cost per therm - net (cents) 46.99 51.07 47.19 37.68 27.85
<FN>
*** A degree day is the measure of the coldness of the weather experienced
based on the extent to which the average of the high and low temperatures
for a day falls below 65 degrees Fahrenheit.
</FN>
17
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND
FINANCIAL CONDITION
The following is management's assessment of Northwest Natural Gas
Company's financial condition including the principal factors that affect
results of operations. The discussion refers to the consolidated activities of
the Company for the three years ended Dec. 31, 2003. Unless otherwise indicated,
references in this discussion to "Notes" are to the notes to the consolidated
financial statements.
The consolidated financial statements include:
Regulated utility:
o Northwest Natural Gas Company (NW Natural)
Non-regulated wholly owned subsidiaries of NW Natural:
o NNG Financial Corporation (Financial Corporation), and
its wholly owned subsidiaries
o Northwest Energy Corporation (Northwest Energy), and
its wholly owned subsidiary
Together these businesses are referred to herein as the "Company" (see
"Results of Operations--Non-utility Operations," 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 the Company's earnings and are reported net of tax.
The Company believes this per share information is useful because it enables
readers to better understand the impact of these factors on the Company's
earnings. All references in this report to earnings per share are on the basis
of diluted shares (see Note 1).
Executive Summary
- -----------------
Highlights
----------
Among its accomplishments in 2003, the Company:
o grew its utility customer base by more than 3 percent for
the 17th year in a row, adding 18,083 customers to its gas
distribution system during the year;
o increased earnings from its business segment for interstate
gas storage services from 14 cents a share in 2002 to 17
cents a share in 2003;
o secured a permit for the construction of a major extension
of its pipeline from the Mist storage field to the Portland
metropolitan area and completed the first 11.7-mile segment
of the pipeline extension, below budget and on time for the
2003-04 heating season;
o successfully completed its general rate case in Oregon with
a result that included phased rate increases, the recovery
of costs relating to its gas storage investments and higher
operating expenses, and approval of a new weather
normalization mechanism;
o secured reliable and adequate gas supplies during a time of
volatile wholesale pricing, at costs that required only
relatively small rate increases for customers; and
o paid dividends on common stock of $1.27 a share, making 2003
the 48th consecutive year in which the Company's dividend
payments have increased.
18
Issues, Challenges and Performance Measures
-------------------------------------------
Issues and challenges the Company expects to face in 2004 include the
effects and uncertainties relating to a general rate case in Washington;
volatile gas commodity prices; continuing weak economic conditions in Oregon and
Washington; completion of the remaining portion of the pipeline extension from
NW Natural's Mist gas storage field including the acquisition of rights-of-way
necessary to build the pipeline; and higher capital and operating costs due to
federal mandates in the area of pipeline integrity.
In order to deal with these and other issues affecting the business, in
2003 NW Natural completed a new strategic plan to map the Company's course
during the next several years. The plan includes strategies for further
improving NW Natural's ability to add customers both profitably and at a rapid
pace; maintaining NW Natural's reputation for exemplary service; reducing
business risk; managing all costs, including capital costs; holding all
employees to high performance standards; and judiciously growing beyond the
Company's local distribution business where it would complement core assets and
competencies. Among the key performance measures the Company will use in
monitoring progress against its goals in these areas are utility earnings per
share, customer satisfaction ratings, new customer additions, operations and
maintenance expense per customer, construction cost per meter connected, and
non-revenue producing capital expenditures per customer.
Earnings and Dividends
- ----------------------
The Company's earnings applicable to common stock in 2003 were $45.7
million, compared to $41.5 million in 2002 and $47.8 million in 2001. Earnings
were $1.76 a share in 2003, compared to $1.62 a share in 2002 and $1.88 a share
in 2001.
Net operating revenues in 2003 were about the same as in 2002, but
higher amounts for other income ($17 million) in 2003 more than offset higher
operating expenses ($14.5 million). Earnings for 2002 were reduced by charges of
$13.9 million (before tax) representing the Company's transaction costs incurred
in its efforts to acquire Portland General Electric Company (PGE) from Enron.
Excluding these charges, earnings per share from consolidated operations in 2002
would have been $1.95 a share. Earnings for 2001 were the highest on record for
the Company.
NW Natural earned $1.57 a diluted share from gas utility operations in
2003, compared to $1.76 a share in both 2002 and 2001. Weather conditions in its
service territory in 2003 were 7 percent warmer than the 25-year average and 7
percent warmer than 2002. Temperatures in 2002 were very close to average but
were 2 percent warmer than 2001. Weather in 2001 was 1 percent colder than
average.
Results in 2003 from the Company's non-utility operations were earnings
of 19 cents a share, including 17 cents a share from NW Natural's gas storage
business segment and 2 cents a share from subsidiary and other non-utility
operations (see "Results of Operations--Non-utility Operations," below).
Non-utility results for 2002 were a loss of 14 cents a share, including earnings
of 14 cents a share from the gas storage segment, a loss of 33 cents a share
relating to the Company's efforts to purchase PGE, and earnings of 5 cents a
share from other subsidiary and non-utility operations. Non-utility results for
2001 were earnings of 12 cents a share, including 8 cents a share from the gas
storage segment.
For the 48th consecutive year, the Company's dividends paid on common
stock increased in 2003. Dividends paid on common stock were $1.27 a share in
2003 compared to $1.26 a share in 2002 and $1.245 a share in 2001.
Application of Critical Accounting Policies and Estimates
- ---------------------------------------------------------
In preparing the Company's financial statements using generally
accepted accounting principles in the United States of America (GAAP),
management exercises judgment in the selection and application of accounting
19
principles, including making estimates and assumptions that affect reported
amounts of assets, liabilities, revenues, expenses and related disclosures in
the financial statements. Management considers its critical accounting policies
to be those which are most important to the representation of the Company's
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 the Company
reported under different conditions or using different assumptions.
The Company's most critical estimates or judgments involve regulatory
cost recovery, unbilled revenues, derivative instruments, pension assumptions,
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. The Company's critical accounting policies and estimates
are described below.
Regulatory Accounting
---------------------
NW Natural is regulated by the Public Utility Commission of Oregon
(OPUC) and the Washington Utilities and Transportation Commission (WUTC), which
establish rules governing the Company's utility rates and services, and to a
certain extent set forth the accounting treatment for certain regulatory
transactions. In general, NW Natural uses the same accounting principles as
other 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 regulation.
For example, NW Natural accounts for the cost of gas using a deferral and cost
recovery mechanism called the Purchased Gas Adjustment (PGA), which is approved
annually by the OPUC and WUTC (see "Results of Operations--Cost of Gas Sold,"
below). There are other expenses or revenues that the OPUC or WUTC may require
the Company to defer and recover or refund in future periods. SFAS No. 71
requires the Company to account for these types of deferred expenses (or
deferred revenues) as regulatory assets (or regulatory liabilities) on the
balance sheet. When NW Natural is allowed to recover these expenses from or
refund them to customers, it recognizes the expense or revenue on the income
statement at the same time it realizes the adjustment to amounts included in
utility rates and charged to customers.
The conditions a regulated company must satisfy to apply the accounting
policies and practices of SFAS No. 71 include:
o an independent regulator sets rates;
o the regulator sets the rates to cover specific costs of
delivering service; and
o the service territory lacks competitive pressures to reduce rates
below the rates set by the regulator.
NW Natural applies SFAS No. 71 in accounting for its regulated utility
operations. The Company periodically assesses whether it can continue to apply
SFAS No. 71. If NW Natural should determine in the future that all or a portion
of its regulatory assets and liabilities no longer meet the criteria for
continued application of SFAS No. 71, then it would be required to write off the
net unrecoverable balances of its regulatory assets and liabilities as a charge
to income.
Revenue Recognition
-------------------
Utility revenues, derived primarily from the sale and transportation of
natural gas, are recognized when the 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 (unbilled revenues). Unbilled revenues are dependent upon a number of
factors that require management's judgment, including total gas receipts and
deliveries, customer usage patterns and weather. Unbilled revenue estimates are
20
reversed the following month when actual billings occur. NW Natural's unbilled
revenues at Dec. 31, 2003 and 2002 were $59.1 million and $44.1 million,
respectively.
In November 2003, NW Natural implemented a weather normalization
mechanism in Oregon that helps stabilize the Company's net operating revenues by
adjusting current customer billings based on temperature variances from average
weather (see "Results of Operations--Regulatory Matters--Rate Mechanisms,"
below).
Non-utility revenues, derived primarily from gas storage services, are
recognized upon delivery of the service to customers. Revenues from optimization
of excess storage and transportation capacity are recognized over the life of
the contract for guaranteed amounts under the contract, or are recognized as
earned for amounts above the guaranteed value.
Accounting for Derivative Instruments and Hedging Activities
------------------------------------------------------------
The Company's Derivatives Policy sets forth the guidelines for using
selected financial derivative products to support prudent risk management
strategies within designated parameters (see Note 1). The policy specifically
prohibits the use of derivatives for trading or speculative purposes. The
Company's primary hedging activities consist of natural gas commodity price and
foreign currency exchange rate hedges, which are accounted for as cash flow
hedges.
The Company's commodity and foreign currency hedge transactions are
included in the annual PGA mechanism, and as such all gains and losses are
subject to regulatory deferral under SFAS No. 71 (see "Regulatory Accounting,"
above). The following table summarizes the realized gains and losses from NW
Natural's commodity and currency hedge transactions in 2003, 2002 and 2001:
(Thousands) 2003 2002 2001
- ---------------------------------------------------------------------------------------------------------------
Gains (losses) on commodity swap contracts $ 29,660 $ (73,922) $ 44,191
Gains (losses) on commodity option contracts 2,723 (1,601) 13,383
---------- --------- ---------
Subtotal 32,383 (75,523) 57,574
Gains on currency contracts 4,129 521 824
---------- --------- ---------
Total gains (losses) on commodity and currency contracts $ 36,512 $ (75,002) $ 58,398
========== ========= =========
Realized gains (losses) from commodity and foreign currency hedge
contracts are recorded as reductions (increases) to the cost of gas and are
included in the calculation of annual PGA rate changes. Unrealized gains and
losses resulting from mark-to-market valuations are not recognized in current
income or other comprehensive income, but are reported as regulatory liabilities
or regulatory assets, which are offset by a corresponding balance in non-trading
derivative assets or liabilities (see Note 11).
Accounting for Pensions
-----------------------
NW Natural has two qualified non-contributory defined benefit pension
plans covering all regular employees with more than one year of service. These
plans are funded through a trust dedicated to providing retirement benefits. Net
periodic pension costs and accumulated benefit obligations are determined in
accordance with SFAS No. 87, "Employers' Accounting for Pensions" (see
"Financial Condition--Pension Cost (Income) and Funding Status," below, and Note
7), using a number of assumptions including the discount rate, the rate of
compensation increases, retirement ages, mortality rates and expected long-term
return on plan assets. These assumptions have a significant impact on the
amounts reported. NW Natural's pension cost consists of service costs, interest
costs, amortization of actuarial gains and losses, expected returns on plan
assets and, in part, on a market-related valuation of assets. Variances between
21
expected returns and actual investment returns are recognized over a three-year
period from the year in which they occur, thereby reducing year-to-year
volatility.
The Company considers a number of factors in developing its pension
assumptions, including an evaluation of relevant discount rates, expected
long-term returns on plan assets, plan asset allocations, expected changes in
wages and retirement benefits, analyses of current market conditions and input
from actuaries and other consultants. For the Dec. 31, 2003 measurement date,
the Company:
o decreased its discount rate assumption from 6.75 percent to 6.25
percent;
o lowered its salary and wage increase assumption from a range of
4.25-5.00 percent to a range of 4.00-4.75 percent; and
o increased its expected long-term return on plan assets from 8.00
percent to 8.25 percent.
Changes in these factors were the primary contributors to a net increase in the
Company's accumulated benefit obligation from $172 million at Dec. 31, 2002, to
$192 million at Dec. 31, 2003.
The Company believes its pension assumptions to be appropriate based
upon the above factors. However, if the discount rate were changed by
one-quarter percentage point, the net periodic pension cost would be changed by
approximately $0.6 million. If the expected return on plan assets were changed
by one-quarter percentage point, the net periodic pension cost would be changed
by approximately $0.4 million.
Contingencies
-------------
The Company records loss contingencies as liabilities when it is
probable that a liability has been incurred and the amount of the loss is
reasonably estimable. Estimating probable losses requires an analysis of
uncertainties that often depend upon judgments about potential actions by third
parties. In the normal course of business, the Company records accruals for loss
contingencies based on an analysis of potential results, developed in
consultation with outside counsel when appropriate, including allowances for
uncollectible accounts, environmental claims and property damage and personal
injury claims. It is possible, however, that future results of operations could
be materially affected by changes in assumptions or estimates regarding these
contingencies. With respect to environmental claims, the Company records
receivables for anticipated recoveries under insurance contracts, or from future
utility rates, when recovery is probable. See Note 12.
Results of Operations
- ---------------------
Regulatory Matters
------------------
NW Natural provides gas utility service in Oregon and Washington, with
Oregon representing over 90 percent of its revenues. Future earnings and cash
flows from utility operations will be determined largely by the pace of
continued growth in the residential and commercial markets and by NW Natural's
ability to remain price competitive in the large industrial market, to control
expenses, and to obtain reasonable and timely regulatory ratemaking treatment
for investments made in utility plant.
General Rate Cases
------------------
In August 2003, the OPUC entered an order covering all of the issues in
NW Natural's first Oregon general rate case since 1999. The order included,
among other things, (i) the settlement of NW Natural's cost of service,
including operations and maintenance expenses, (ii) projected investments for
the prospective test year, (iii) a capital structure including 49.5 percent
common equity, (iv) a return on common shareholders' equity (ROE) of 10.2
percent, (v) a rate redesign that shifted $4.8 million of margin revenue
22
requirement from industrial rate schedules to residential and commercial rate
schedules, and (vi) the adoption of a weather normalization mechanism. The order
authorized a revenue increase of $13.9 million per year, of which $6.2 million
went into effect on Sept. 1, 2003 and $2.8 million went into effect on a
deferred basis on Nov. 12, 2003 as the first 11.7 miles of the Company's South
Mist Pipeline Extension (SMPE) was placed into service. The remainder will go
into effect as all or portions of the SMPE project and the Company's Coos County
distribution system project are completed and go into service in 2004 (see
"Financial Condition--Investing Activities," below).
NW Natural's most recent general rate increase in Washington, which was
fully effective in October 2001, authorized rates designed to produce an ROE of
10.8 percent. The WUTC approved a revenue increase of $4.3 million per year, or
12.1 percent.
In November 2003, NW Natural filed a new general rate case in
Washington. The filing proposes a revenue increase of $7.9 million per year from
Washington operations through rate increases averaging 15 percent. The proposed
rates are designed to produce an ROE of 11 percent and to recover increases in
NW Natural's cost of service including costs for expansion of the Mist gas
storage system and construction of a new service center in Vancouver; higher
expenses in areas such as pensions, health benefits and insurance; and revenue
declines due to changes in customers' consumption patterns. NW Natural also is
proposing a decoupling mechanism for residential and commercial customers that
includes weather normalization, and a re-design of industrial rates. The
schedule for the case provides for settlement conferences in April 2004, the
filing of WUTC staff and intervenor testimony in May, hearings in July and a
decision by the WUTC determining new rates by the end of October 2004. The
Company is unable to determine the extent to which its proposals will be
accepted by the WUTC.
Rate Mechanisms
---------------
The weather normalization mechanism approved by the OPUC will be
applied to NW Natural's Oregon residential and commercial customers' bills
between Nov. 15 and May 15 of each heating season, beginning November 2003. The
mechanism adjusts the margin component of customers' rates to reflect "normal"
weather using the 25-year average temperature for each day of the billing
period. The mechanism is intended to stabilize the recovery of fixed costs and
reduce fluctuations in customers' bills due to colder- or warmer-than-average
weather.
Rate changes are applied each year under the PGA mechanisms in NW
Natural's tariffs in Oregon and Washington to reflect changes in the costs of
natural gas commodity purchased under contracts with gas producers (see
"Comparison of Gas Operations--Cost of Gas Sold," below), the application of
temporary rate adjustments to amortize balances in regulatory asset or liability
accounts and the removal of temporary rate adjustments effective the previous
year. In 2003, the OPUC approved a rate increase averaging 3.5 percent for
Oregon sales customers and the WUTC approved a rate increase averaging 16.8
percent for Washington sales customers, both effective on Oct. 1, 2003. In 2002,
the OPUC approved PGA rate decreases averaging 14 percent for NW Natural's
Oregon sales customers and the WUTC approved PGA rate decreases averaging 25
percent for NW Natural's Washington sales customers, both effective on Oct. 1,
2002. In 2001, the OPUC approved PGA rate increases averaging 22 percent for
Oregon sales customers and the WUTC approved PGA rate increases averaging 21
percent for Washington sales customers, both effective on Oct. 1, 2001.
In an order issued in 1999, the OPUC formalized a process that tests
for excessive earnings in connection with gas utilities' annual filings under
their PGA mechanisms. The OPUC confirmed NW Natural's ability to pass through
100 percent of its prudently incurred gas costs into rates. Under this order, NW
Natural is authorized to retain all of its earnings up to a threshold level
equal to its authorized ROE plus 300 basis points. One-third of any earnings
above that level will be refunded to customers. The excess earnings threshold is
subject to adjustment up or down each year depending on movements in interest
rates. No amounts were identified in this process for refund to customers with
respect to NW Natural's earnings results in 2002 or 2001. NW Natural does not
23
expect there will be amounts identified for refund with respect to its earnings
in 2003, which will be reviewed by the OPUC in the second quarter of 2004.
In 2002, the OPUC approved a rate mechanism designed to stabilize
margin revenues in the face of above- or below-normal consumption patterns. NW
Natural believes that reductions in recent years in its customers' gas
consumptions per degree-day (see "Comparison of Gas Operations--Residential and
Commercial," below) were caused by increases in the cost of purchased gas that
were passed on to customers as rate increases, and to efforts throughout the
region to conserve energy. The mechanism adjusts for rate changes according to
the impact of price elasticity, starting with small increases to residential and
commercial rates that became effective on Oct. 1, 2002. These rate changes
contributed an estimated $3.5 million of margin, equivalent to 8 cents a share
of earnings, during the fourth quarter of 2002 and an estimated $6.5 million of
margin, equivalent to 15 cents a share of earnings, during the first eight
months of 2003 before the Oregon general rate increase took effect.
In addition, the OPUC authorized NW Natural to implement a partial
decoupling mechanism effective Oct. 1, 2002. Decoupling mechanisms are used to
break the link between a utility's earnings and the energy consumed by its
customers so the utility does not have an incentive to discourage customers'
conservation efforts. The decoupling mechanism works by adding margin revenues
during periods when customer consumptions are lower than baseline consumption or
by deducting margin revenues when consumptions are higher than the baseline.
Under the partial decoupling mechanism, NW Natural uses a balancing account to
defer and subsequently amortize 90 percent of the margin differentials between
baseline usage by its residential and commercial customers and
weather-normalized actual usage by these customers. The deferred amounts are
treated as adjustments to be refunded or collected in future periods. Baseline
consumption is based on customer consumption patterns determined in the Oregon
general rate case, adjusted for consumptions resulting from new customers. The
partial decoupling mechanism will expire at the end of September 2005 unless the
OPUC approves an extension based on the results of an independent study to
measure the mechanism's effectiveness.
In connection with the OPUC's approval of the decoupling mechanism, NW
Natural agreed to adopt certain service quality measures that establish the
Company's performance goal for minimizing complaints by customers where the
Company is determined to be at fault. If NW Natural exceeds the prescribed level
of at-fault complaints, it will be subject to penalties. NW Natural was not
subject to penalties relating to these measures in 2003.
24
Comparison of Gas Operations
----------------------------
The following table summarizes the composition of gas utility volumes
and revenues for the three years ended Dec. 31:
(Thousands, except customers and degree days) 2003 2002 2001
- -------------------------------------------------------------------------------------------------------------------------
Utility gas sales and transportation volumes - therms:
- ------------------------------------------------------
Residential and commercial sales 569,791 597,246 592,358
Unbilled volumes 12,099 (6,617) 1,771
---------- ---------- ----------
Weather-sensitive volumes 581,890 53% 590,629 52% 594,129 53%
Industrial firm sales 55,314 5% 63,215 6% 79,778 7%
Industrial interruptible sales 47,994 4% 26,241 2% 63,597 6%
---------- --- ---------- --- ---------- ---
Total gas sales 685,198 62% 680,085 60% 737,504 66%
Transportation deliveries 414,554 38% 445,999 40% 385,783 34%
---------- --- ---------- --- ---------- ---
Total volumes sold and delivered 1,099,752 100% 1,126,084 100% 1,123,287 100%
========== === ========== === ========== ===
Utility operating revenues - dollars:
- -------------------------------------
Residential and commercial sales $ 504,849 $ 556,210 $ 520,141
Unbilled revenues 14,474 (12,702) 13,774
---------- ---------- ----------
Weather-sensitive revenues 519,323 86% 543,508 86% 533,915 84%
Industrial firm sales 33,578 6% 42,965 7% 49,662 8%
Industrial interruptible sales 23,661 4% 15,937 2% 34,283 5%
---------- --- ---------- --- ---------- ---
Total gas sales 576,562 96% 602,410 95% 617,860 97%
Transportation revenues 17,962 3% 26,020 4% 20,637 3%
Other revenues 7,460 1% 4,018 1% (2,325) -
---------- --- ---------- --- --------- ---
Total utility operating revenues $ 601,984 100% $ 632,448 100% $ 636,172 100%
========== === ========== === ========== ===
Cost of gas sold $ 323,128 $ 353,034 $ 364,699
========== ========== ==========
Utility net operating revenues (margin) $ 278,856 $ 279,414 $ 271,473
========== ========== ==========
Total number of customers (end of period) 578,150 560,067 540,931
========== ========== ==========
Actual degree days 3,952 4,232 4,325
========== ========== ==========
25-year average degree days 4,238 4,257 4,267
========== ========== ==========
NW Natural refunded deferred gas cost savings to its Oregon customers
through billing credits in June 2002. These refunds were the customers' 67
percent portion of gas cost savings realized between October 2001 and March
2002, which had been deferred, with interest, pursuant to NW Natural's PGA
tariff in Oregon (see "Cost of Gas Sold," below). The refunds reduced gross
operating revenues during 2002 by $30.4 million, and reduced both cost of gas
and deferred gas costs payable by $29.5 million. The refunds also reduced margin
by about $0.9 million, but this amount was almost entirely offset by
corresponding reductions in franchise tax expense and uncollectible accounts
expense such that the effect of the refunds on net income was negligible.
25
Residential and Commercial Sales
--------------------------------
NW Natural continued to grow its customer base, with a net increase of
18,083 customers during 2003. This represents a growth rate of 3.2 percent,
compared to 3.5 percent in 2002 and 3.3 percent in 2001. In the three years
ended Dec. 31, 2003, more than 54,000 customers were added to the system,
representing an average annual growth rate of 3.5 percent.
The volumes of gas sold to residential and commercial customers were 1
percent lower in 2003 than in 2002, reflecting warmer weather that was partially
offset by customer growth and the price elasticity effects of lower rates.
Related revenues were 4 percent lower in 2003 than in 2002. Excluding the impact
of gas cost refunds totaling $30.4 million to Oregon customers during 2002,
related revenues were $54.6 million, or 10 percent, lower in 2003 than in 2002,
primarily due to lower rates effective Oct. 1, 2002 (see "Regulatory
Matters--Rate Mechanisms," above). The volumes of gas sold to residential and
commercial customers were 1 percent lower in 2002 than in 2001, reflecting
warmer weather as well as lower consumption patterns by customers due to higher
gas commodity prices included in rates in previous years. Excluding the impact
of the refunds to Oregon customers during 2002, related revenues increased 7
percent, primarily due to PGA rate increases effective Oct. 1, 2001.
Typically, 80 percent or more of NW Natural's annual operating revenues
are derived from gas sales to weather-sensitive residential and commercial
customers. Accordingly, variations in temperatures between periods will affect
volumes of gas sold to these customers. Weather conditions in 2003 were 7
percent warmer than average. Temperatures were very close to average in 2002 and
1 percent colder than average in 2001. Weather in 2003 was 7 percent warmer than
2002 and 2002 was 2 percent warmer than 2001. Average weather conditions are
calculated from the most recent 25 years of temperature data measured by heating
degree-days.
In November 2003, NW Natural implemented a weather normalization
mechanism that will be applied to Oregon residential and commercial customers'
bills between Nov. 15 and May 15 of each heating season (see "Regulatory
Matters--Rate Mechanisms," above). Customers may opt out of the mechanism during
a defined period each year; less than 10 percent of NW Natural's Oregon
residential and commercial customers opted out during its first heating season.
The mechanism contributed $2.1 million of margin in the fourth quarter of 2003
due to warmer-than-average weather. The contribution was equivalent to 5 cents a
share of earnings, making up a significant portion of the weather-related margin
loss in that quarter.
In order to match revenues with related purchased gas costs, NW Natural
records unbilled revenues for gas delivered and sold to customers, but not yet
billed, through the end of the period. Amounts reported as unbilled revenues
reflect the increase or decrease in the balance of unbilled revenues over the
prior year-end. Weather conditions, rate changes and customer billing dates from
one period to the next affect year-end balances.
26
Industrial Sales and Transportation
-----------------------------------
The following table summarizes the delivered volumes and utility net
operating revenues (margin) in the industrial and electric generation markets:
(Thousands) 2003 2002 2001
-----------------------------------------------------------------------------------------------
Delivered volumes - therms:
----------------------------
Industrial sales and transportation 519,265 531,195 486,116
Electric generation 1,667 3,400 42,867
--------- --------- ---------
Total volumes 520,932 534,595 528,983
========= ========= =========
Utility net operating revenues - dollars:
------------------------------------------
Industrial sales and transportation $ 37,693 $ 40,666 $ 43,251
Electric generation 6 4,584 4,721
--------- --------- ---------
Total margin $ 37,699 $ 45,250 $ 47,972
========= ========= =========
Total volumes delivered to industrial and electric generation customers
were 3 percent lower in 2003 than in 2002, and 1 percent higher in 2002 than in
2001. Combined margins from these customers were 17 percent lower in 2003 than
in 2002 and 6 percent lower in 2002 than in 2001.
Excluding electric generation customers, volumes delivered to end-use
industrial sales and transportation customers were 2 percent lower and margin
was 7 percent lower in 2003 than in 2002. Results from the industrial market in
2003 reflect weak economic conditions during the year, as well as some
cost-related changes in the design of industrial rates in the Oregon general
rate case that reduced industrial margins in the fourth quarter. Volumes
delivered to industrial customers were 9 percent higher in 2002 than in 2001,
but margin was 6 percent lower. The decline in margin from these customers in
2002 was due to migrations of some industrial customers from higher margin firm
service to lower margin interruptible service and to plant shutdowns or cutbacks
in the manufacturing sector because of economic conditions. NW Natural
re-designed its industrial rates in Oregon as part of its general rate case in
2003, transferring $4.8 million of annual revenue requirement from industrial
rates to residential and commercial rates in order to better reflect relative
costs of service and to become more competitive in the industrial market.
In the electric generation market, margin was negligible in 2003 but
was $4.6 million and $4.7 million in 2002 and 2001, respectively, equivalent to
11 cents a share in each year. More than 90 percent of the margin, but only
about 14 percent of the gas deliveries, in 2002 and 2001 was from two customers
that were served under contracts that went into effect in the second half of
2001 and expired at the end of the second quarter of 2002. Most of the margin
from these contracts was from fixed charges. A third electric generation
customer used 3.0 million therms in 2002 and 36.8 million therms in 2001 under
contracts with low volumetric charges.
Other Revenues
--------------
Other revenues include revenues and revenue adjustments from sources
other than the sale and transportation of gas (see Note 1), including deferrals
to and amortizations from regulatory asset and liability accounts and
miscellaneous customer fees. In 2003, other revenues contributed $7.5 million to
utility operating revenues compared to $4.0 million in 2002 and a negative $2.3
million in 2001.
Other revenues in 2003 included positive contributions due to
amortizations of regulatory accounts covering customer consumption under NW
Natural's decoupling mechanism (see "Regulatory Matters--Rate Mechanisms,"
above), amortizations of income shared with customers from interstate gas
storage services, and customer late payment and collection fees and
miscellaneous revenues, partially offset by amortizations from regulatory
accounts covering conservation programs and Year 2000 costs.
27
The following table summarizes other revenues by primary category in
2003, 2002 and 2001:
(Thousands) 2003 2002 2001
- --------------------------------------------------------------------------
Rate adjustments:
Decoupling deferrals $ 3,466 $ 1,720 $ --
Decoupling amortizations (783) -- --
Interstate storage amortization 3,057 1,212 --
Conservation programs amortization (2,408) (2,074) (4,941)
Year 2000 amortization (949) (1,539) (1,236)
Miscellaneous revenues:
Customer fees 2,919 3,115 2,991
Other 2,158 1,584 861
-------- -------- ---------
Total other revenues $ 7,460 $ 4,018 $ (2,325)
======== ======== =========
Cost of Gas Sold
----------------
Natural gas commodity prices have fluctuated dramatically in recent
years. NW Natural has sought to mitigate the effect of higher gas commodity
prices and price volatility on core utility customers through the use of its
underground storage facilities, by entering into gas commodity-based financial
hedge contracts, and by making short-term sales of gas commodity and
transportation capacity to on-system or off-system customers in periods when
core utility customers do not fully utilize firm pipeline capacity and gas
supplies.
In 2003, the Company replaced all of its expiring long-term contracts
with supply contracts for gas purchases of similar aggregate volume levels. All
of the new contracts have terms of five years or less and contain commodity
price provisions that are tied directly to monthly market index prices for the
term of the contract. The Company enters into financial hedge contracts that are
intended to have the effect of converting these monthly market index prices into
fixed prices for most of its gas purchases under these contracts.
The cost per therm of gas sold was 9 percent lower in 2003 than in
2002, and 5 percent higher in 2002 than in 2001. The cost per therm of gas sold
includes current gas purchases, gas drawn from storage inventory, gains or
losses from commodity hedges, margin from off-system gas sales, demand cost
balancing adjustments (demand equalization), regulatory deferrals and company
use. Results for 2002 included an adjustment that reduced cost of gas by $29.5
million (see "Comparison of Gas Operations," above). Excluding this adjustment,
cost per therm of gas sold was 16 percent lower in 2003 than in 2002, reflecting
decreases in gas commodity prices effective in late 2002, and 14 percent higher
in 2002 than in 2001, reflecting increases in gas commodity prices effective in
late 2001.
Results for 2002 also included adjustments reducing cost of gas
relating to amounts of deferred expenses for the recovery of pipeline demand
charges under NW Natural's PGA mechanism. These adjustments contributed 7 cents
a share to earnings in 2002, of which 6 cents a share applied to periods prior
to 2002. The rate methodology represented in the adjustments continues to be
applied in the Company's accounting for pipeline demand charges.
NW Natural's recorded amount of unaccounted-for gas was 0.55 percent of
gas sendout in 2003, compared to 0.75 percent in 2002. Unaccounted-for gas is
the difference between the amount of gas the Company receives from all sources,
28
including pipeline deliveries and withdrawals from storage, and the amount of
gas it delivers to customers or other delivery points. Unaccounted-for gas may
be caused in part by physical gas leakage, but it also may be due to cumulative
inaccuracies in gas metering, estimates of unbilled gas or other causes. NW
Natural considers a normal amount of unaccounted-for gas to be 0.50 percent of
its total gas sendout during a period, but the amount may vary within a range
around this estimate. During 2003, the lower estimated amount of unaccounted-for
gas had the effect of reducing cost of gas and increasing margin by $1.2 million
as compared to 2002.
NW Natural uses a natural gas commodity-price hedge program under the
terms of its Derivatives Policy to help manage its variable price gas commodity
contracts (see "Application of Critical Accounting Policies and
Estimates--Accounting for Derivative Instruments and Hedging Activities,"
above). NW Natural recorded net hedging gains of $32.4 million from this program
during 2003, compared to net hedging losses of $75.5 million in 2002 and net
hedging gains of $57.6 million in 2001, with negligible impact on net income in
any of those years. Hedging gains and losses relating to gas commodity purchases
are included in cost of gas and factored into NW Natural's annual PGA rate
adjustments.
Under NW Natural's PGA tariff in Oregon, net income from Oregon
operations is affected within defined limits by changes in purchased gas costs.
NW Natural is allowed to collect an amount for purchased gas costs based on
estimates that are included in current utility rates. If the actual purchased
gas costs are higher than the amounts included in rates, NW Natural is not
allowed to charge its customers currently for those higher gas costs but is
allowed to defer the costs and collect them in the future. Similarly, when the
actual purchased gas costs are lower than the amount included in rates, the
savings are not immediately passed on to customers but are deferred and refunded
in future periods. NW Natural absorbs 33 percent of the higher cost of gas sold,
or retains 33 percent of the lower cost, in either case as compared to the
projected costs built into rates. The remaining 67 percent of the higher or
lower gas costs is recorded as deferred regulatory assets or liabilities for
recovery from or refund to customers in future rates. NW Natural's gas costs in
2003 were slightly lower than the gas costs embedded in rates, with the effect
that NW Natural's share of the lower costs increased margin by $0.3 million,
equivalent to less than 1 cent a share of earnings. In 2002 and 2001, NW
Natural's gas costs were much lower than the projected costs built into rates
and the Company's share of the savings realized from gas purchases contributed
$10.8 million and $4.1 million of margin, equivalent to 26 cents a share and 10
cents a share of earnings, respectively.
Due to the warm weather and the reduced gas requirements of its
industrial sales customers during 2003, NW Natural was able to use gas supplies
that were under contract for the winter season, but were not required for
delivery to core market customers, to make off-system gas sales. The Company's
purchase prices for this gas had been locked in through commodity swap and call
option agreements entered into in the prior year at levels lower than market
prices during 2003. Under the PGA tariff, the margin from these sales is treated
as a reduction to cost of gas, with the effect that 67 percent is deferred for
refund to NW Natural's customers and the remaining 33 percent is retained by the
Company. NW Natural's share of the margin from off-system gas sales in 2003 was
$4.9 million, equivalent to 11 cents a share of earnings, compared to margin of
$0.9 million or 2 cents a share of earnings in 2002 and margin of $1.0 million
or 2 cents a share of earnings in 2001.
Non-utility Operations
----------------------
At Dec. 31, 2003 and 2002, the Company's non-utility operations
consisted of gas storage operations and two wholly-owned subsidiaries, Financial
Corporation and Northwest Energy. Of the subsidiaries, only Financial
Corporation had active operations during 2002 and 2003.
Gas Storage
-----------
NW Natural realized net income from its non-utility gas storage
business segment in 2003, after regulatory sharing and income taxes, of $4.3
million or 17 cents a share, compared to $3.6 million or 14 cents a share in
2002 and $2.1 million or 8 cents a share in 2001.
29
Gas storage services include sales to off-system interstate customers
using storage capacity that has been developed in advance of core utility
customers' requirements. NW Natural retains 80 percent of the income before tax
from gas storage services and credits the remaining 20 percent to a deferred
regulatory account for distribution to its core utility customers.
Results for the gas storage business segment also include revenues, net
of amounts shared with core utility customers, from a contract with an
independent energy trading company that seeks to optimize the use of NW
Natural's assets by trading temporarily unused portions of its gas storage
capacity and upstream pipeline transportation capacity. NW Natural retains 80
percent of the pre-tax income from the optimization of storage and pipeline
transportation capacity when the costs of such capacity have not been included
in core utility rates, or 33 percent of the pre-tax income from such capacity
when the costs have been included in core utility rates. The remaining 20
percent and 67 percent, respectively, are credited to a deferred regulatory
account for distribution to NW Natural's core utility customers.
Financial Corporation
---------------------
Financial Corporation's operating results in 2003 were net income of
$0.7 million, compared to $1.2 million in 2002 and $0.7 million in 2001. The
decrease in net income in 2003 compared to 2002 was primarily due to lower
income from investments in limited partnerships in wind and solar electric
generation projects in California, and lower miscellaneous receivables. The
increase in net income in 2002 compared to 2001 was due to higher income from
these investments. The Company's investment in Financial Corporation at Dec. 31,
2003, was $5.5 million, compared to $9.1 million and $7.9 million at Dec. 31,
2002 and 2001, respectively. The reduced investment in Financial Corporation at
Dec. 31, 2003, was primarily due to a $4.2 million cash dividend that Financial
Corporation paid to NW Natural in the fourth quarter of 2003.
Northwest Energy
----------------
Northwest Energy was formed in 2001 to serve as the holding company for
NW Natural and PGE if the acquisition of PGE had been completed. Northwest
Energy recorded nominal expenses for corporate development activities in 2003.
Upon the termination of the proposed acquisition effort in 2002, Northwest
Energy recorded a loss totaling $8.4 million (after tax) for the transaction
costs incurred in connection with this effort. These charges were equivalent to
33 cents a share.
Operating Expenses
------------------
Operations and Maintenance
--------------------------
Operations and maintenance expenses of $96.4 million in 2003 were $11.3
million, or 13 percent, higher than in 2002. The increase was primarily due to
higher operating payroll costs from added positions and wage, salary, vacation
and bonus increases ($4.1 million), higher pension costs including the impact of
changes in actuarial assumptions ($3.1 million) (see "Financial
Condition--Pension Cost (Income) and Funding Status," below), higher premiums
for health care and prescription drug coverage ($0.9 million), higher renewal
premiums on business risk insurance ($0.9 million), higher employee benefit
costs ($0.8 million), higher professional services fees ($0.7 million), and
higher expenses relating to workers compensation ($0.5 million) and other
operating costs ($1.2 million). These cost increases were partially offset by a
decrease in uncollectible accounts expense ($0.9 million) due to lower net
write-offs of accounts receivable compared to 2002, when customer bills and
subsequent write-offs were impacted by higher gas prices and colder weather.
Most of the cost increases NW Natural experienced in 2003 were recognized in the
rate increases resulting from the Company's general rate case in Oregon (see
"Regulatory Matters--General Rate Cases," above).
30
Operations and maintenance expenses of $85.1 million in 2002 were $1.2
million, or 1 percent, higher than in 2001. The increase in 2002 resulted
primarily from higher pension costs ($2.5 million), higher premiums for health
care and prescription drug coverage ($1.0 million), higher payroll costs due to
wage and salary increases and incentive bonus accruals ($0.8 million) and higher
renewal premiums on business risk insurance ($0.3 million), partially offset by
a litigation reserve in 2001 ($1.7 million), lower information technology
expenses ($1.0 million) and lower uncollectible accounts expense ($0.5 million).
Taxes Other Than Income Taxes
-----------------------------
Taxes other than income taxes, which are principally comprised of
property, franchise and payroll taxes, increased $1.0 million, or 3 percent, in
2003 over 2002. Property taxes increased $0.9 million, or 7 percent, due to
utility plant additions and slightly higher property tax rates. Franchise taxes,
regulatory fees and payroll tax expenses accounted for the remaining $0.1
million increase.
In 2002, taxes other than income taxes increased $1.8 million, or 6
percent, over 2001. Property taxes increased $1.6 million, or 13 percent, due to
utility plant additions and higher property tax rates.
Depreciation and Amortization
-----------------------------
The following table summarizes the increases in total plant and
property and total depreciation and amortization for the three years ended Dec.
31, 2003:
(Thousands) 2003 2002 2001
------------------------------------------------------------------------------------------------------
Plant and property:
Utility plant:
Depreciable $ 1,598,485 $ 1,498,903 $ 1,434,009
Non-depreciable, including
construction work in progress 60,604 41,062 31,070
----------- ----------- ------------
1,659,089 1,539,965 1,465,079
----------- ----------- ------------
Non-utility property:
Depreciable 22,353 20,832 18,203
Non-depreciable, including
construction work in progress 1,042 -- --
----------- ----------- ------------
23,395 20,832 18,203
----------- ----------- ------------
Total plant and property $ 1,682,484 $ 1,560,797 $ 1,483,282
=========== =========== ============
Depreciation and amortization:
Utility plant $ 53,798 $ 51,693 $ 49,413
Non-utility property 451 397 227
----------- ----------- ------------
Total depreciation and amortization expense $ 54,249 $ 52,090 $ 49,640
=========== =========== ============
Average depreciation rate 3.5% 3.5% 3.5%
=========== =========== ============
31
The Company's total depreciation and amortization expense increased by
$2.2 million, or 4 percent, in 2003 and by $2.5 million, or 5 percent, in 2002.
The increased expense for both years is primarily due to additional investments
in utility property that were made to meet continuing customer growth and to
expand the use of the Company's Mist gas storage system (see "Financial
Condition--Cash Flows--Investing Activities," below).
As a percentage of average depreciable plant and property, both total
depreciation and amortization expense and utility depreciation and amortization
expense was 3.5 percent in each of 2003, 2002 and 2001. Non-utility depreciation
and amortization expense as a percentage of average depreciable non-utility
property was 2.1 percent in 2003, 2.0 percent in 2002 and 1.7 percent in 2001.
Other Income (Expense)
----------------------
Other income (expense) improved by $17.0 million in 2003, primarily due
to the $13.9 million pre-tax charge for costs incurred in 2002 for the effort to
acquire PGE. Excluding this charge, the Company's other income (expense)
increased by $3.1 million in 2003. The increase was primarily due to reductions
in interest charges on deferred regulatory account balances ($1.4 million)
reflecting lower net credit balances outstanding in these accounts, and an
increase in gains from Company-owned life insurance ($2.0 million) due to
increases in market value of equity-based life insurance investments, partially
offset by a decrease in earnings from equity investments ($0.5 million) due to
lower income from partnership investments held by Financial Corporation.
Other income (expense) decreased $16.2 million in 2002 compared to
2001, primarily due to the $13.9 million charge relating to PGE transaction
costs. Excluding this charge, other income (expense) decreased $2.3 million in
2002, primarily due to higher interest accrued on deferred regulatory account
balances ($2.6 million), an increase in miscellaneous non-operating expenses
($0.6 million) and a decrease in miscellaneous non-operating income ($0.3
million), partially offset by an increase in earnings from Financial
Corporation's investments ($1.3 million).
Interest Charges - Net
----------------------
The Company's net interest expense in 2003 was $1.0 million, or 3
percent, higher than in 2002. Interest expense in 2003 included dividends paid
in the second half of 2003 totaling $0.2 million on the Company's redeemable
preferred stock, which were classified as interest expense upon the adoption of
SFAS No. 150 (see Note 1). The increase in interest expense in 2003 was
primarily due to higher balances of debt outstanding during the period. The
increase was partially offset by lower average interest rates and higher amounts
of Allowance for Funds Used During Construction (AFUDC) due to higher average
balances of construction work in progress (CWIP).
The Company's net interest expense in 2002 was $0.3 million,
or 1 percent, higher than in 2001, also due to higher balances of debt
outstanding.
AFUDC represents the cost of funds used for construction work in
progress (see Note 1). In 2003, AFUDC reduced interest expense by $0.9 million
compared to reductions of $0.6 million in 2002 and $1.0 million in 2001. The
average interest rate component of AFUDC, comprised of short-term and long-term
borrowing rates, as appropriate, was 2.3 percent in 2003, 2.8 percent in 2002
and 6.2 percent in 2001.
Income Taxes
------------
The effective corporate income tax rates were 33.7 percent and 34.9
percent for the years ended Dec. 31, 2003 and 2002, respectively. The lower tax
rate for 2003 reflects increased tax benefits from a non-taxable gain on
Company- and trust-owned life insurance. Excluding these benefits, the effective
tax rate for 2003 would have been 35.0 percent. The tax rate for 2002 includes
32
the effect of the tax benefit from the $13.9 million charge for PGE transaction
costs. Excluding this charge, the effective tax rate for 2002 would have been
35.6 percent compared to 35.4 percent for 2001 (see Note 8).
Redeemable Preferred and Preference Stock Dividend Requirements
---------------------------------------------------------------
Redeemable preferred and preference stock dividend requirements
decreased $2.0 million in 2003. In November 2003, NW Natural redeemed all of the
outstanding shares of its $7.125 Series of Redeemable Preferred Stock with an
aggregate stated value of $7.5 million at the applicable early redemption price
of 102.375 percent. In December 2002, NW Natural redeemed all 250,000
outstanding shares ($25 million aggregate stated value) of its $6.95 Series of
Redeemable Preference Stock pursuant to the mandatory redemption provisions
applicable to that Series. Dividend requirements for the preferred and
preference stock decreased by $0.1 million in both 2002 and 2001 due to annual
sinking fund redemptions. At Dec. 31, 2003, no shares of redeemable preferred or
preference stock were outstanding.
Financial Condition
- -------------------
Capital Structure
-----------------
The Company's goal is to maintain a capital structure comprised of 45
to 50 percent common stock equity, up to 5 percent preferred stock and 45 to 50
percent short-term and long-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 meet long-term debt and
preferred stock redemption requirements and to pay down outstanding commercial
paper (see "Liquidity and Capital Resources," below, and Notes 3 and 5).
Liquidity and Capital Resources
-------------------------------
At Dec. 31, 2003, the Company had $4.7 million in cash and cash
equivalents compared to $7.3 million at Dec. 31, 2002. Short-term liquidity is
provided by cash from operations and from the sale of commercial paper notes,
which are supported by commercial bank lines of credit. The Company has
available through Sept. 30, 2004, committed lines of credit with four commercial
banks (see "Lines of Credit," below, and Note 6).
NW Natural's capital expenditures are primarily related to utility
construction resulting from customer growth and system improvements (see "Cash
Flows--Investing Activities," below). In addition, NW Natural has certain
contractual commitments under capital leases, operating leases and gas supply
purchase and other contracts that require an adequate source of funding. These
capital and contractual expenditures 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.
In October 2002, the Company filed a registration statement with the
Securities and Exchange Commission (SEC) registering $150 million of Medium-Term
Notes, Series B (MTNs). This filing became effective in January 2003. Pursuant
to this registration statement, during 2003 the Company issued $90 million of
MTNs and used the proceeds to pay down outstanding commercial paper balances and
to fund, in part, NW Natural's ongoing utility construction program (see
"Financing Activities," below). In February 2004, the Company filed a universal
shelf registration statement with the SEC for the registration of $200 million
of securities, which may include First Mortgage Bonds, unsecured debt, preferred
stock and common stock. Concurrent with the February 2004 shelf filing, the
Company withdrew from registration the $60 million of MTNs remaining on its
previous shelf registration. The $200 million universal shelf registration
statement became effective in February 2004.
Neither NW Natural's Mortgage and Deed of Trust nor the indentures
under which other long-term debt is issued contain credit rating triggers or
stock price provisions that require the acceleration of debt repayment. Also,
33
there are no rating triggers or stock price provisions contained in contracts or
other agreements with third parties, except for agreements with certain
counter-parties under NW Natural's Derivatives Policy which require the affected
party to provide substitute collateral such as cash, guaranty or letter of
credit if credit ratings are lowered to non-investment grade, or in some cases
if the mark-to-market value exceeds a certain threshold.
Off-Balance Sheet Arrangements
------------------------------
The Company has no material off-balance sheet financing arrangements.
Contractual Obligations
-----------------------
The following table shows the Company's contractual obligations by
maturity and type of obligation. NW Natural also has obligations with respect to
its pension and post-retirement medical benefit plans (see Note 7).
(Thousands) Payments Due in Years Ending Dec. 31,
------------------------------------------------------------
2004 2005 2006 2007 2008 Thereafter Total
- --------------------------------------------------------------------------------------------------------------------
Commercial paper $ 85,200 $ - $ - $ - $ - $ - $ 85,200
Long-term debt - 15,000 8,000 29,500 5,000 442,819 500,319
Capital leases 125 114 81 15 - - 335
Operating leases 4,289 3,767 3,754 3,686 3,626 55,326 74,448
Gas supply commitments 52,515 56,759 53,991 53,991 52,463 294,464 564,183
SMPE commitments 22,696 - - - - - 22,696
Other purchase commitments 14,330 95 - - - - 14,425
-------------------------------------------------------------------------------------
Total $ 179,155 $ 75,735 $ 65,826 $ 87,192 $ 61,089 $ 792,609 $ 1,261,606
=====================================================================================
SMPE commitments in 2004 primarily consist of obligations NW Natural
has to a general contractor to complete the construction of the remaining
portion of the SMPE project. A construction contract is in place for one segment
of the pipeline and an additional contract is currently being negotiated for the
remainder of the project. 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 certain MTNs have put options that, if exercised, would
accelerate the maturity of long-term debt by $10 million in 2005, $20 million in
2007 and $20 million in 2008.
Commercial Paper
----------------
The Company's primary source of short-term funds is commercial paper
notes payable. Both NW Natural and Financial Corporation issue commercial paper
under agency agreements with a commercial bank. NW Natural's commercial paper is
supported by its committed bank lines of credit (see "Lines of Credit," below),
while Financial Corporation's commercial paper is supported by committed bank
lines of credit and the guaranty of NW Natural (see Note 6). NW Natural had
$85.2 million in commercial paper notes outstanding at Dec. 31, 2003, compared
to $69.8 million outstanding at Dec. 31, 2002. Financial Corporation had no
commercial paper notes outstanding at Dec. 31, 2003 or 2002.
34
Lines of Credit
---------------
NW Natural has lines of credit with four commercial banks totaling $150
million. Half of the credit facility with each bank, totaling $75 million, is
committed and available through Sept. 30, 2004, and the other $75 million is
committed and available through Sept. 30, 2005. NW Natural may be unable to draw
upon the two-year portions of the credit lines, totaling $75 million, until
filings are made or approvals received from the OPUC or the WUTC with respect to
its notes relating to the two-year commitments. NW Natural expects that it will
be able to make the necessary filings or secure such approvals, if required.
In addition, Financial Corporation has available through Sept. 30,
2004, committed lines of credit with two commercial banks totaling $10 million.
Financial Corporation's lines are supported by the guaranty of NW Natural.
Under the terms of these lines of credit, NW Natural and Financial
Corporation pay commitment fees but are not required to maintain compensating
bank balances. The interest rates on borrowings under these lines of credit, if
any, are based on current market rates. There were no outstanding balances on
either the NW Natural or Financial Corporation lines of credit at Dec. 31, 2003
or 2002.
NW Natural's lines of credit require that credit ratings be maintained
in effect at all times and that notice be given of any change in its senior
unsecured debt ratings. A change in NW Natural's credit rating is not an event
of default, nor is the maintenance of a specific minimum level of credit rating
a condition to drawing upon the lines of credit. However, interest rates on any
loans outstanding under NW Natural's bank lines are tied to credit ratings,
which would increase or decrease the cost of bank debt, if any, when ratings are
changed.
The lines of credit require the Company to maintain an indebtedness to
total capitalization ratio of 65 percent or less and to maintain a consolidated
net worth at least equal to 80 percent of its net worth at Sept. 30, 2003, plus
50 percent of the Company's net income for each subsequent fiscal quarter.
Failure to comply with either of these covenants would entitle the banks to
terminate their lending commitments and to accelerate the maturity of all
amounts outstanding. The Company was in compliance with both of these covenants
at Dec. 31, 2003, and with the equivalent covenants in the prior year's lines of
credit at Dec. 31, 2002.
Optional Redemptions of Long-Term Debt and Redeemable Preferred Stock
---------------------------------------------------------------------
In 2003, the Company exercised early redemption provisions applicable
to certain of its long-term debt, including all $4 million of the 7.50% Series B
MTNs due 2023, all $11 million of the 7.52% Series B MTNs due 2023, and all $20
million of the 7.25% Series B MTNs due 2023. These MTNs were redeemed in the
third quarter of 2003 at 103.75 percent, 103.76 percent and 103.65 percent of
their respective principal amounts. In the fourth quarter of 2003, the Company
also exercised early redemption provisions applicable to all of the remaining
shares of its $7.125 Series of Redeemable Preferred Stock with an aggregate
stated value of $7.5 million, at a redemption price equivalent to 102.375
percent. The Company redeemed the MTNs and the preferred stock with available
cash or with the proceeds from sales of commercial paper, and re-financed this
long-term debt and preferred stock through the sale of new long-term debt in the
fourth quarter of 2003. Early redemption premiums are recognized as unamortized
costs on debt redemptions pursuant to SFAS No. 71 and are amortized to expense
over the life of the new debt.
35
Cash Flows
----------
Operating Activities
--------------------
Operations provided net cash of $107 million in 2003 compared to $124
million in 2002. The 14 percent decrease was due to a decrease in cash from
operations before working capital changes ($19 million), partially offset by an
increase in working capital ($2.1 million). The decrease in cash from operations
before working capital changes compared to 2002 was primarily due to non-cash
adjustments to net income in 2002, including the loss recorded for PGE costs
($13.9 million), combined with a decrease in other assets and liabilities ($27.2
million) compared to an increase in 2002, and a decrease in deferred gas costs
($5.6 million), partially offset by an adjustment to reverse the minimum pension
liability recorded in 2002 ($5.0 million), a larger increase in deferred income
taxes and investment tax credits ($18.7 million), higher net income from
operations ($2.2 million) and higher depreciation and amortization ($2.2
million). The increase in working capital was primarily due to an increase in
accrued interest and taxes compared to a decrease in 2002 ($25.9 million), a
decrease in inventories compared to an increase in 2002 ($15.9 million), a
larger increase in accounts payable ($7.9 million) and a larger decrease in
other current assets and liabilities ($4.4 million), partially offset by
increases in accounts receivable ($23.1 million) and in accrued unbilled revenue
($28.7 million), in both cases compared to decreases in 2002.
NW Natural's refunds to customers of approximately $30.4 million of
deferred gas cost savings in 2002 (see "Results of Operations - Comparison of
Gas Operations," above) reduced cash flows from operations by that amount, but
the reduction was more than offset by the other factors affecting cash flows
cited above.
Continuing operations provided net cash of $124 million in 2002
compared to $72 million in 2001. The 73 percent increase was due to increased
cash from operations before working capital changes ($5.7 million) and lower
working capital requirements ($47 million). The increase in cash from operations
before working capital changes was due to an increase in deferred income taxes
and investment tax credits in 2002 compared to a reduction in 2001 ($22.5
million), the loss provision for the PGE transaction costs ($13.9 million) and
higher depreciation and amortization ($2.4 million), largely offset by a small
increase in deferred gas cost payables in 2002 compared to a large swing from
net gas cost receivables to payables in 2001 ($26.5 million), and lower net
income in 2002 ($6.4 million). The decrease in working capital requirements was
due to an increase in accounts payable in 2002 compared to a decrease in 2001
($44 million), a decrease in accrued unbilled revenue in 2002 compared to an
increase in 2001 ($26 million), and a decrease in accounts receivable in 2002
compared to an increase in 2001 ($22 million), partially offset by a decrease in
accrued interest and taxes in 2002 compared to an increase in 2001 ($40 million)
and a larger increase in inventories in 2002 ($6.2 million).
The Company has lease and purchase commitments relating to its
operating activities that are financed with cash flows from operations (see
"Liquidity and Capital Resources," above, and Note 12).
The Job Creation and Worker Assistance Act of 2002 (the Assistance Act)
combined with the Jobs and Growth Tax Relief Reconciliation Act of 2003 (the
Reconciliation Act), allows an additional first-year tax depreciation deduction
on the adjusted basis of "qualified property." The Assistance Act provides for
an additional depreciation deduction equal to 30 percent of an asset's adjusted
basis. The Reconciliation Act increased this first-year additional depreciation
deduction to 50 percent of an asset's adjusted basis. The additional first-year
depreciation deduction is an acceleration of depreciation deductions that
otherwise would have been taken in the later years of an asset's recovery
period. In general, the extra first-year depreciation deduction is available for
most personal property acquired after Sept. 10, 2001, and before Sept. 11, 2004.
The Company anticipates enhanced cash flow from reduced income taxes, totaling
an estimated $30 million to $50 million, during the effective period, based on
actual and projected plant investments between Sept. 11, 2001 and Sept. 10,
2004.
36
Investing Activities
--------------------
Cash requirements for investing activities in 2003 totaled $127
million, up from $84 million in 2002. Cash requirements for acquisition and
construction of utility plant totaled $125 million, up from $80 million in 2002.
The increase in cash requirements for utility construction in 2003 was primarily
the result of higher capital expenditures relating to NW Natural's SMPE project
($27 million), higher system improvements and support ($12 million) and other
special projects to serve new customer load or new service areas ($8.9 million).
Cash requirements for investing activities in 2002 totaled $84 million,
down from $87 million in 2001, primarily due to lower amounts of cash used for
investments in non-utility property ($6.9 million) and for the PGE transaction
($5.2 million), partially offset by higher amounts of cash used for the
construction of utility plant ($7.6 million) and lower cash proceeds from the
sale of assets ($2.8 million). Cash requirements for utility construction in
2002 totaled $80 million, up from $72 million in 2001, primarily as a result of
capital expenditures related to NW Natural's pipeline safety program ($4.7
million) and special projects expanding service to existing customers or into
new service areas ($3.4 million).
Investments in non-utility property totaled $2.6 million in both 2003
and 2002, including expenditures in both years for certain improvements to the
Company's gas pipeline system that were primarily related to interstate storage
services.
During the five-year period 2004 through 2008, utility construction
expenditures are estimated at between $500 million and $600 million. The level
of capital expenditures over the next five years reflects projected customer
growth, the SMPE project and system improvement projects resulting in part from
requirements under the Pipeline Safety Improvement Act of 2002 (Pipeline Safety
Act) (see below). An estimated 60 percent of the required funds are expected to
be internally generated over the five-year period; the remainder will be funded
through a combination of long-term debt and equity securities with short-term
debt providing liquidity and bridge financing.
NW Natural's utility capital expenditures in 2004 are estimated to
total $165 million, including $31 million for customer growth, $38 million for
system improvement and support, $71 million for the SMPE and related gas storage
projects, $8 million for the construction of a gas distribution system in Coos
County, Oregon and $17 million for construction overhead.
The SMPE project has a scheduled completion date in late 2004. NW
Natural must obtain easements and rights-of-way for the construction of the
pipeline and may need to use condemnation proceedings to secure some of them.
NW Natural entered into a stipulation with the OPUC in 2001 for an
enhanced pipeline safety program that includes an accelerated bare steel
replacement program and a geo-hazard safety program. The bare steel replacement
program accelerates the replacement of NW Natural's bare steel piping over 20
years instead of 40 years. The geo-hazard safety program includes the
identification, assessment and remediation of risks to piping infrastructure
created by landslides, washouts, earthquakes or similar occurrences. The
stipulation allowed NW Natural to receive deferred accounting rate treatment
commencing Oct. 1, 2002, for costs associated with the programs exceeding $3
million per year, expected to be approximately $1.5 million annually.
In December 2003, the U.S. Department of Transportation's Office of
Pipeline Safety issued a rule that specifies the detailed requirements for
transmission pipeline integrity management programs (IMPs) as mandated by the
Pipeline Safety Act. The Pipeline Safety Act requires operators of gas
37
transmission pipelines to identify lines located in High Consequence Areas
(HCAs) and to develop IMPs to periodically inspect the integrity of the
pipelines and make repairs or replacements as necessary to ensure the ongoing
integrity of the pipelines. The legislation requires NW Natural to complete
inspection of the 50 percent highest risk pipelines located in its HCAs within
the first five years, and the remaining covered pipelines within 10 years of the
date of the enactment. The Pipeline Safety Act also requires re-inspections of
the covered pipelines every seven years thereafter for the life of the
pipelines. The capital and operating costs of compliance with the legislation
and rules, and the accounting and regulatory treatments for these costs, are
uncertain. Currently, however, NW Natural estimates that its IMP will cost $5
million to $8 million in 2004 and $5 million to $15 million per year beginning
in 2005, totaling $50 million to $100 million over the next 10 years.
Financing Activities
--------------------
Cash provided by financing activities in 2003 totaled $17 million,
compared to cash used in financing activities in 2002 of $43 million. Factors
contributing to the $60 million difference were an increase in short-term debt
in 2003 ($15.4 million) compared to a decrease in 2002 ($38.5 million) and the
redemption of the $6.95 Series of Preference Stock in 2002 ($25 million),
partially offset by a higher amount used for the retirement of long-term debt
($55 million in 2003 compared to $40.5 million in 2002) and the redemption,
including the annual sinking fund, of the $7.125 Series of Preferred Stock in
2003 ($8.4 million).
Cash used in financing activities in 2002 totaled $43 million, compared
to cash provided by financing activities in 2001 of $15 million. Factors
contributing to the $58 million difference were a reduction in short-term debt
in 2002 ($38 million) compared to an increase in 2001 ($52 million), the
redemption of the $6.95 Series of Preference Stock in 2002 ($25 million), and a
higher amount used for the retirement of long-term debt ($40.5 million in 2002
compared to $20 million in 2001), partially offset by an increase in long-term
debt issued ($90 million in 2002 compared to $18 million in 2001) and a
reduction in common stock repurchased ($5.8 million).
NW Natural sold $90 million of its secured Medium-Term Notes, Series B
(MTNs) in each of 2003 and 2002 and used the proceeds to redeem long-term debt
($55 million in 2003 and $40.5 million in 2002), provide cash for investments in
utility plant and reduce short-term borrowings.
In 2000, NW Natural commenced a program to repurchase up to 2 million
shares, or up to $35 million in value, of NW Natural's common stock through a
repurchase program that has been extended through May 2004. The purchases are
made in the open market or through privately negotiated transactions. No shares
were repurchased in 2002 or in 2003. Since the program's inception the Company
has repurchased 355,400 shares of common stock at a total cost of $8.2 million.
Pension Cost (Income) and Funding Status
----------------------------------------
Net periodic pension cost is determined in accordance with SFAS No. 87,
"Employers' Accounting for Pensions" (see "Application of Critical Accounting
Policies - Accounting for Pensions," above). The annual pension cost or income
is allocated between operations and maintenance expense and construction
overhead.
Net periodic pension cost for the Company's qualified defined benefit
pension plans was $6.2 million in 2003, compared to net pension income of $0.1
million and $4.1 million in 2002 and 2001, respectively. The increase in pension
cost was largely due to investment losses in 2001 and 2002, which are recognized
over a three-year period, and to lower discount rates which had the effect of
increasing accumulated benefit obligations. The Company is required to make a
cash contribution of at least $1.9 million, and may make an additional
contribution up to a total of $6.8 million, to its non-bargaining employee
pension plan for the 2003 plan year, payable by Sept. 15, 2004. No cash
contributions to the qualified plans were required for the 2002 or 2001 plan
years. The fair value of the plan assets increased to $168 million at Dec. 31,
2003, from $143 million at Dec. 31, 2002, including $36 million in investment
38
gains, partially offset by $10 million in withdrawals to pay benefits and $0.9
million in eligible expenses of the plans. The present value of benefit
obligations under the plans increased from an estimated $172 million to $192
million over that period, however, so the plans remained under-funded by about
$24 million at Dec. 31, 2003.
Despite the decline from a position of pension income in 2001 and 2002
to a position of pension expense in 2003, and the reductions in recent years in
the funded status of the plans, NW Natural believes it will be able to maintain
well-funded pension plans. NW Natural does not expect its current or future cash
contributions to the plans to have a material adverse effect on its liquidity or
financial condition.
Ratios of Earnings to Fixed Charges
-----------------------------------
For the years ended Dec. 31, 2003, 2002 and 2001, the Company's ratios
of earnings to fixed charges, computed using the Securities and Exchange
Commission method, were 2.83, 2.74 and 3.01, respectively. For this purpose,
earnings consist of net income before taxes plus fixed charges, and fixed
charges consist of interest on all indebtedness, dividends on all preferred and
preference stock, the amortization of debt expense and discount or premium and
the estimated interest portion of rentals charged to income.
Contingent Liabilities
- ----------------------
Environmental Matters
---------------------
The Company is subject to federal, state and local laws and regulations
related to environmental matters. These evolving laws and regulations may
require expenditures over a long timeframe to control environmental impacts. The
Company believes, at this time, that appropriate investigation or remediation is
being undertaken at all the relevant sites. Based on existing knowledge, the
Company does not expect that the ultimate resolution of these matters will have
a material adverse effect on its financial condition, results of operations or
cash flows. See Note 12.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The Company's primary market risk exposures associated with activities
involving derivative financial instruments and other financial instruments are
natural gas commodity price risk, foreign currency exchange risk and interest
rate risk. Derivative financial instruments are used as tools to mitigate
certain of these market risks (see Notes 1 and 11). Such instruments are used
for hedging purposes, not for trading purposes. Market risks associated with the
derivative financial instruments are monitored by management personnel who do
not directly enter into these contracts and by the Audit Committee of the Board
of Directors.
Physical and Financial Commodity, Foreign Currency and Interest Rate
--------------------------------------------------------------------
Transactions
------------
NW Natural enters into short-term and long-term natural gas purchase
contracts with demand and commodity fixed-price and floating-price components,
along with associated short-term and long-term natural gas transportation
contracts. Foreign currency forward contracts are used to hedge against foreign
exchange rate fluctuations on purchases made under these contracts that are
denominated in Canadian dollars.
Historically, NW Natural has taken physical delivery of at least the
minimum quantities specified in its natural gas purchase contracts. The
contracts are subject to annual re-pricing, a process that is intended to
reflect anticipated market price trends during the next year. NW Natural's PGA
mechanism in Oregon provides for the recovery from customers of actual commodity
39
costs in comparison with established benchmark costs, except that NW Natural
absorbs 33 percent of the higher cost of gas sold, or retains 33 percent of the
lower cost, in either case as compared to projections.
At Dec. 31, 2003, differences between notional values and fair values
with respect to NW Natural's open positions in derivative financial instruments
were not material to the Company's financial position or results of operations
because of the treatment of these instruments in regulatory mechanisms relating
to gas costs (see "Results of Operations - Comparison of Gas Operations - Cost
of Gas," above, and Notes 1 and 11).
To the degree that market risks exist due to potential adverse changes
in commodity prices, foreign exchange rates and interest rates in relation to
these financial and physical contracts, the Company considers the risks to be:
Commodity Price Risk
--------------------
The prices of natural gas commodity are subject to fluctuations due to
unpredictable factors including weather, pipeline transportation congestion and
other factors that affect short-term supply and demand. Commodity swap and call
option contracts (also known as financial hedge contracts) are used to convert
certain natural gas purchase contracts from floating prices to fixed prices. At
Dec. 31, 2003 and 2002, notional amounts under these commodity swap and call
option contracts totaled $304.1 million and $180.6 million, respectively. At
Dec. 31, 2003, five of these commodity hedge contracts extended beyond Dec. 31,
2004. If all of the commodity swap and call option contracts had been settled on
Dec. 31, 2003, a regulatory gain of $23.7 million would have been realized (see
Note 11).
Foreign Currency Risk
---------------------
The costs of natural gas commodity and certain pipeline services
purchased from Canadian suppliers are subject to changes in the value of
Canadian currency in relation to 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 Dec. 31, 2003 and 2002,
notional amounts under foreign currency forward contracts totaled $6.4 million
and $15.5 million, respectively. As of Dec. 31, 2003, no foreign currency
forward contracts extended beyond Dec. 31, 2004. If all of the foreign currency
forward contracts had been settled on Dec. 31, 2003, a gain of $0.2 million
would have been realized (see Note 11).
Interest Rate Risk
------------------
Interest rate risk relates to new debt financing needed to fund capital
requirements, including maturing debt securities, and to the issuance of
commercial paper. Interest rate risk is managed through the issuance of
fixed-rate debt with varying maturities and the reduction of debt through
optional redemption when interest rates are favorable. No derivative financial
instruments to hedge interest rates were in place at Dec. 31, 2003 or 2002.
40
Forward-Looking Statements
- --------------------------
This report and other presentations made by the Company from time to
time may contain forward-looking statements within the meaning of Section 21E of
the Securities Exchange Act of 1934, as amended. Forward-looking statements
include statements concerning plans, objectives, goals, strategies, future
events or performance, and other statements that are other than statements of
historical facts. The Company's expectations, beliefs and projections are
expressed in good faith and are believed to have a reasonable basis. However,
each such forward-looking statement involves uncertainties and is qualified in
its entirety by reference to the following important factors, among others, that
could cause the actual results of the Company to differ materially from those
projected in such forward-looking statements: (i) prevailing state and federal
governmental policies and regulatory actions, including those of the OPUC, the
WUTC and the U.S. Department of Transportation's Office of Pipeline Safety, with
respect to allowed rates of return, industry and rate structure, purchased gas
and investment recovery, acquisitions and dispositions of assets and facilities,
operation and construction of plant facilities, the maintenance of pipeline
integrity, present or prospective wholesale and retail competition, changes in
tax laws and policies and changes in and compliance with environmental and
safety laws, regulations and policies; (ii) weather conditions and other natural
phenomena; (iii) unanticipated population growth or decline, and changes in
market demand caused by changes in demographic or customer consumption patterns;
(iv) competition for retail and wholesale customers; (v) pricing of natural gas
relative to other energy sources; (vi) risks resulting from uninsured property
damage to Company property, intentional or otherwise; (vii) unanticipated
changes in interest or foreign currency exchange rates or in rates of inflation;
(viii) economic factors that could cause a severe downturn in certain key
industries, thus affecting demand for natural gas; (ix) unanticipated changes in
operating expenses and capital expenditures; (x) unanticipated changes in future
liabilities relating to employee benefit plans; (xi) capital market conditions,
including their effect on pension costs; (xii) competition for new energy
development opportunities; (xiii) 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
(xiv) legal and administrative proceedings and settlements. All subsequent
forward-looking statements, whether written or oral and whether made by or on
behalf of the Company, also are expressly qualified by these cautionary
statements.
Any forward-looking statement speaks only as of the date on which such
statement is made, and the Company undertakes 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 the
Company to predict all such factors, nor can it 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.
41
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
TABLE OF CONTENTS
Page
1. Report of Independent Auditors........................................ 43
2. Consolidated Financial Statements:
Consolidated Statements of Income for the Years Ended
December 31, 2003, 2002 and 2001...................................... 44
Consolidated Statements of Earnings Invested in the Business
and Comprehensive Income for the Years Ended December 31,
2003, 2002 and 2001................................................... 45
Consolidated Balance Sheets, December 31, 2003 and 2002............... 46
Consolidated Statements of Cash Flows for the Years
Ended December 31, 2003, 2002 and 2001................................ 48
Consolidated Statements of Capitalization, December 31,
2003 and 2002......................................................... 49
Notes to Consolidated Financial Statements............................ 50
3. Quarterly Financial Information (unaudited)........................... 75
4. Supplementary Data for the Years Ended December 31, 2003,
2002 and 2001:
Financial Statement Schedule
Schedule II - Valuation and Qualifying Accounts and Reserves.......... 76
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.
42
REPORT OF INDEPENDENT AUDITORS
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 (the "Company")
at December 31, 2003 and 2002, and the results of their operations and their
cash flows for each of the three years in the period ended December 31, 2003 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. These financial statements and financial
statement schedule are the responsibility of the Company's management; our
responsibility is to express an opinion on these financial statements and
financial statement schedule based on our audits. We conducted our audits of
these statements in accordance with auditing standards generally accepted in the
United States of America, which require that we plan and perform the audit to
obtain reasonable assurance about whether the financial statements are free of
material misstatement. An audit includes 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. We believe that our
audits provide a reasonable basis for our opinion.
/s/PricewaterhouseCoopers LLP
- -----------------------------
Portland, Oregon
February 26, 2004
43
NORTHWEST NATURAL GAS COMPANY
CONSOLIDATED STATEMENTS OF INCOME
Thousands, except per share amounts (year ended December 31) 2003 2002 2001
- -----------------------------------------------------------------------------------------------------------
Operating revenues:
Gross operating revenues $ 611,256 $ 641,376 $ 650,252
Cost of sales 323,190 353,832 374,241
---------- --------- ---------
Net operating revenues 288,066 287,544 276,011
Operating expenses:
Operations and maintenance 96,420 85,120 83,920
Taxes other than income taxes 35,125 34,076 32,240
Depreciation and amortization 54,249 52,090 49,640
---------- --------- ---------
Total operating expenses 185,794 171,286 165,800
---------- --------- ---------
Income from operations 102,272 116,258 110,211
Other income (expense) 2,150 (14,890) 1,334
Interest charges - net of amounts capitalized 35,099 34,132 33,805
---------- --------- ---------
Income before income taxes 69,323 67,236 77,740
Income tax expense 23,340 23,444 27,553
---------- --------- ---------
Net income 45,983 43,792 50,187
Redeemable preferred and preference stock dividend requirements 294 2,280 2,401
---------- --------- ---------
Earnings applicable to common stock $ 45,689 $ 41,512 $ 47,786
========== ========= =========
Average common shares outstanding:
Basic 25,741 25,431 25,159
Diluted 26,061 25,814 25,612
Earnings per share of common stock:
Basic $ 1.77 $ 1.63 $ 1.90
Diluted $ 1.76 $ 1.62 $ 1.88
------------------------------------
See Notes to Consolidated Financial Statements.
44
NORTHWEST NATURAL GAS COMPANY
CONSOLIDATED STATEMENTS OF EARNINGS INVESTED IN THE BUSINESS AND
COMPREHENSIVE INCOME
Thousands (year ended December 31) 2003 2002 2001
- ------------------------------------------------------------------------------------------------------------------------------
Earnings invested in the business:
Balance at beginning of year $ 157,136 $ 147,950 $ 134,189
Net income 45,983 $ 45,983 43,792 $ 43,792 50,187 $ 50,187
Cash dividends paid:
Redeemable preferred and preference stock (392) (2,579) (2,410)
Common stock (32,655) (32,024) (31,307)
Common stock repurchased - - (2,688)
Common stock expense (19) (3) (21)
--------- --------- ---------
Balance at end of year $ 170,053 $ 157,136 $ 147,950
========= ========= =========
Accumulated other comprehensive income (loss):
Balance at beginning of year $ (3,084) $ (375) $ -
Other comprehensive income (loss) - net of tax:
Minimum pension liability adjustment 2,068 2,068 (2,936) (2,936) (148) (148)
Change in unrealized loss from price risk
management activities - - 227 227 (227) (227)
------------------- -------------------- ---------------------
Comprehensive income $ 48,051 $ 41,083 $ 49,812
======== ======== ========
Balance at end of year $ (1,016) $ (3,084) $ (375)
========= ========= =========
------------------------------------
See Notes to Consolidated Financial Statements.
45
NORTHWEST NATURAL GAS COMPANY
CONSOLIDATED BALANCE SHEETS
Thousands (December 31) 2003 2002
- ----------------------------------------------------------------------------------------
Assets:
Plant and property:
Utility plant $ 1,659,089 $ 1,539,965
Less accumulated depreciation 471,716 435,601
----------- -----------
Utility plant - net 1,187,373 1,104,364
----------- -----------
Non-utility property 23,395 20,832
Less accumulated depreciation and amortization 4,855 4,404
----------- -----------
Non-utility property - net 18,540 16,428
----------- -----------
Total plant and property 1,205,913 1,120,792
----------- -----------
Other investments 12,635 12,703
----------- -----------
Current assets:
Cash and cash equivalents 4,706 7,328
Accounts receivable, less allowance for uncollectible
accounts of $1,763 in 2003 and $1,815 in 2002 52,213 46,936
Accrued unbilled revenue 59,109 44,069
Inventories of gas, materials and supplies 50,859 58,030
Prepayments and other current assets 32,661 36,934
----------- -----------
Total current assets 199,548 193,297
----------- -----------
Regulatory assets:
Income tax asset 63,449 47,975
Unamortized costs on debt redemptions 7,803 6,508
Other 6,020 7,040
----------- -----------
Total regulatory assets 77,272 61,523
----------- -----------
Other assets:
Investment in life insurance 59,710 54,916
Fair value of non-trading derivatives 23,885 12,426
Other 12,369 11,620
----------- -----------
Total other assets 95,964 78,962
----------- -----------
Total assets $ 1,591,332 $ 1,467,277
=========== ===========
-----------------------------------
See Notes to Consolidated Financial Statements.
46
NORTHWEST NATURAL GAS COMPANY
CONSOLIDATED BALANCE SHEETS
Thousands (December 31) 2003 2002
- ----------------------------------------------------------------------------------------
Capitalization and liabilities:
Capitalization
Common stock $ 82,137 $ 81,023
Premium on common stock 255,871 248,028
Earnings invested in the business 170,053 157,136
Unearned stock compensation (729) (711)
Accumulated other comprehensive income (loss) (1,016) (3,084)
----------- -----------
Total common stock equity 506,316 482,392
Redeemable preferred stock - 8,250
Long-term debt 500,319 445,945
----------- -----------
Total capitalization 1,006,635 936,587
----------- -----------
Current liabilities:
Notes payable 85,200 69,802
Accounts payable 86,029 74,436
Long-term debt due within one year - 20,000
Taxes accrued 8,605 7,822
Interest accrued 2,998 2,902
Other current and accrued liabilities 31,589 30,045
----------- -----------
Total current liabilities 214,421 205,007
----------- -----------
Regulatory liabilities:
Accrued asset removal costs 135,638 125,197
Customer advances 1,564 1,791
Deferred gas costs payable 5,627 10,635
Unrealized gain on non-trading derivatives 23,885 12,426
----------- -----------
Total regulatory liabilities 166,714 150,049
----------- -----------
Other liabilities:
Deferred income taxes 171,797 141,732
Deferred investment tax credits 6,945 7,824
Other 24,820 26,078
----------- -----------
Total other liabilities 203,562 175,634
----------- -----------
Commitments and contingencies (see Note 12) - -
----------- -----------
Total capitalization and liabilities $ 1,591,332 $ 1,467,277
=========== ===========
-----------------------------------
See Notes to Consolidated Financial Statements.
47
NORTHWEST NATURAL GAS COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
Thousands (year ended December 31) 2003 2002 2001
- ------------------------------------------------------------------------------------------------------------------
Operating activities:
Net income from operations $ 45,983 $ 43,792 $ 50,187
Adjustments to reconcile net income to cash provided by
operations:
Depreciation and amortization 54,249 52,090 49,640
(Gain) loss on sale of assets 10 (221) -
Loss for PGE acquisition costs - 13,873 -
Minimum pension liability adjustment 2,068 (2,936) (148)
Unrealized gain (loss) from price risk management activities - 227 (227)
Deferred income taxes and investment tax credits 29,186 10,450 (12,088)
Undistributed (earnings) losses from equity investments (474) (988) 321
Allowance for funds used during construction (1,734) (550) (959)
Deferred gas costs - net (5,008) 546 27,062
Other (22,599) 4,582 1,345
--------- --------- ---------
Cash from operations before working capital changes 101,681 120,865 115,133
Changes in operating assets and liabilities:
Accounts receivable - net of allowance for
uncollectible accounts (5,277) 17,786 (3,969)
Accrued unbilled revenue (15,040) 13,680 (12,130)
Inventories of gas, materials and supplies 7,171 (8,693) (2,454)
Accounts payable 11,593 3,738 (40,000)
Accrued interest and taxes 1,145 (24,725) 15,435
Other current assets and liabilities 5,533 1,176 (494)
--------- --------- ---------
Cash provided by operating activities 106,806 123,827 71,521
--------- --------- ---------
Investing activities:
Acquisition and construction of utility plant assets (124,660) (79,530) (71,943)
Investment in non-utility property (2,563) (2,629) (9,554)
PGE acquisition costs - (4,316) (9,557)
Proceeds from sale of assets 18 500 3,256
Other investments 542 1,848 529
--------- --------- ---------
Cash used in investing activities (126,663) (84,127) (87,269)
--------- --------- ---------
Financing activities:
Common stock issued 8,331 6,533 5,157
Common stock repurchased - - (5,792)
Redeemable preferred and preference stock retired (8,428) (25,750) (750)
Long-term debt issued 90,000 90,000 18,000
Long-term debt retired (55,000) (40,500) (20,000)
Change in short-term debt 15,398 (38,489) 52,028
Cash dividend payments:
Redeemable preferred and preference stock (392) (2,579) (2,410)
Common stock (32,655) (32,024) (31,307)
Common stock expense (19) (3) (21)
--------- --------- ---------
Cash provided by (used in) financing activities 17,235 (42,812) 14,905
--------- ---------- ---------
Decrease in cash and cash equivalents (2,622) (3,112) (843)
Cash and cash equivalents - beginning of year 7,328 10,440 11,283
--------- --------- ---------
Cash and cash equivalents - end of year $ 4,706 $ 7,328 $ 10,440
========= ========= =========
- -----------------------------------------------------------------------------------------------------------------
Supplemental disclosure of cash flow information:
Cash paid during the period for:
Interest and preferred dividends $ 35,210 $ 34,640 $ 33,034
Income taxes $ 13,940 $ 33,474 $ 25,201
- -----------------------------------------------------------------------------------------------------------------
Supplemental disclosure of non-cash financing activities:
Conversion to common stock:
7-1/4 % Series of Convertible Debentures $ 626 $ 1,932 $ 413
------------------------------------
See Notes to Consolidated Financial Statements
48
NORTHWEST NATURAL GAS COMPANY
CONSOLIDATED STATEMENTS OF CAPITALIZATION
Thousands, except share amounts (December 31) 2003 2002
- --------------------------------------------------------------------------------------------------------------------------------
Common stock equity:
Common stock - par value $3-1/6 per share, authorized 60,000,000 shares: $ 82,137 $ 81,023
outstanding - 2003, 25,938,002 shares; 2002, 25,586,313 shares
Premium on common stock 255,871 248,028
Earnings invested in the business 170,053 157,136
Unearned compensation (729) (711)
Accumulated other comprehensive income (loss) (1,016) (3,084)
----------- ---------
Total common stock equity 506,316 50% 482,392 51%
Redeemable preferred stock, authorized 1,500,000 shares:
$7.125 Series, stated value $100 per share; outstanding - 2003, none;
2002, 82,500 shares - 0% 8,250 1%
Long-term debt:
Medium-Term Notes
-----------------
First Mortgage Bonds:
6.400% Series B due 2003 - 20,000
6.340% Series B due 2005 5,000 5,000
6.380% Series B due 2005 5,000 5,000
6.450% Series B due 2005 5,000 5,000
6.050% Series B due 2006 8,000 8,000
6.310% Series B due 2007 20,000 20,000
6.800% Series B due 2007 9,500 9,500
6.500% Series B due 2008 5,000 5,000
4.110% Series B due 2010 10,000 -
7.450% Series B due 2010 25,000 25,000
6.665% Series B due 2011 10,000 10,000
7.130% Series B due 2012 40,000 40,000
8.260% Series B due 2014 10,000 10,000
7.000% Series B due 2017 40,000 40,000
6.600% Series B due 2018 22,000 22,000
8.310% Series B due 2019 10,000 10,000
7.630% Series B due 2019 20,000 20,000
9.050% Series A due 2021 10,000 10,000
5.620% Series B due 2023 40,000 -
7.250% Series B due 2023 - 20,000
7.500% Series B due 2023 - 4,000
7.520% Series B due 2023 - 11,000
7.720% Series B due 2025 20,000 20,000
6.520% Series B due 2025 10,000 10,000
7.050% Series B due 2026 20,000 20,000
7.000% Series B due 2027 20,000 20,000
6.650% Series B due 2027 20,000 20,000
6.650% Series B due 2028 10,000 10,000
7.740% Series B due 2030 20,000 20,000
7.850% Series B due 2030 10,000 10,000
5.820% Series B due 2032 30,000 30,000
5.660% Series B due 2033 40,000 -
Convertible Debentures
----------------------
7-1/4% Series due 2012 5,819 6,445
----------- ---------
500,319 465,945
Less long-term debt due within one year - 20,000
----------- ---------
Total long-term debt 500,319 50% 445,945 48%
----------- --- --------- ---
Total capitalization $ 1,006,635 100% $ 936,587 100%
=========== === ========= ===
------------------------------------
See Notes to Consolidated Financial Statements.
49
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:
-------------------------------------------
Organization and Principles of Consolidation
- --------------------------------------------
The consolidated financial statements include the accounts of:
Regulated utility:
o Northwest Natural Gas Company (NW Natural)
Non-regulated wholly-owned subsidiaries of NW Natural:
o NNG Financial Corporation (Financial Corporation), and its
wholly-owned subsidiaries
o Northwest Energy Corporation (Northwest Energy), and its
wholly-owned subsidiary
Together these businesses are referred to herein as the Company (see
Note 2). Intercompany accounts and transactions have been eliminated.
Investments in corporate joint ventures and partnerships in which the
Company's ownership interest is 50 percent or less and over which the
Company does not exercise control are accounted for by the equity
method or the cost method (see Note 9).
Certain amounts from prior years have been reclassified to conform, for
comparison purposes, with the current financial statement presentation.
These reclassifications had no impact on prior year consolidated
results of operations.
Use of Estimates
- ----------------
The preparation of financial statements in conformity with generally
accepted accounting principles in the United States of America 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
- -------------------
The Company's principal business is the distribution of natural gas,
which is regulated by the Public Utility Commission of Oregon (OPUC)
and the Washington Utilities and Transportation Commission (WUTC).
Accounting records and practices conform to the requirements and
uniform system of accounts prescribed by these regulatory authorities
in accordance with Statement of Financial Accounting Standards (SFAS)
No. 71, "Accounting for the Effects of Certain Types of Regulation."
In applying SFAS No. 71, NW Natural capitalizes certain costs and
revenues as regulatory assets and liabilities pursuant to orders of the
OPUC or WUTC in general rate or expense deferral proceedings, to
provide for recovery of revenues or expenses from, or refunds to,
utility customers in future periods. At Dec. 31, 2003 and 2002, the
amounts deferred as regulatory assets and liabilities were net
liabilities of $89.4 million and $88.5 million, respectively. The net
amounts recognized at Dec. 31, 2003 and 2002 include $135.6 million and
$125.2 million, respectively, of accumulated removal costs, which have
been reclassified from accumulated depreciation to regulatory
liabilities at Dec. 31, 2003, in accordance with SFAS No. 143,
"Accounting for Asset Removal Obligations" (see "New Accounting
Standards," below). In addition, the "Income tax asset" balance
increased by $15.5 million primarily reflecting the grossed-up tax
benefit of removal costs passed through in rate base after Dec. 31,
1992.
50
If NW Natural 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 it would be required to
write off the net unrecoverable balances against earnings.
New Accounting Standards
- ------------------------
Adopted Standards
-----------------
Effective Jan. 1, 2003, the Company adopted SFAS No. 143, "Accounting
for Asset Retirement Obligations." SFAS No. 143 requires the
recognition of an Asset Retirement Obligation (ARO) for legal
obligations associated with the retirement of tangible long-lived
assets, including the recording of fair value of the liability, if
reasonably estimable, for an ARO in the period in which it is incurred.
The ARO liability is recorded and the cost is capitalized as part of
the carrying amount of the related long-lived asset. Over time, the
liability is accreted to its present value each period and the
capitalized cost is depreciated over the useful life of the related
asset. The Company did not have any material legal obligations
associated with the retirement of its tangible long-lived assets,
except for certain assets with indefinite system lives for which the
Company cannot estimate the ARO because the settlement date is
indeterminable. However, the Company's adoption of SFAS No. 143 did
result in a balance sheet reclassification of asset removal cost
obligations from accumulated depreciation and amortization to
regulatory liabilities (see "Plant and Property," below, for a
discussion of the Company's policy on asset removal costs).
Also effective Jan. 1, 2003, the Company adopted SFAS No. 145,
"Rescission of FASB Statement Nos. 4, 44 and 64, Amendment of FASB
Statement No. 13 and Technical Corrections," and SFAS No. 146,
"Accounting for Costs Associated with Exit or Disposal Activities,"
which replaces Emerging Issues Task Force Issue No. 94-3, "Liability
Recognition for Certain Employee Termination Benefits and Other Costs
to Exit an Activity (including Certain Costs Incurred in a
Restructuring)." SFAS No. 145, which updates, clarifies and simplifies
existing accounting pronouncements, addresses the reporting of debt
extinguishments and accounting for certain lease modifications that
have economic effects that are similar to sale-leaseback transactions.
SFAS No. 146 requires companies to recognize costs associated with exit
or disposal activities, such as lease termination costs and certain
employee severance costs, when they are incurred rather than at the
date of a commitment to an exit or disposal plan. The primary effect of
applying SFAS No. 146, which was effective for all exit or disposal
activities initiated after Dec. 31, 2002, is on the timing of
recognition of costs associated with exit or disposal activities. The
adoption of SFAS Nos. 145 and 146 did not have a material impact on the
Company's financial condition or results of operations.
Also effective Jan. 1, 2003, the Company adopted the disclosure
requirements of SFAS No. 148, "Accounting for Stock-Based Compensation
- Transition and Disclosure - an amendment to FASB Statement No. 123,"
but continues to account for its stock-based compensation plans using
the intrinsic value method prescribed in Accounting Principles Board
Opinion (APB) No. 25, "Accounting for Stock Issued to Employees,"
rather than adopt a fair value method of accounting for its stock-based
employee compensation. SFAS No. 148 provides alternative methods of
transition for a voluntary change to the fair value method. In
addition, SFAS No. 148 requires prominent disclosures in annual and
interim financial statements about the accounting method used for
stock-based employee compensation and its effect on reported results.
SFAS No. 148 encourages, but does not require, companies to record
compensation expense using the fair value method of accounting. The
adoption of SFAS No. 148 did not have a material impact on the
Company's financial condition or results of operations, and it would
not have had a material impact if the Company had elected to adopt a
fair value method of accounting for stock-based compensation (see
"Stock-Based Compensation," below, and Note 4).
Effective July 1, 2003, the Company adopted SFAS No. 149, "Amendment of
Statement 133 on Derivative Instruments and Hedging Activities." SFAS
No. 149 primarily amends SFAS No. 133, "Accounting for Derivative
Instruments and Hedging Activities," to clarify the definition of a
derivative and to require derivative instruments that include up-front
cash payments to be classified as financing activity in the statement
of cash flows. SFAS No. 149 is effective for contracts entered into or
modified after June 30, 2003, and for hedging relationships designated
51
after June 30, 2003. The adoption of SFAS No. 149 did not have a
material impact on the Company's financial condition or results of
operations.
Also effective July 1, 2003, the Company adopted SFAS No. 150,
"Accounting for Certain Financial Instruments with Characteristics of
both Liabilities and Equity." SFAS No. 150 establishes standards for
how an issuer classifies and measures in its financial statements
certain financial instruments with characteristics of both liabilities
and equity. SFAS No. 150 requires an issuer to classify a financial
instrument as a liability if that financial instrument embodies an
obligation of the issuer. The adoption of SFAS No. 150 resulted in the
Company's reclassifying dividends of $0.2 million after July 1, 2003 on
its redeemable preferred stock as interest expense, thus affecting the
Company's reported net income for 2003. The Company redeemed its last
remaining shares of preferred stock outstanding during the fourth
quarter of 2003. The adoption of SFAS No. 150 did not have a material
impact on the Company's financial condition or results of operations.
In December 2003, the Financial Accounting Standards Board (FASB)
issued SFAS No. 132, "Employers' Disclosures about Pensions and Other
Postretirement Benefits, an amendment of FASB Statements No. 87, 88,
and 106." SFAS No. 132 requires that expanded disclosures on pension
and other postretirement benefit plans be included in financial
statements for fiscal years ending on or after Dec. 15, 2003. The
Company has adopted SFAS No. 132. See Note 7.
In November 2002, the FASB issued FASB Interpretation No. (FIN) 45,
"Guarantor's Accounting and Disclosure Requirements for Guarantees,
Including Indirect Guarantees of Indebtedness of Others." FIN 45
clarifies the requirements of FASB Statement No. 5, "Accounting for
Contingencies," relating to the guarantor's accounting for, and
disclosure of, the issuance of certain types of guarantees. A guarantor
must recognize a liability for the fair value of an obligation assumed
under a guarantee and provide additional disclosures about the
obligations associated with guarantees issued. In connection with the
settlement of litigation involving leases in the Mist gas storage
field, NW Natural agreed to defend and indemnify a party against claims
relating to the validity and enforceability of certain transferred
leases. However, NW Natural has no obligation to defend or indemnify
the party from any claims for recovery of punitive or other exemplary
damages. The Company has provided no other guarantees of indebtedness
of others. Accordingly, the application of FIN 45 did not have a
material impact on the Company's financial condition or results of
operations.
In January 2003, the FASB issued FIN 46, "Consolidation of Variable
Interest Entities." FIN 46 provides guidance on the identification of,
and the financial reporting for, entities over which control is
achieved through means other than voting rights, known as "variable
interest entities." FIN 46 provides guidance for determining whether
consolidation is required. Certain variable interest entities must be
consolidated by the primary beneficiary if the equity investors in the
entity do not have the characteristics of a controlling financial
interest or do not have sufficient equity at risk for the entity to
finance its activities without additional subordinated financial
support from other parties. FIN 46 was effective immediately for all
new variable interest entities created or acquired after Jan. 31, 2003.
The Company did not have any significant interests in any variable
interest entities during any of the current reporting periods. The
application of FIN 46 had no material impact on the Company's financial
condition or results of operations.
Plant and Property
- ------------------
Plant and property is stated at cost, including labor, materials and
overhead (see Note 9). The cost of utility plant and interstate storage
includes an allowance for funds used during construction in
construction overhead to represent the net cost of borrowed funds used
for construction purposes (see "Allowance for Funds Used During
Construction," below).
NW Natural's provision for depreciation of utility property is computed
under the straight-line, age-life method in accordance with independent
engineering studies and as approved by regulatory authorities. The
52
average depreciation rate was approximately 3.5 percent for each of the
years 2003, 2002 and 2001. The depreciation rate reflects the
approximate economic life of the utility property.
Effective Jan. 1, 2003, the Company adopted SFAS No. 143 (see "New
Accounting Standards," above). Among other things, SFAS No. 143
requires that future asset retirement costs (removal costs) that meet
the requirements of SFAS No. 71, as amended and supplemented, be
classified as a regulatory liability. In accordance with long-standing
industry practice, the Company accrues for future removal costs on many
long-lived assets through a charge to depreciation expense allowed in
rates. Prior to the adoption of SFAS No. 143, the resulting regulatory
liabilities were recognized as accruals to accumulated depreciation. At
the time when removal costs were incurred, accumulated depreciation was
charged with the costs of removal and the book cost of the asset being
retired. Upon the adoption of SFAS No.143, the Company reclassified on
its Dec. 31, 2003 and 2002 consolidated balance sheets $135.6 million
and $125.2 million, respectively, of previously accrued asset removal
costs recovered through rates from accumulated depreciation and
amortization to regulatory liabilities - accrued asset removal costs.
This reclassification is based on the Company's estimate of accumulated
removal costs using its most recent depreciation study. The Company
will continue to accrue future asset removal costs through depreciation
expense, with a corresponding credit to regulatory liabilities -
accrued asset removal costs. When the Company retires depreciable
utility plant and equipment, it will charge the associated original
costs to accumulated depreciation and amortization, and any related
removal costs incurred will be charged to regulatory liabilities -
accrued asset removal costs. 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 the net rate base.
Allowance for Funds Used During Construction
- --------------------------------------------
Certain additions to utility plant include an allowance for funds used
during construction (AFUDC). AFUDC represents the cost of funds
borrowed during construction and is calculated using actual commercial
paper interest rates. If commercial paper borrowings are less than the
total costs of 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
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. NW Natural's
composite AFUDC rates were 4.5 percent in 2003, 2.8 percent in 2002 and
6.2 percent in 2001.
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.
Revenue Recognition
- -------------------
Utility revenues, derived primarily from the sale and transportation of
natural 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 (unbilled revenues). Unbilled revenues are
dependent upon a number of factors that require management judgment,
including total gas receipts and deliveries, customer use and weather.
Unbilled revenues are reversed the following month when actual billings
occur. The Company's accrued unbilled revenues at Dec. 31, 2003 and
2002 were $59.1 million and $44.1 million, respectively.
Non-utility revenues, derived primarily from gas storage services, are
recognized upon delivery of the service to customers. Revenues from
optimization of excess storage and transportation capacity are
recognized over the life of the contract for guaranteed amounts under
the contract, or are recognized as earned for amounts above the
guaranteed value.
53
Inventories
- -----------
Inventories, consisting primarily of natural gas in storage, are stated
at the lower of average cost or net realizable value.
Derivatives Policy
- ------------------
NW Natural's Derivatives Policy sets forth the guidelines for using
selected financial derivative products to support prudent risk
management strategies within designated parameters. The Derivatives
Policy allows for the use of derivatives to manage natural gas
commodity prices related to natural gas purchases, foreign currency
prices related to gas purchase commitments from Canada, oil or propane
commodity prices related to gas sales and transportation services under
rate schedules pegged to other commodities, and interest rates related
to long-term debt maturing in less than five years or expected to be
issued in future periods. NW Natural's objective for using derivatives
is to decrease the volatility of earnings and cash flows associated
with changes in commodity prices, foreign currency prices and interest
rates. The use of derivatives is permitted only after the commodity
price, exchange rate, and interest rate 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 (see Note 11). The Policy is intended to prevent speculative
risk. NW Natural does not enter into derivative instruments for trading
purposes and believes that any increase in market risk created by
holding derivatives should be offset by the exposures they modify.
In accounting for derivative activities, the Company applies SFAS No.
133, "Accounting for Derivative Instruments and Hedging Activities," 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). SFAS No. 133 requires that
the Company recognize derivatives as either assets or liabilities on
the balance sheet and measure those instruments at fair value. SFAS No.
133 also 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 purchase and normal sale, other than a financial
instrument or derivative instrument for which physical delivery is
probable. Many of the Company's gas supply and transportation contracts
are derivative instruments as defined under SFAS No. 133, but qualify
for the normal purchase and normal sale exception.
NW Natural designates its derivatives as fair value or cash flow hedges
based upon the criteria established by SFAS No. 133. For fair value
hedges, the gain or loss is recognized in earnings in the period of
change. For cash flow hedges, the effective portion of the gain or loss
is initially reported in accumulated other comprehensive income (OCI),
unless the derivative is subject to deferral under NW Natural's
regulated tariffs with the OPUC or the WUTC. The ineffective portion of
the gain or loss in a cash flow hedge is recognized in current
earnings, but only to the extent that the amount is not covered under
NW Natural's regulatory deferral mechanism. Effectiveness is measured
by comparing changes in cash flows of the hedged item to gains or
losses on derivative instruments.
NW Natural's primary hedging activities, consisting of natural gas
commodity price and foreign currency exchange rate hedges, are
principally accounted for as cash flow hedges under SFAS No. 133 and
are subject to regulatory deferral under SFAS No. 71. Unrealized gains
and losses from mark-to-market valuations of these contracts are not
recognized in current income but are reported as derivative assets or
liabilities and offset by a corresponding deferred account balance
included under "regulatory liabilities" or "regulatory assets." Due to
their regulatory deferral treatment, effective portions of changes in
the fair value of these derivatives are not recorded in OCI but are
recognized as a regulatory asset or liability.
Income Taxes
- ------------
The Company accounts for income taxes in accordance with SFAS No. 109,
"Accounting for Income Taxes." Under SFAS No. 109, the Company
recognizes deferred income taxes for all temporary differences between
54
the financial statement and tax basis of assets and liabilities at
current income tax rates. Deferred tax liabilities and assets reflect
the expected future tax consequences, based on enacted tax law, of
temporary differences between the tax basis of assets and liabilities
and their financial reporting amounts (see Note 8).
SFAS No. 109 also requires recognition of the additional deferred
income tax assets and liabilities for temporary differences where
regulators prohibit deferred income tax treatment for ratemaking
purposes. Consistent with rate and accounting orders of regulatory
authorities, deferred income taxes are not currently collected for
those temporary income tax differences where the prescribed regulatory
accounting methods do not provide for current recovery in rates. NW
Natural has recorded a regulatory tax asset for amounts pending
recovery from customers in future rates, equivalent to $63.4 million
and $48 million at Dec. 31, 2003 and 2002, respectively. These amounts
are primarily based on differences between the book and tax bases of
net utility plant in service.
Investment tax credits on utility plant additions and leveraged leases,
which reduce income taxes payable, are deferred for financial statement
purposes and are amortized over the life of the related plant or lease.
Investment and energy tax credits generated by non-regulated
subsidiaries are amortized over a period of one to five years.
Other Income (Expense)
- ----------------------
Other income (expense) consists of interest income, gain on sale of
assets, investment income of Financial Corporation, the costs incurred
in connection with the Company's effort to acquire Portland General
Electric Company (PGE) from Enron Corp. and other miscellaneous income
from merchandise sales, rents, leases and other items.
Earnings Per Share
- ------------------
Basic earnings per share are computed based on the weighted average
number of common shares outstanding each year. Diluted earnings per
share reflect the potential effects of the conversion of convertible
debentures and the exercise of stock options. Diluted earnings are
calculated as follows:
Thousands, except per share amounts 2003 2002 2001
--------------------------------------------------------------------------------------------------------------
Net income $ 45,983 $ 43,792 $ 50,187
Redeemable preferred and preference stock dividend requirements 294 2,280 2,401
-------- -------- --------
Earnings applicable to common stock - basic 45,689 41,512 47,786
Debenture interest less taxes 257 285 370
-------- -------- --------
Earnings applicable to common stock - diluted $ 45,946 $ 41,797 $ 48,156
======== ======== ========
Average common shares outstanding - basic 25,741 25,431 25,159
Stock options 28 59 32
Convertible debentures 292 324 421
-------- -------- --------
Average common shares outstanding - diluted 26,061 25,814 25,612
======== ======== ========
Earnings per share of common stock - basic $ 1.77 $ 1.63 $ 1.90
======== ======== ========
Earnings per share of common stock - diluted $ 1.76 $ 1.62 $ 1.88
========= ======== ========
For the years ended Dec. 31, 2003, 2002 and 2001, 77,500 shares, 84,000
shares and 138,491 shares, respectively, representing the number of
stock options the exercise prices for which were greater than the
average market prices for the Company's common stock for such years,
were excluded from the calculation of diluted earnings per share
because the effect was antidilutive.
55
Stock-Based Compensation
- ------------------------
The Company applies APB Opinion No. 25, "Accounting for Stock Issued to
Employees," to account for its stock-based compensation plans.
Accordingly, the Company does not recognize compensation expense for
the fair value of its stock option grants. Instead, the Company has
elected to continue using the intrinsic value method of accounting for
stock options rather than adopting the fair value method of accounting.
However, the Company does recognize compensation expense for the fair
value of stock awards granted under its Long-Term Incentive Plan and
Non-Employee Directors Stock Compensation Plan in the period when
shares are earned (see Note 4).
2. CONSOLIDATED SUBSIDIARY OPERATIONS AND SEGMENT INFORMATION:
-----------------------------------------------------------
At Dec. 31, 2003, the Company had two direct, wholly-owned
subsidiaries, Financial Corporation and Northwest Energy. Northwest
Energy was formed in 2001 to serve as the holding company for NW
Natural and PGE if the acquisition of PGE had been completed. Since the
acquisition of PGE has been terminated, Northwest Energy remains a
non-active subsidiary of the Company.
The Company's core business is the distribution and sale of natural gas
("Utility" segment). Another segment, "Gas Storage," represents natural
gas storage services provided to interstate customers, including asset
optimization services under a contract with an independent energy
trading company. The remaining business segment, "Other," primarily
consists of non-regulated investments in alternative energy projects in
California (see "Financial Corporation," below), a Boeing 737-300
aircraft leased to Continental Airlines and Northwest Energy's limited
acquisition activities (see Note 9).
Gas Storage
- -----------
Gas storage services are provided to off-system interstate customers
using Company-owned storage capacity that has been developed in advance
of core utility customers' (residential, commercial and industrial
firm) requirements. NW Natural retains 80 percent of the income before
tax from gas storage services and credits the remaining 20 percent to a
deferred regulatory account for sharing with its core utility
customers.
Results for the gas storage segment also include revenues, net of
amounts shared with core utility customers, from a contract with an
independent energy trading company that seeks to optimize the use of NW
Natural's assets by trading temporarily unused portions of its gas
storage capacity and upstream pipeline transportation capacity. NW
Natural retains 80 percent of the pre-tax income from the optimization
of storage and pipeline transportation capacity when the costs of such
capacity have not been included in core utility rates, or 33 percent of
the pre-tax income from such capacity when the costs have been included
in core utility rates. The remaining 20 percent and 67 percent,
respectively, are credited to a deferred regulatory account for
distribution to NW Natural's core utility customers.
Financial Corporation
- ---------------------
Financial Corporation has several financial investments, including
investments as a limited partner in solar electric generating systems,
windpower electric generating projects and low-income housing projects.
Financial Corporation's total assets were $8.0 million and $11.6
million at Dec. 31, 2003 and 2002, respectively.
56
Segment Information Summary
- ---------------------------
The following table presents summary financial information about the
reportable segments for 2003, 2002 and 2001. Inter-segment transactions
are insignificant.
---------------------------------------------------------------------------------------------------------
Thousands Utility Gas Storage Other Total
---------------------------------------------------------------------------------------------------------
2003
----
Net operating revenues $ 278,856 $ 9,036 $ 174 $ 288,066
Depreciation and amortization 53,798 451 - 54,249
Other operating expenses 130,619 804 122 131,545
Income from operations 94,439 7,781 52 102,272
Income from financial investments 3,406 - 474 3,880
Net income 40,913 4,312 758 45,983
Total assets at Dec. 31, 2003 1,558,342 18,464 14,526 1,591,332
2002
----
Net operating revenues $ 279,414 $ 7,944 186 $ 287,544
Depreciation and amortization 51,693 396 1 52,090
Other operating expenses 118,156 962 78 119,196
Income from operations 109,565 6,586 107 116,258
Income from financial investments 1,390 - 988 2,378
Loss provision for PGE transaction costs - - (8,414) (8,414)
Net income (loss) 47,280 3,646 (7,134) 43,792
Total assets at Dec. 31, 2002 1,432,776 16,403 18,098 1,467,277
2001
----
Net operating revenues $ 271,473 $ 4,368 170 $ 276,011
Depreciation and amortization 49,413 227 - 49,640
Other operating expenses (income) 115,708 489 (37) 116,160
Income from operations 106,352 3,652 207 110,211
Income (loss) from financial investments 1,646 - (321) 1,325
Net income 47,233 2,112 842 50,187
Total assets at Dec. 31, 2001 1,506,787 14,243 29,623 1,550,653
3. CAPITAL STOCK:
- ----------------------
Common Stock
- ------------
At Dec. 31, 2003, NW Natural had reserved 134,240 shares of common
stock for issuance under the Employee Stock Purchase Plan, 353,059
shares for future conversions of its 7-1/4% Convertible Debentures,
389,951 shares under its Dividend Reinvestment and Stock Purchase Plan,
1,751,544 shares under its Restated Stock Option Plan (see Note 4), and
3,000,000 shares under the Shareholder Rights Plan.
Redeemable Preferred Stock
- --------------------------
On Nov. 14, 2003, NW Natural redeemed all of the remaining shares of
its $7.125 Series of Redeemable Preferred Stock with an aggregate
stated value of $7.5 million, at a redemption price equivalent to
102.375 percent with proceeds from sales of commercial paper. The
Company re-financed the commercial paper with the sale of new
long-term debt in the fourth quarter of 2003. The early redemption
premium from the redemption of the $7.125 Series was recognized as an
unamortized cost pursuant to SFAS No. 71 and will be amortized to
expense over the life of the new debt.
57
Redeemable Preference Stock
- ---------------------------
On Dec. 31, 2002, NW Natural redeemed all 250,000 shares of its $6.95
Series of Redeemable Preference Stock with proceeds from the sale of
commercial paper.
Stock Repurchase Program
- ------------------------
NW Natural's Board of Directors approved a stock repurchase program in
2000 to purchase up to 2 million shares, or up to $35 million in value,
of NW Natural's common stock in the open market or through privately
negotiated transactions. The repurchase program has been extended
through May 2004. No shares were repurchased in 2002 or 2003. Since the
program's inception, the Company has repurchased 355,400 shares of
common stock at a total cost of $8.2 million.
Restated Stock Option Plan
- --------------------------
In May 2002, the shareholders approved an amendment to the Restated
Stock Option Plan that increased the total number of shares authorized
for option grants from 1,200,000 to 2,400,000 shares. At Dec. 31, 2003,
options on 1,429,500 shares were available for grant and options on
322,044 shares were outstanding.
58
The following table shows the changes in the number of shares of NW
Natural's capital stock and the premium on common stock for the years
2003, 2002 and 2001:
--------------------Shares------------------- Premium on
Redeemable Redeemable common
Common preference preferred stock
stock stock stock (thousands)
----------------------------------------------------------
Balance, Dec. 31, 2000 25,233,424 250,000 97,500 $238,215
Sales to employees 30,952 - - 498
Sales to stockholders 177,624 - - 3,854
Exercise of stock options - net 12,289 - - 110
Conversion of convertible
debentures to common 20,485 - - 343
Stock repurchases (246,700) - - (2,323)
Sinking fund purchases - - (7,500) -
-------------- ----------- ------------ ----------
Balance, Dec. 31, 2001 25,228,074 250,000 90,000 240,697
Sales to employees 42,862 - - 748
Sales to stockholders 157,288 - - 3,854
Exercise of stock options - net 61,020 - - 1,105
Conversion of convertible
debentures to common 97,069 - - 1,624
Sinking fund purchases - - (7,500) -
Redemption - (250,000) - -
-------------- ------------ ------------ ----------
Balance, Dec. 31, 2002 25,586,313 - 82,500 248,028
Sales to employees 14,175 - - 425
Sales to stockholders 178,714 - - 4,347
Exercise of stock options - net 127,357 - - 2,545
Conversion of convertible
debentures to common 31,443 - - 526
Sinking fund purchases - - (7,500) -
Early redemption - - (75,000) -
-------------- ------------ ------------ ----------
Balance, Dec. 31, 2003 25,938,002 - - $255,871
============== ============ ============ ==========
4. STOCK-BASED COMPENSATION:
- ---------------------------------
NW Natural has the following stock-based compensation plans: the
Long-Term Incentive Plan (LTIP); the Restated Stock Option Plan
(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,
officers and, in the case of the NEDSCP, non-employee directors.
NW Natural's shareholders approved the LTIP effective Jan. 1, 2001, to
provide a flexible, competitive compensation program for eligible
officers. 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 are
purchased on the open market. Through Dec. 31, 2003, NW Natural has
granted four performance-based awards, one based on a two-year
performance period (2001-02) and three based on three-year performance
periods (2001-03, 2002-04 and 2003-05), and one restricted stock award.
The aggregate target awards for each of the 2001-02 and the 2001-03
performance-based award periods were 26,000 shares and the maximum
awards were 52,000 shares; the aggregate target and maximum awards for
the 2002-04 award period were 29,000 and 58,000 shares, respectively;
and the aggregate target and maximum awards for the 2003-05 award
period were 32,000 and 64,000 shares, respectively. Final awards depend
59
on the attainment of certain return on equity performance goals. At
Dec. 31, 2003, the two-year and three-year performance-based awards
that started in 2001 lapsed because the performance-based measures were
not achieved. The restricted stock award consists of 4,500 shares
granted in 2001 with a vesting period of 65 months. The LTIP stock
awards are compensatory awards for which compensation expense is
recognized based on the market value of performance shares earned, or a
pro rata amortization over the vesting period for the restricted stock
award.
The Restated SOP authorizes an aggregate of 2,400,000 shares of common
stock for issuance as incentive or non-statutory stock options. These
options may be granted only to officers and key employees designated by
a committee of NW Natural's Board of Directors. All options are granted
at an option price not less than the market value at the date of grant
and may be exercised for a period not exceeding 10 years from the date
of grant. Option holders may exchange shares they have owned for at
least six months, at the current market price, to purchase shares at
the option price. Since inception in 1985, options on 1,100,921 shares
of common stock have been granted at prices ranging from $11.75 to
$27.875 per share, and options on 130,421 shares have expired.
In accordance with APB No. 25, no compensation expense is recognized
for options granted under the Restated SOP or shares issued under the
ESPP. If compensation expense for awards under these two plans had been
determined based on fair value at the grant dates using the method
prescribed by SFAS No. 123, "Accounting for Stock-Based Compensation,"
net income and earnings per share would have been reduced to the pro
forma amounts shown below:
Pro Forma Effect of Stock Options:
------------------------------------------------------------------------------------
Thousands, except per share amounts 2003 2002 2001
------------------------------------------------------------------------------------
Net income as reported $ 45,983 $ 43,792 $ 50,187
Pro forma stock-based compensation
expense determined under the fair
value based method - net of tax (279) (478) (338)
--------- --------- ---------
Pro forma net income 45,704 43,314 49,849
Redeemable preferred and preference
stock (294) (2,280) (2,401)
--------- --------- ---------
Pro forma earnings applicable to common
stock - basic 45,410 41,034 47,448
Debenture interest less taxes 257 285 370
--------- --------- ----------
Pro forma earnings applicable to
common stock - diluted $ 45,667 $ 41,319 $ 47,818
========= ========= ==========
Basic earnings per share
As reported $ 1.77 $ 1.63 $ 1.90
Pro forma $ 1.76 $ 1.61 $ 1.89
------------------------------------------------------------------------------------
Diluted earnings per share
As reported $ 1.76 $ 1.62 $ 1.88
Pro forma $ 1.75 $ 1.60 $ 1.87
------------------------------------------------------------------------------------
The fair value of each stock option grant is estimated on the grant
date (there were no stock option grants in 2003) using the
Black-Scholes option pricing model with the following weighted average
assumptions:
2002 2001
-----------------------------------------------------------------------
Expected life in years 7.0 7.0
Risk-free interest rate 3.6% 5.2%
Expected volatility 29.1% 31.0%
Dividend yield 4.8% 4.9%
Present value of options granted $20.49 $17.34
-----------------------------------------------------------------------
60
Information regarding the Restated SOP's activity is summarized as
follows:
---------Price per Share----------------
Weighted-Average
Options Range Exercise Price
--------------------------------------------------------------------------------------------
Balance outstanding, Dec. 31, 2000 416,005 $20.17 - 27.875 $ 22.75
Granted 15,000 24.91 24.91
Exercised (12,289) 20.17 - 20.920 20.36
Expired (31,625) 20.25 - 27.875 24.31
--------------------------------------------------------------------------------------------
Balance outstanding, Dec. 31, 2001 387,091 20.25 - 27.875 22.79
Granted 163,750 26.07 - 27.850 26.35
Exercised (68,827) 20.25 - 27.875 21.74
Expired (18,200) 20.25 - 27.875 25.43
--------------------------------------------------------------------------------------------
Balance outstanding, Dec. 31, 2002 463,814 20.25 - 27.875 24.10
Exercised (140,470) 20.25 - 27.875 21.14
Expired (1,300) 20.25 20.25
--------------------------------------------------------------------------------------------
Balance outstanding, Dec. 31, 2003 322,044 20.25 - 27.875 $ 25.35
--------------------------------------------------------------------------------------------
Shares available for grant
Dec. 31, 2001 373,750
--------------------------------------------------------------------------------------------
Shares available for grant
Dec. 31, 2002 1,428,200
--------------------------------------------------------------------------------------------
Shares available for grant
Dec. 31, 2003 1,429,500
--------------------------------------------------------------------------------------------
The weighted average remaining contractual life of outstanding stock
options at Dec. 31, 2003 was 6.5 years.
The characteristics of exercisable stock options at Dec. 31, 2003 were
as follows:
Weighted-
Range of Exercisable Average
Exercise Prices Stock Options Exercise Price
----------------------------------------------------------------------
$20.25-$27.875 213,144 $24.86
The ESPP allows employees to purchase common stock at 85 percent of the
closing price on the trading day immediately preceding the subscription
date, which is set annually. Each eligible employee may purchase up to
$24,000 worth of stock through payroll deduction over a six to 12-month
period.
Effective Feb. 26, 2004, the NEDSCP was amended to permit non-employee
directors to receive stock awards either in cash or in Company stock.
If non-employee directors elect to receive their awards in stock,
approximately $100,000 worth of the Company's common stock is awarded
upon joining the Board. These stock awards are subject to vesting and
to restrictions on sale and transferability. The shares vest in monthly
installments over the five calendar years following the award. On Jan.
1 of each year following the initial award, non-employee directors who
elect to receive awards in Company stock are awarded an additional
$20,000 worth of restricted Company stock, which vests in monthly
installments in the fifth year following the award (after the previous
award has fully vested). The Company holds 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 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 are purchased in the open
market by the Company at the time of the award.
61
The following table presents the changes in unearned stock compensation
for the years 2003 and 2002, which are reported as a reduction to total
common equity in the consolidated balance sheets:
Thousands 2003 2002
-----------------------------------------------------------------------
Unearned stock compensation:
Balance at beginning of year $ 711 $ 372
Purchases of restricted stock 328 891
Restricted stock amortizations (310) (552)
---------- -----------
Balance at end of year $ 729 $ 711
========== ===========
Under a separate plan, non-employee directors also may elect to invest
their cash fees and retainers for board service in shares of the
Company's common stock.
5. 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
property additions, adjusted net earnings and other provisions of the
Mortgage. The Mortgage constitutes a first mortgage lien on
substantially all of NW Natural's utility property.
The 7-1/4% Series of Convertible Debentures may be converted at any
time into 50-1/4 shares of common stock for each $1,000 face value
($19.90 per share).
The maturities on the long-term debt and redeemable preferred stock
outstanding, for each of the 12-month periods through Dec. 31, 2008
amount to: none in 2004; $15 million in 2005; $8 million in 2006; $29.5
million in 2007; and $5 million in 2008. Holders of certain Medium-Term
Notes (MTNs) have put options that, if exercised, would accelerate the
maturity of long-term debt by $10 million in 2005, $20 million in 2007
and $20 million in 2008.
6. NOTES PAYABLE AND LINES OF CREDIT:
- ------------------------------------------
The Company's primary source of short-term funds is commercial paper
notes payable. Both NW Natural and Financial Corporation issue
commercial paper under agency agreements with a commercial bank. NW
Natural's commercial paper is supported by its committed bank lines of
credit (see below), while Financial Corporation's commercial paper is
supported by committed bank lines of credit and the guaranty of NW
Natural. The amounts and average interest rates of commercial paper
debt outstanding at Dec. 31 were as follows:
----------2003------ ----------2002----------
Thousands Amount Rate Amount Rate
-----------------------------------------------------------------------
NW Natural $85,200 1.1% $69,802 1.4%
Financial Corporation - - - -
------- -------
Total $85,200 $69,802
-----------------------------------------------------------------------
NW Natural has lines of credit with four commercial banks totaling $150
million. Half of the credit facility with each bank, totaling $75
million, is committed and available through Sept. 30, 2004, and the
other $75 million is committed and available through Sept. 30, 2005. NW
Natural may be unable to draw upon the two-year portions of the credit
lines, totaling $75 million, until filings are made or approvals
received from the OPUC or the WUTC with respect to its notes relating
to the two-year commitments. NW Natural expects that it will be able to
make the necessary filings or secure such approvals, if required.
Financial Corporation has available through Sept. 30, 2004, committed
lines of credit with two commercial banks totaling $10 million.
Financial Corporation's lines are supported by the guaranty of NW
Natural.
62
Under the terms of these lines of credit, NW Natural and Financial
Corporation pay commitment fees but are not required to maintain
compensating bank balances. The interest rates on borrowings under
these lines of credit, if any, are based on current market rates. There
were no outstanding balances on either the NW Natural or Financial
Corporation lines of credit as of Dec. 31, 2003 or 2002.
NW Natural's lines of credit require that credit ratings be maintained
in effect at all times and that notice be given of any change in its
senior unsecured debt ratings. A change in NW Natural's credit rating
is not an event of default, nor is the maintenance of a specific
minimum level of credit rating a condition to drawing upon the lines of
credit. However, interest rates on any loans outstanding under NW
Natural's bank lines are tied to credit ratings, which would increase
or decrease the cost of bank debt, if any, when ratings are changed.
The lines of credit require the Company to maintain an indebtedness to
total capitalization ratio of 65 percent or less and to maintain a
consolidated net worth at least equal to 80 percent of its net worth at
Sept. 30, 2003, plus 50 percent of the Company's net income for each
subsequent fiscal quarter. Failure to comply with either of these
covenants would entitle the banks to terminate their lending
commitments and to accelerate the maturity of all amounts outstanding.
The Company was in compliance with both of these covenants at Dec. 31,
2003, and with the equivalent covenants in the prior year's lines of
credit at Dec. 31, 2002.
7. PENSION AND OTHER POSTRETIREMENT BENEFITS:
- --------------------------------------------------
NW Natural maintains two qualified non-contributory defined benefit
pension plans covering all regular employees with more than one year of
service, a non-qualified supplemental pension plan for eligible
executive officers and other postretirement benefit plans for its
employees. Only the two qualified defined benefit pension plans have
plan assets. Those assets are held in a qualified trust to fund
retirement benefits.
63
The following table provides a reconciliation of the changes in benefit
obligations and fair value of assets, as applicable, for the pension
plans and other postretirement benefit plans over the three-year period
ended Dec. 31, 2003, and a statement of the funded status and amounts
recognized in the consolidated balance sheets, using measurement dates
of Dec. 31, 2003, 2002 and 2001:
Post-Retirement Benefits
- -----------------------------------------------------------------------------------------------------------------------------------
Pension Benefits Other Postretirement Benefits
- -----------------------------------------------------------------------------------------------------------------------------------
Thousands 2003 2002 2001 2003 2002 2001
- --------- ---- ---- ---- ---- ---- ----
Change in benefit obligation:
Benefit obligation at Jan. 1 $185,124 $166,751 $146,802 $ 18,457 $ 16,987 $ 14,069
Service cost 4,748 4,637 3,964 456 395 325
Interest cost 12,402 11,807 11,332 1,336 1,174 1,116
Expected benefits paid (10,363) (9,453) (9,152) (1,027) (979) (942)
Plan amendments - - 1,838 (111) (300) -
Net actuarial (gain) loss 13,441 11,382 11,967 4,268 1,180 2,419
------------- ---------------- --------------- ---------------- ---------------- ----------------
Benefit obligation at Dec. 31 205,352 185,124 166,751 23,379 18,457 16,987
------------- ---------------- --------------- ---------------- ---------------- ----------------
Change in plan assets:
Fair value of plan assets at
Jan. 1 143,164 168,964 190,451 - - -
Actual return on plan assets 34,520 (17,082) (13,077) - - -
Employer contributions 1,003 735 742 1,027 979 942
Benefits paid (10,363) (9,453) (9,152) (1,027) (979) (942)
------------- ---------------- --------------- ---------------- ---------------- ----------------
Fair value of plan assets at
Dec. 31 168,324 143,164 168,964 - - -
------------- ---------------- --------------- ---------------- ---------------- ----------------
Funded status:
Funded status at Dec. 31 (37,028) (41,960) 2,212 (23,379) (18,457) (16,987)
Unrecognized transition
obligation - - 351 3,703 4,226 4,795
Unrecognized prior service cost 6,240 7,371 8,575 - - 172
Unrecognized net actuarial
(gain) loss 32,156 42,060 (2,956) 8,304 4,437 3,405
------------- ---------------- --------------- --------------- ---------------- -----------------
Net amount recognized $ 1,368 $ 7,471 $ 8,182 $ (11,372) $ (9,794) $ (8,615)
============= ================ =============== =============== ================ =================
Amounts recognized in the
consolidated balance sheets
at Dec. 31
Prepaid benefit cost $ 11,113 $ 17,339 $ 17,211 - - -
Accrued benefit liability (11,319) (18,741) (9,346) (11,372) (9,794) (8,615)
Intangible asset - 4,438 169 - - -
Other comprehensive loss 1,574 4,435 148 - - -
------------- --------------- ---------------- ---------------- --------------- -----------------
Net amount recognized $ 1,368 $ 7,471 $ 8,182 $ (11,372) $ (9,794) $ (8,615)
============= =============== ================ ================ =============== =================
64
The Company's qualified defined benefit pension plans had an
accumulated benefit obligation in excess of plan assets at Dec. 31,
2003. The plans' aggregate accumulated benefit obligation was $192
million, $172 million and $156 million at Dec. 31, 2003, 2002 and 2001,
respectively, and the fair value of plan assets was $168 million, $143
million and $169 million, respectively. The fair value of plan assets
increased from Dec. 31, 2002 to Dec. 31, 2003 due to $36 million in
investment gains, partially offset by $10 million in withdrawals to pay
benefits and $0.9 million to pay eligible expenses of the plans. The
combination of investment returns and cash contributions is expected to
provide sufficient funds to cover all benefit obligations of the plans.
The Company is required to make a cash contribution of at least $1.9
million, and may make an additional contribution up to a total of $6.8
million, to its non-bargaining employee pension plan for the 2003 plan
year, payable by Sept. 15, 2004.
The Company's investment policy and performance objectives for the
qualified pension plan assets (plan assets) held in the Northwest
Natural Gas Company Retirement Trust Fund was approved by a retirement
committee composed of management employees. The policy sets 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 Security Act of 1974 (ERISA). The approved
asset classes are cash and short-term investments, fixed income, common
stock and convertible securities, absolute return strategies, real
estate and investments in securities of NW Natural, and may be invested
in separately managed accounts or in commingled or mutual funds.
Re-balancing will take place at least annually, or when significant
cash flows occur, in order to maintain the allocation of assets within
the stated target allocation ranges. The Retirement Trust Fund is not
currently invested in any NW Natural securities.
The Company's pension plan asset allocation at Dec. 31, 2003 and 2002,
and the target allocation and expected long-term rate of return by
asset category for 2004 are as follows:
Percentage
of Plan Expected
Assets Target Long-term
Dec. 31, Allocation Rate of Return
Asset Category 2003 2002 2004 2004
-----------------------------------------------------------------------
US Large Cap Equity 40.2% 36.3% 40% 9.00%
US Small/Mid Cap Equity 7.3% 4.3% 8% 9.50%
Non-US Equity 16.0% 17.1% 15% 9.00%
Fixed Income 24.8% 34.7% 25% 6.00%
Real Estate 3.9% 2.0% 40% 8.00%
Absolute Return 7.8% 5.6% 8% 9.00%
Weighted Average 8.25%
The Company's non-qualified supplemental pension plan's accumulated
benefit obligation was $13.0 million, $12.8 million and $10.7 million
at Dec. 31, 2003, 2002 and 2001, respectively. Although this plan is an
unfunded plan with no plan assets due to its nature as a non-qualified
plan, the Company indirectly funds its obligations with trust-owned
life insurance. The amount of life insurance coverage is designed to
provide sufficient returns to cover the benefit obligations and other
costs of the plan.
The Company's plans for providing postretirement benefits other than
pensions also are unfunded plans. The aggregate benefit obligation for
those plans was $23.4 million, $18.5 million and $17.0 million at Dec.
31, 2003, 2002 and 2001, respectively.
65
The following tables provide the components of net periodic benefit
cost (income) for the pension and other postretirement benefit plans
for the years ended Dec. 31, 2003, 2002 and 2001, and the assumptions
used in measuring these costs and benefit obligations:
Thousands Pension Benefits Other Postretirement Benefits
--------- ------------------------------------------------------------------
2003 2002 2001 2003 2002 2001
---- ---- ---- ---- ---- ----
Service cost $ 4,748 $ 4,637 $ 3,964 $ 456 $ 395 $ 325
Interest cost 12,402 11,807 11,332 1,336 1,174 1,116
Expected return on
plan assets (12,232) (16,335) (17,198) - - -
Amortization of
transition
obligation - 351 351 411 436 436
Amortization of
prior service cost 1,132 1,204 1,284 - 6 19
Recognized actuarial
(gain) loss 1,058 (216) (2,464) 401 147 75
------ ------- --------- ----- ----- -----
Net periodic benefit
cost (income) $7,108 1,448 $ (2,731) 2,604 2,158 1,971
------ ------- --------- ----- ----- -----
Assumptions:
-----------
Discount rate for net
periodic benefit
cost (NPBC) 6.75% 7.25% 7.50% 6.75% 7.25% 7.50%
Rate of increase
in compensation for
NPBC 4.25-5.00% 4.25-5.00% 4.25-5.00% n/a n/a n/a
Expected long-term
rate of return
for NPBC 8.00% 9.00% 9.00% n/a n/a n/a
Discount rate for
determination
of funded status 6.25% 6.75% 7.25% 6.25% 6.75% 7.25%
Rate of increase in
compensation
for funded status 4.00-4.75% 4.25-5.00% 4.25-5.00% n/a n/a n/a
Expected long-term
rate of return for
funded status 8.25% 8.00% 9.00% n/a n/a n/a
The assumed annual trend rates used in measuring postretirement
benefits as of Dec. 31, 2003 were 9 percent for medical and 14 percent
for prescription drugs. Medical costs were assumed to decrease
gradually each year to a rate of 4.5 percent for 2008, while
prescription drug costs were assumed to decrease gradually each year to
a rate of 4.5 percent for 2013.
Assumed health care cost trend rates 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 1% Increase 1% Decrease
-----------------------------------------------------------------------
Effect on the total service and
interest cost components of
net periodic postretirement
health care benefit cost $ 71 $ (67)
Effect on the health care
component of the accumulated
postretirement benefit obligation $ 955 $ (858)
66
The following table provides information regarding employer
contributions and benefit payments for the pension and other
postretirement benefit plans for the years ended Dec. 31, 2003 and
2002, and estimated future payments:
Other
Pension Postretirement
Thousands Benefits Benefits
-----------------------------------------------------------------------
Employer Contributions by Plan Year
-----------------------------------
2002 $ 735 $ 979
2003 2,949 1,027
2004 (estimated) 3,007 1,509
-----------------------------------------------------------------------
Benefit Payments
----------------
2002 $ 9,440 $ 979
2003 10,363 1,027
-----------------------------------------------------------------------
Estimated Future Benefit Payments
---------------------------------
2004 $11,667 $ 1,509
2005 12,224 1,555
2006 12,698 1,674
2007 12,965 1,770
2008 13,811 1,883
2009-2013 78,915 10,312
NW Natural's Retirement K Savings Plan (RKSP) is a qualified defined
contribution plan under Internal Revenue Code Section 401(k). NW
Natural also has a non-qualified deferred compensation plan 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. NW Natural's matching contributions to these
plans totaled $1.6 million in 2003, $1.4 million in 2002 and $1.3
million in 2001.
Effective Jan. 1, 2002, the RKSP was amended to establish an Employee
Stock Ownership Plan (ESOP) within the RKSP by converting the existing
RKSP Company Stock Fund into an ESOP. This amendment allowed the
Company to claim a tax benefit of $0.2 million in both 2003 and 2002
for the dividends paid on the Company's common stock held by the ESOP.
In order to claim this deduction, the Company was required to allow
RKSP participants the option of receiving the dividends paid on the
Company's common stock in the ESOP account in cash rather than having
the dividends automatically reinvested (see Note 8).
67
8. INCOME TAXES:
- ---------------
A reconciliation between income taxes calculated at the statutory
federal tax rate and the tax provision reflected in the financial
statements is as follows:
Thousands 2003 2002 2001
-------------------------------------------------------------------------------------------------------------------
Computed income taxes based on statutory federal income
tax rate of 35% $ 24,263 $ 23,533 $ 27,209
Increase (reduction) in taxes resulting from:
Difference between book and tax depreciation 222 222 222
Current state income tax, net of federal tax benefit 2,310 2,299 2,672
Federal income tax credits (357) (362) (362)
Amortization of investment tax credits (879) (858) (855)
Gains on Company and trust-owned life insurance (1,192) (487) (576)
Removal costs (925) (573) (508)
Reversal of amounts provided in prior years (226) (240) (72)
Other - net 124 (90) (177)
--------- -------- --------
Total provision for income taxes $ 23,340 $ 23,444 $ 27,553
========= ======== ========
Total income taxes paid $ 13,940 $ 33,474 $ 25,201
========= ======== ========
The provision for income taxes consists of the following:
Thousands 2003 2002 2001
-------------------------------------------------------------------------------------------------------------------
Income taxes currently payable:
Federal $ 10,011 $ 9,377 $ 32,682
State 1,175 1,239 5,912
--------- -------- --------
Total 11,186 10,616 38,594
--------- -------- --------
Deferred taxes - net:
Federal 10,747 11,476 (8,606)
State 2,286 2,210 (1,580)
--------- -------- --------
Total 13,033 13,686 (10,186)
--------- -------- --------
Investment and energy tax credits restored:
From utility operations (801) (800) (800)
From subsidiary operations (78) (58) (55)
--------- -------- --------
Total (879) (858) (855)
--------- -------- --------
Total provision for income taxes $ 23,340 $ 23,444 $ 27,553
========= ======== ========
Percentage of pretax income 33.7% 34.9% 35.4%
========= ======== ========
68
Deferred tax assets and liabilities are comprised of the
following:
Thousands 2003 2002
-------------------------------------------------------------------------------------------------------------------
Deferred tax liabilities:
Plant and Property $ 113,781 $ 96,525
Regulatory income tax assets 63,449 47,975
Regulatory liabilities - 319
Other deferred liabilities 6,109 6,569
--------- --------
Total 183,339 151,388
--------- --------
Deferred tax assets:
Regulatory assets 970 -
Minimum pension liability 557 1,883
Other deferred aasets 10,015 7,773
--------- --------
Total 11,542 9,656
--------- --------
Net accumulated deferred income tax liability $ 171,797 $141,732
========= ========
Tax benefits of $1.3 million associated with charges for minimum
pension liabilities in 2002 were reversed in OCI for the year ended
Dec. 31, 2003.
9. PROPERTY AND INVESTMENTS:
- ---------------------------------
The following table sets forth the major classifications of NW
Natural's utility plant and accumulated depreciation at Dec. 31:
2003 2002
-------------------------------------- -----------------------------------
Average Average
Depreciation Depreciation
Thousands Amount Rate Amount Rate
---------------------------------------------------------------------------------------------------------------------
Transmission and distribution $ 1,347,402 3.3% $ 1,254,624 3.4%
Utility Storage 107,547 2.7% 107,110 2.7%
General 87,107 6.0% 83,878 6.3%
Intangible and other 56,429 5.1% 53,291 4.3%
------------- ------------
Utility plant in service 1,598,485 3.5% 1,498,903 3.5%
Gas stored long-term 12,778 11,301
Construction work in progress 47,826 29,761
------------- ------------
Total utility plant 1,659,089 1,539,965
Accumulated depreciation (471,716) (435,601)
------------- ------------
Utility plant-net $ 1,187,373 $ 1,104,364
============= ============
Accumulated depreciation does not include $135.6 million and $125.2
million at Dec. 31, 2003 and 2002, respectively, due to the
reclassification of accumulated depreciation relating to removal costs
in accordance with SFAS No. 143 (see Note 1).
69
The following table summarizes the Company's investments in non-utility
plant at Dec. 31:
Thousands 2003 2002
-------------------------------------------------------------------------
Non-utility storage $18,507 $17,037
Dock, land, oil station and other 3,846 3,795
Construction work in progress 1,042 -
----------- -----------
Total non-utility plant 23,395 20,832
Less accumulated depreciation 4,855 4,404
----------- -----------
Non-utility plant - net $18,540 $16,428
=========== ===========
-------------------------------------------------------------------------
The following table summarizes the Company's partnership and joint
venture investments accounted for under the equity or cost methods, and
its investment in an aircraft leveraged lease, at Dec. 31:
Thousands 2003 2002
-------------------------------------------------------------------------
Aircraft leveraged lease $ 6,438 $ 6,489
Gas pipeline and other 2,880 2,950
Electric generation 3,317 3,264
----------- -----------
Total other investments $12,635 $12,703
=========== ===========
-------------------------------------------------------------------------
In 1987, the Company invested in a Boeing 737-300 aircraft, which is
leased to Continental Airlines for 20 years under a leveraged lease
agreement.
A Financial Corporation subsidiary, KB Pipeline Company, has a 10
percent ownership interest in an 18-mile interstate natural gas
pipeline and is the operator of this pipeline. In December 2003, KB
Pipeline gave notice to the pipeline co-owners that it is resigning as
pipeline operator effective in June 2004 due to increased obligations
resulting from the Federal Energy Regulatory Commission's final
regulations implementing Standards of Conduct for Transmission
Providers. Those regulations govern the relationship between interstate
natural gas pipelines and their energy affiliates or marketing
functions and impose obligations previously inapplicable to KB Pipeline
with regard to separation of duties and related matters. The
regulations will continue to be applicable to KB Pipeline as a co-owner
after its resignation as pipeline operator.
Financial Corporation has ownership interests ranging from 4.0 to 5.3
percent in solar electric generation plants located near Barstow,
California. Power generated by these plants is sold to Southern
California Edison Company under long-term contracts. Financial
Corporation also has ownership interests ranging from 25 to 41 percent
in wind power electric generation projects located near Livermore and
Palm Springs, California. The wind-generated power is sold to Pacific
Gas and Electric Company and Southern California Edison Company under
long-term contracts.
70
10. FAIR VALUE OF FINANCIAL INSTRUMENTS:
- --------------------------------------------
The estimated fair value for NW Natural's financial instruments has
been determined using available market information and appropriate
valuation methodologies. The following are financial instruments whose
carrying values are sensitive to market conditions:
Dec. 31, 2003 Dec. 31, 2002
--------------------------------- --------------------------------
Carrying Estimated Carrying Estimated
Thousands Amount Fair Value Amount Fair Value
----------------------------------------------------------------------------------------------------------------------
Redeemable preferred stock $ - $ - $ 8,250 $ 8,333
Long-term debt including amount due
within one year $500,319 $562,688 $465,945 $518,495
--------------------------------------------------------------------------------------------------------------
Fair value of the redeemable preferred stock and long-term debt was
estimated using market prices in effect on the valuation date. Interest
rates for debt with similar terms and remaining maturities were used to
estimate fair value for long-term debt issues.
11. USE OF FINANCIAL DERIVATIVES:
- -------------------------------------
NW Natural enters into short-term and long-term natural gas purchase
contracts with suppliers, including contracts tied to floating prices.
As such, NW Natural is exposed to changes in commodity prices. Natural
gas prices are subject to fluctuations due to unpredictable factors
including weather, inventory levels, pipeline transportation
availability, and the economy, each of which affects short-term supply
and demand. As part of its overall strategy to maintain an acceptable
level of exposure to gas price fluctuations, NW Natural uses a targeted
mix of fixed-rate and cap-protected derivative instruments to hedge the
exposure under floating price gas supply contracts. Swap contracts are
used to convert certain long-term gas purchase contracts from floating
prices to fixed prices. Call option contracts are used to limit the
maximum adverse impact from floating price contracts while retaining
the potential favorable impact from declining gas prices. The prices
embedded in these commodity hedge contracts are incorporated in NW
Natural's annual rate changes under its Purchased Gas Adjustment rate
mechanisms, thereby limiting customers' exposure to frequent changes in
purchased gas costs. The estimated fair value of gains and losses from
commodity hedge contracts are recorded as a derivative asset or
liability, and are offset by a corresponding amount recorded to a
deferred regulatory asset or liability account for the effective
portion of each hedge contract. The actual gains and losses realized at
settlement of the hedge contracts are used to offset the actual
purchase cost from NW Natural's physical supply contracts.
Certain natural gas purchases from Canadian suppliers are invoiced in
Canadian dollars, including both commodity and demand charges, thereby
exposing NW Natural to adverse changes in foreign currency rates.
Foreign currency forward contracts are used to minimize the impact of
fluctuations in currency rates. Foreign currency contracts for
commodity costs are purchased on a month-to-month basis because the
Canadian cost is priced at the average noonday exchange rate for each
month. Foreign currency contracts for demand costs have terms ranging
up to 24 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 longer-term currency contracts for
demand charges are subject to a regulatory deferral tariff and, as
such, are recorded as a derivative asset or liability which is offset
by a corresponding amount to a deferred asset or liability account.
71
NW Natural did not use any derivative instruments to hedge oil or
propane prices or interest rates during 2003, 2002 or 2001.
At Dec. 31, 2003, NW Natural had the following derivatives outstanding
covering its exposures to commodity and foreign currency prices: a
series of 20 natural gas price swap contracts, three natural gas call
option contracts, and 77 foreign currency forward contracts. Each of
these contracts was designated as a cash flow hedge. The estimated fair
values and the notional amounts of derivative instruments (unrealized
gains and losses) outstanding were as follows:
Dec. 31, 2003 Dec. 31, 2002
------------------------- -------------------------
Fair Value Notional Fair Value Notional
Thousands Gain (Loss) Amount Gain (Loss) Amount
-----------------------------------------------------------------------------------------------------------------------
Fixed-price natural gas commodity swap contracts $ 23,285 $ 284,317 $ 11,422 $ 159,724
Fixed-price natural gas call option contracts 366 19,761 717 18,084
Physical natural gas supply contract with embedded derivative - - 448 2,754
Foreign currency forward purchase contracts 234 6,417 (161) 15,525
------------------------- -------------------------
Total $ 23,885 $ 310,495 $ 12,426 $ 196,087
========================= =========================
In 2003, NW Natural realized net gains of $32.4 million from the
settlement of natural gas commodity swap and call option contracts,
which were recorded as decreases to the cost of gas, compared to net
losses of $75.5 million during 2002 and net gains of $57.6 million
during 2001. The currency exchange rate in all foreign currency forward
purchase contracts is included in NW Natural's cost of gas at
settlement; therefore, no gain or loss was recorded from the settlement
of those contracts. The change in value of cash flow hedge contracts,
not included in regulatory recovery, is included in OCI.
The fair value of derivative instruments at Dec. 31, 2003 (see table
above) was determined using estimated or quoted market prices for the
periods covered by the contracts. Market prices for the natural gas
commodity-price swap and call option contracts were obtained from
external sources. NW Natural reviews these third-party valuations for
reasonableness using fair value calculations for other contracts with
similar terms and conditions. The market prices for the foreign
currency forward contracts were based on currency exchange rates quoted
by The Bank of Canada.
As of Dec. 31, 2003, NW Natural had five natural gas commodity price
swap contracts extending beyond Dec. 31, 2004, but none extends beyond
Oct. 31, 2005. None of the natural gas commodity call option contracts
extends beyond March 31, 2004.
12. COMMITMENTS AND CONTINGENCIES:
- --------------------------------------
Lease Commitments
-----------------
The Company leases land, buildings and equipment under agreements that
expire in various years through 2018. Rental expense under operating
leases was $4.9 million, $4.8 million and $4.7 million for the years
ended Dec. 31, 2003, 2002 and 2001, respectively. The table below
reflects the future minimum lease payments due under non-cancelable
leases at Dec. 31, 2003. Such payments total $74.5 million for
operating leases. The net present value of payments on capital leases
less imputed interest was $0.3 million. These commitments principally
relate to the lease of the Company's office headquarters, underground
gas storage facilities, vehicles and computer equipment.
72
Later
Millions 2004 2005 2006 2007 2008 years
-----------------------------------------------------------------------------------------------------
Operating leases $ 4.3 $ 3.8 $ 3.8 $ 3.7 $ 3.6 $ 55.3
Capital leases 0.1 0.1 0.1 - - -
-------- -------- ------- ------ ------- --------
Minimum lease payments $ 4.4 $ 3.9 $ 3.9 $ 3.7 $ 3.6 $ 55.3
======== ======== ======= ====== ======= ========
Pipeline Capacity Purchase and Release Commitments
--------------------------------------------------
NW Natural has signed agreements providing for the availability of firm
pipeline capacity under which it must 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, NW Natural has entered into long-term sale agreements to
release firm pipeline capacity. The aggregate amounts of these
agreements were as follows at Dec. 31, 2003:
Pipeline Pipeline
Capacity Capacity
Purchase Release
Thousands Agreements Agreements
---------------------------------------------------------------------------------------------------------
2004 $ 56,296 $ 3,781
2005 60,540 3,782
2006 57,772 3,781
2007 57,773 3,782
2008 56,245 3,781
2009 through 2023 301,397 6,933
------------- -----------
Total 590,023 25,840
Less: Amount representing interest 128,151 3,463
------------- -----------
Total at present value $ 461,872 $ 22,377
============= ===========
NW Natural's total payments of fixed charges under capacity purchase
agreements in 2003, 2002 and 2001 were $86.7 million, $86.2 million and
$86.5 million, respectively. Included in the amounts for 2003, 2002 and
2001 were reductions for capacity release sales of $3.7 million, $4.2
million and $3.8 million, respectively. 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
---------------------
NW Natural owns 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 NW Natural for
environmental contamination under the Oregon Department of
Environmental Quality's (ODEQ) Voluntary Clean-Up Program. On June 30,
2003, the Company 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. NW Natural will work with the ODEQ to determine the appropriate
remedial action from among the alternatives. Based upon the proposed
actions in the draft plan, the Company estimates its range of remaining
liability, including the cost of investigation, from feasible
alternatives, at between $1.5 million and $7 million. At Dec. 31, 2003,
NW Natural had liabilities totaling $1.5 million outstanding,
regulatory deferred costs of $0.2 million and a $2.5 million insurance
73
receivable, for its estimated costs of investigation and interim
remediation at the Gasco site, including consultants' fees, ODEQ
oversight reimbursement and legal fees.
NW Natural previously owned property adjacent to the Gasco site that
now is the location of a manufacturing plant owned by Wacker Siltronic
Corporation (the Wacker site). In 2000, the ODEQ issued an order
requiring Wacker and NW Natural to determine the nature and extent of
releases of hazardous substances to Willamette River sediments from the
Wacker site. NW Natural has completed the majority of the studies
required under the ODEQ work plan and the agency is reviewing data
generated by the studies. At Dec. 31, 2003, NW Natural recorded
liabilities totaling $0.3 million for its estimated costs of the
investigation and initial remediation on the Wacker site, nearly all of
which had been spent as of Dec. 31, 2003.
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 (the Portland Harbor) that includes the area adjacent to the
Gasco site and the Wacker site. In 2000, the EPA listed the Portland
Harbor as a Superfund site and notified the Company that it is a
potentially responsible party. Between 2000 and 2003, NW Natural
recorded liabilities totaling $2.6 million, of which $1.9 million had
been spent as of Dec. 31, 2003. The amount of NW Natural's liability is
based on estimates of the Company's share of the lower end of a range
of probable liability for the costs of the Remedial
Investigation/Feasibility Study for the Portland Harbor. Available
information is insufficient to determine either the total amount of
liability for investigation and remediation of the Portland Harbor or
the higher end of a range for NW Natural's estimated share of that
liability. On March 1, 2004, the Company received a letter from the EPA
requesting that the Company enter into a consent order relating to
removal of certain contaminants in the riverbed adjacent to the Gasco
site. The Company is reviewing the EPA's request and has not determined
what its response will be, or what a reasonable estimate of the cost
would be for any action the Company might take in response to the
request.
The City of Portland notified NW Natural that it was planning a sewer
improvement project that would include excavation within the former
site of a gas manufacturing plant (the Portland Gas site) that was
owned and operated by a predecessor of the Company between 1860 and
1913. The preliminary assessment of this site performed by a consultant
for the EPA in 1987 indicated that it could be assumed that by-product
tars may have been disposed of on site. The report concluded, however,
that it is likely that waste residues from the plant, if present on the
site, were covered by deep fill during construction of the nearby
seawall bordering the Willamette River and probably have stabilized due
to physical and chemical processes. Neither the City of Portland nor
the ODEQ has notified NW Natural whether a further investigation or
potential remediation might be required on the site in connection with
the sewer project, which has commenced. Available information is
insufficient to determine either the total amount of NW Natural's
liability or a probable range, if any, of potential liability.
In May 2003, the OPUC approved NW Natural's request for deferral of
environmental costs associated with specific sites, including the
Gasco, Wacker, Portland Gas and Portland Harbor sites. The
authorization, effective for a 12-month period beginning April 7, 2003,
allows NW Natural to defer and seek recovery of unreimbursed
environmental costs in a future general rate case. The Company recorded
a cumulative deferral of $1.0 million in environmental costs related to
these specific sites in 2003. Additionally, on a cumulative basis
through Dec. 31, 2003, the Company has accrued environmental costs
totaling $8.0 million relating to the sites, including $5.9 million
that has already been disbursed.
NW Natural has accrued all material loss contingencies relating to
environmental matters that it believes to be probable of assertion and
reasonably estimable. Due to the preliminary nature of these
environmental investigations, the range of any additional possible loss
contingency cannot be currently estimated. NW Natural will first seek
to recover the costs of further investigation and remediation for which
it may be responsible with respect to the Gasco site, the Wacker site,
the Portland Harbor site and the Portland Gas site, if any, from
insurance. If these costs are not recovered from insurance, then NW
Natural will seek recovery through future rates. At Dec. 31, 2003, NW
Natural had a $3.7 million receivable representing an estimate of the
74
environmental costs NW Natural expects to incur and recover from
insurance, including $2.5 million for costs relating to the Gasco site
and $1.25 million for costs relating to the Portland Harbor site.
Enron Gas Supply Contract
-------------------------
On Oct. 16, 2003, NW Natural received a demand letter from Enron North
America Corp. (Enron) seeking payment of $1.1 million allegedly owed
pursuant to a gas supply contract between NW Natural and Enron, which
was in effect when Enron filed for bankruptcy in December 2001. The
contract was terminated when Enron filed for bankruptcy, and NW Natural
does not believe that any amounts are owed to Enron under the contract.
NORTHWEST NATURAL GAS COMPANY
QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
Dollars Quarter ended
---------------------------------------------------------
(Thousands, except per share amounts) March 31 June 30 Sept. 30 Dec. 31 Total
- ---------------------------------------------------------------------------------------------------------
2003
Operating revenues $206,539 $117,489 $69,481 $217,747 $611,256
Net operating revenues 98,588 58,549 39,465 91,464 288,066
Net income (loss) 26,404 4,462 (6,546) 21,663 45,983
Basic earnings (loss) per share 1.03 0.17 (0.25) 0.84 1.77 /*/
Diluted earnings (loss) per share 1.01 0.17 (0.25) 0.83 1.76 /*/
2002
Operating revenues $278,563 $101,873 $78,717 $182,223 $641,376
Net operating revenues 110,666 56,564 38,059 82,255 287,544
Net income (loss) 34,447 (2,992) (6,008) 18,345 43,792
Basic earnings (loss) per share 1.34 (0.14) (0.26) 0.70 1.63 /*/
Diluted earnings (loss) per share 1.32 (0.14) (0.26) 0.69 1.62 /*/
<FN>
/*/ 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 the Company's business.
</FN>
75
NORTHWEST NATURAL GAS COMPANY
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
- -----------------------------------------------------------------------------------------------------------------
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E
- -----------------------------------------------------------------------------------------------------------------
Additions Deductions
Balance at ----------------------------------------- Balance
beginning Charged to Charged to at end
of costs other Net of
period and expenses accounts write-offs period
------ ------------ -------- ---------- -------
Thousands (year ended December 31)
2003
- ----
Reserves deducted in balance
sheet from assets to which they apply:
Allowance for uncollectible accounts $1,815 $1,990 $0 $2,042 $1,763
2002
- ----
Reserves deducted in balance
sheet from assets to which they apply:
Allowance for uncollectible accounts $1,962 $2,876 $0 $3,023 $1,815
2001
- ----
Reserves deducted in balance
sheet from assets to which they apply:
Allowance for uncollectible accounts $1,867 $3,359 $0 $3,264 $1,962
76
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
As of Dec. 31, 2003, the principal executive officer and principal
financial officer of the Company have evaluated the effectiveness of the design
and operation of the Company's disclosure controls and procedures (as defined in
Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934, as amended
(Exchange Act)). Based upon that evaluation, the principal executive officer and
principal financial officer of the Company have concluded that such disclosure
controls and procedures are effective in timely alerting them to any material
information relating to the Company and its consolidated subsidiaries required
to be included in the Company's reports filed with or furnished to the
Securities and Exchange Commission under the Exchange Act.
(b) Changes in Internal Control Over Financial Reporting
There has been no change in the Company's internal control over
financial reporting that occurred during the Company's most recent fiscal
quarter that has materially affected, or is reasonably likely to materially
affect, the Company's internal control over financial reporting.
77
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
Information concerning the Company's Board of Directors and the Audit
Committee financial expert contained in the Company's definitive Proxy Statement
for the May 27, 2004 Annual Meeting of Shareholders is hereby incorporated by
reference.
Age at
Name December 31, 2003 Positions held during last five years
---- ----------------- -------------------------------------
Mark S. Dodson 58 President and Chief Executive Officer
(2003- ); President, Chief Operating
Officer and General Counsel (2001-02);
Senior Vice President, Public Affairs
and General Counsel (1998-01); Senior
Vice President (1997).
Michael S. McCoy 60 Executive Vice President, Customer and
Utility Operations (2000- ); Senior
Vice President, Customer and Utility
Operations (1999-00); Senior Vice
President, Customer Services
(1992-99).
Bruce R. DeBolt 56 Senior Vice President, Finance, and
Chief Financial Officer (1990- ).
Gregg S. Kantor 46 Senior Vice President, Public and
Regulatory Affairs (2003- ); Vice
President, Public Affairs and
Communications (1998-02).
Beth A. Ugoretz 48 Senior Vice President and General
Counsel (2003- ); Executive Vice
President, Kindercare Learning
Centers, Inc. (1997-00).
Lea Anne Doolittle 48 Vice President, Human Resources
(2000- ); Director of Compensation
(1993-2000), PacifiCorp.
Stephen P. Feltz 48 Treasurer and Controller (1999- );
Assistant Treasurer (1996-99);
Manager, General Accounting
(1996-99).
C. J. Rue 58 Secretary (1982- ); Assistant
Treasurer (1987- ).
Richelle T. Luther 35 Assistant Secretary (2002- );
Associate, Stoel Rives, LLP
(1997-02).
Each executive officer serves successive annual terms; present terms end May 27,
2004. There are no family relationships among the Company's executive officers.
The Company has 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 the Company's website at www.nwnatural.com.
78
ITEM 11. EXECUTIVE COMPENSATION
Information concerning Executive Compensation contained in the
Company's definitive Proxy Statement for the May 27, 2004 Annual Meeting of
Shareholders is hereby incorporated by reference. Information related to
Executive Officers as of December 31, 2003 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 the Company are authorized for issuance as of
Dec. 31, 2003 (see Note 12 to the Consolidated Financial Statements):
(A) (B) (C)
Number of securities
remaining available for
Number of securities future issuance under
to be issued upon Weighted-average equity compensation
exercise of exercise price of plans (excluding
outstanding options, outstanding options, securities reflected
Plan Category warrants and rights warrants and rights in column (a))
- ------------------------------------------------------------------------------------------------------------------
Equity compensation plans
approved by security holders:
Long-Term Incentive Plan
(LTIP)(Target Award)/1/ 61,000 N/A 434,500
Restated Stock Option Plan 322,044 $25.35 1,429,500
Employee Stock Purchase Plan 30,956 $24.70 103,284
Equity compensation plans not
approved by security holders:
Executive Deferred Compensation Plan
(EDCP)/2/ 9,202 N/A N/A
Directors Deferred Compensation Plan
(DDCP)/2/ 72,003 N/A N/A
Non-Employee Directors Stock
Compensation Plan/3/ N/A N/A N/A
------------------- ---------------------
Total 495,205 $25.30 1,967,284
=================== =====================
Certain other information called for by Item 12 is incorporated herein
by reference to portions of the Company's definitive Proxy Statement for the May
27, 2004 Annual Meeting of Shareholders.
- --------------------
<FN>
/1/ Shares issued pursuant to the LTIP do not include an exercise price,
but are payable by the Company when the award criteria are satisfied. If the
maximum awards were paid pursuant to awards outstanding at Dec. 31, 2003, the
number of shares shown in column (a) would increase by 61,000 shares and the
number of shares shown in column (c) would decrease by 61,000 shares.
/2/ At the participant's election, deferred amounts may be credited to
either a "cash account" or a Company "stock account." If deferred amounts are
credited to stock accounts, such accounts are credited with a number of shares
based on the purchase price of the Common Stock on the next purchase date under
the Company's Dividend Reinvestment and Stock Purchase Plan, and such accounts
are credited with additional shares based on the deemed reinvestment of
dividends. 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. The Company has contributed Common Stock to the trustee of the
Umbrella Trust such that the Umbrella Trust holds the number of shares of Common
Stock equal to the number of shares credited to all participants' stock
accounts.
/3/ The material features of this plan are more particularly described in
Note 4 to the Consolidated Financial Statements included in this report.
</FN>
79
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The information captioned "Certain Relationships and Related
Transactions" in the Company's definitive Proxy Statement for the May 27, 2004
Annual Meeting of Shareholders is hereby incorporated by reference.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
The information captioned "Other Matters-Selection of Independent
Auditors" in the Company's definitive Proxy Statement for the May 27, 2004
Annual Meeting of Shareholders is hereby incorporated by reference.
PART IV
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(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 82.
(b) Reports on Form 8-K.
A report on Form 8-K dated Nov. 4, 2003 was furnished to the SEC on
November 4, 2004 regarding a press release issued by the Company
concerning earnings for the quarter and nine months ended Sept. 30,
2003. The report was furnished under Item 12, "Results of Operations
and Financial Condition."
A report on Form 8-K dated Jan. 29, 2004 was filed with the SEC on Jan.
29, 2004 regarding a press release issued by the Company concerning
earnings for the fiscal year ended Dec. 31, 2003. Information in the
report was filed with respect to disclosure under Item 5, "Other Events
and Regulation FD Disclosure" and furnished with respect to disclosure
under Item 12, "Results of Operations and Financial Condition."
80
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: March 9, 2004 By: /s/ Mark S. Dodson
---------------------------------
Mark S. Dodson, 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 TITLE DATE
- ------------------------------------------------------------------------------------------------------
/s/ Mark S. Dodson Principal Executive Officer and Director March 9, 2004
- --------------------------------
Mark S. Dodson, President
and Chief Executive Officer
/s/ Bruce R. DeBolt Principal Financial Officer March 9, 2004
- --------------------------------
Bruce R. DeBolt
Senior Vice President, Finance,
and Chief Financial Officer
/s/ Stephen P. Feltz Principal Accounting Officer March 9, 2004
- --------------------------------
Stephen P. Feltz
Treasurer and Controller
/s/ Timothy P. Boyle Director )
- -------------------------------- )
Timothy P. Boyle )
)
/s/ John D. Carter Director )
- -------------------------------- )
John D. Carter )
)
/s/ C. Scott Gibson Director )
- -------------------------------- )
C. Scott Gibson )
)
/s/ Tod R. Hamachek Director )
- -------------------------------- )
Tod R. Hamachek )
)
/s/ Randall C. Pape Director ) March 9, 2004
- -------------------------------- )
Randall C. Pape )
)
/s/ Richard G. Reiten Director )
- -------------------------------- )
Richard G. Reiten )
)
/s/ Robert L. Ridgley Director )
- -------------------------------- )
Robert L. Ridgley )
)
/s/ Melody C. Teppola Director )
- -------------------------------- )
Melody C. Teppola )
)
/s/ Russell F. Tromley Director )
- -------------------------------- )
Russell F. Tromley )
)
/s/ Richard L. Woolworth Director )
- --------------------------------
Richard L. Woolworth
81
EXHIBIT INDEX
-------------
To
Annual Report on Form 10-K
For Fiscal Year Ended
December 31, 2003
Exhibit Number Document
-------------- --------
*(3a.) Restated Articles of Incorporation, as filed
and effective June 24, 1988 and amended
December 8, 1992, December 1, 1993 and May
27, 1994 (incorporated herein by reference
to Exhibit (3a.) to Form 10-K for 1994, File
No. 0-994).
*(3b.) Bylaws as amended December 18, 2003
(incorporated herein by reference to Exhibit
4(b) in File No. 333-112604).
*(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).
82
Exhibit Number Document
-------------- --------
*(4g.) Rights Agreement, dated as of February 27, 1996,
between the Company and Boatmen's Trust Company
(Mellon Investor Services LLC, successor), which
includes as Exhibit A thereto the form of a
Right Certificate and as Exhibit B thereto the
Summary of Rights to Purchase Common Shares
(incorporated herein by reference to Exhibit 1
to Form 8-A, dated February 27, 1996, File No.
0-994).
*(4h.) Amendment No. 1, dated October 5, 2001, to
Rights Agreement, dated February 27, 1996,
between the Company and Boatmen's Trust
Company (Mellon Investor Services LLC,
successor) (incorporated herein by reference
to Exhibit 4 to Form 10-Q for quarter ended
September 30, 2001, File No. 0-994).
*(10j.) Transportation Agreement, dated June 29,
1990, between the Company and Northwest
Pipeline Corporation (incorporated herein by
reference to Exhibit (10j.) to Form 10-K for
1993, File No. 0-994).
*(10j.(1)) Replacement Firm Transportation Agreement,
dated July 31, 1991, between the Company and
Northwest Pipeline Corporation (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 Corporation 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).
(11) Statement re computation of per share
earnings.
(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.
83
Exhibit Number Document
-------------- --------
(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, 1995 Restatement (incorporated herein
by reference to Exhibit (10b.) to Form 10-K
for 1994, File No. 0-994).
*(10b.-1) 1995 Amendment to Executive Supplemental
Retirement Income Plan (1995 Restatement)
(incorporated herein by reference to Exhibit
(10b.-1) to Form 10-K for 1995, File No.
0-994).
*(10b.-2) Amendment 1998-1 to the Executive
Supplemental Retirement Income Plan (1995
Restatement) (incorporated herein by
reference to Exhibit 10(a) to Form 10-Q for
the quarter ended September 30, 1998, File
No. 0-994).
*(10b.-3) ESRIP Change in Control Amendment to the
Executive Supplemental Retirement Income
Plan (1995 Restatement) (incorporated herein
by reference to Exhibit 10(b) to Form 10-Q
for the quarter ended September 30, 1998,
File No. 0-994).
*(10c.) Restated Stock Option Plan, as
amended effective May 23, 2002 (incorporated
herein by reference to Exhibit 10(a) to Form
10-Q for quarter ended September 30, 2002,
File No. 0-994).
*(10e.) ExecutiveDeferred Compensation Plan,
effective as of January 1, 1987, Restated as
of January 1, 2003 (incorporated herein by
reference to Exhibit (10 e.) to Form 10-K
for 2002, File No. 0-994).
..
(10f.) Directors Deferred Compensation Plan,
effective June 1, 1981, restated as of
February 26, 2004
*(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 February 26,
2004.
*(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).
..
*(10n.) Employment agreement dated November 2, 1995,
as amended February 27, 1996, between the
Company and an executive officer
(incorporated herein by reference to Exhibit
(10n.) to Form 10-K for 1995, File No.
0-994).
84
Exhibit Number Document
-------------- --------
*(10n.-1) Amendment dated December 18, 1997 to
employment agreement dated November 2, 1995,
as previously amended February 27, 1996,
between the Company and an executive officer
(incorporated herein by reference to Exhibit
(10n.-1) to Form 10-K for 1997, File No.
0-994).
*(10n.-2) Amendment dated September 24, 1998 to
employment agreement dated November 2, 1995,
as previously amended, between the Company
and an executive officer (incorporated
herein by reference to Exhibit 10(e) to Form
10-Q for the quarter ended September 30,
1998, File No. 0-994).
*(10n.-3) Summary of Compensation Arrangements for
Chairman of the Board, March 1, 2003 -
February 28, 2005 (incorporated herein by
reference to Exhibit (10n.-3)) to Form 10-K
for 2002, File No. 0-994).
*(10o.) Form of amended and restated executive
change in control severance agreement as
entered into between the Company and each
executive officer (incorporated herein by
reference to Exhibit 10(a) to Form 10-Q for
the quarter ended June 30, 2001, File No.
0-994).
*(10o.(1)) Form of change in control letter agreement
as entered into between the Company and each
executive officer (incorporated herein by
reference to Exhibit 10(a) to Form 10-Q for
the quarter ended September 30, 2001, File
No. 0-994).
*(10p.) Employment Agreement dated July 2, 1997,
between the Company and an executive officer
(incorporated herein by reference to Exhibit
10(a) for Form 10-Q for the quarter ended
September 30, 1997, File No. 0-994).
*(10p.-1) Amendment dated December 18, 1997 to
employment agreement dated July 2, 1997,
between the Company and an executive officer
(incorporated herein by reference to Exhibit
(10p.-1) to Form 10-K for 1997, File No.
0-994).
*(10p.-2) Amendment dated September 24, 1998 to
employment agreement dated July 2, 1997, as
previously amended, between the Company and
an executive officer (incorporated herein by
reference to Exhibit 10(g) to Form 10-Q for
the quarter ended September 30, 1998, File
No. 0-994).
*(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. 0-994).
..
*(10r.) Employment agreement dated May 11, 1999,
between the Company and an executive officer
(incorporated herein by reference to Exhibit
10 to Form 10-Q for the quarter ended June
30, 1999, File No. 0-994).
*(10u.) Separation Agreement and Mutual Release of
All Claims between the Company and an executive
officer, dated February 28, 2001 (incorporated
herein by reference to Exhibit (10u.) to Form
10-K for 2000, File No. 0-994).
85
Exhibit Number Document
-------------- --------
*(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.) Restricted stock retention agreement, dated
August 1, 2001, as entered into between the
Company and an executive officer (incorporated
herein by reference to Exhibit 10(b) to Form
10-Q for the quarter ended June 30, 2001, File
No. 0-994).
The Company agrees to furnish the Commission, upon request, a
copy of certain instruments defining rights of holders of
long-term debt of the Company or its consolidated
subsidiaries which authorize securities thereunder in amounts
which do not exceed 10% of the total assets of the Company.
- -------------------------------------
*Incorporated herein by reference as indicated