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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 [FEE REQUIRED]
For the fiscal year ended December 31, 1993
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934 [NO FEE REQUIRED]
For the Transition period from ___________ to____________
Commission file number 0-994
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 Number)
220 N.W. Second Avenue, Portland, Oregon 97209
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: (503) 226-4211
Securities registered pursuant to Section 12(b) of the Act:
Title of each class Name of each exchange on which registered
- ------------------- -----------------------------------------
None None
Securities registered pursuant to Section 12(g) of the Act:
Title of each class Shares outstanding on February 28, 1994
- ------------------- ---------------------------------------
Common Stock, $3 1/6 par value 13,219,706
Preference Stock, without par value 314,680
Preferred Stock, without par value 170,333
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 ].
The aggregate market value of the shares of voting stock (common stock) held by
non-affiliates of the registrant at February 28, 1994 was: $470,016,700
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, dated April 15, 1994, are
incorporated by reference in Part III.
NORTHWEST NATURAL GAS COMPANY
Annual Report to Securities and Exchange Commission
on Form 10-K
for the year 1993
Table of Contents
PART I Page
Item 1. Business
General. . . . . . . . . . . . . . . . . . . . . . . 1
Service Area . . . . . . . . . . . . . . . . . . . . 2
Gas Supply . . . . . . . . . . . . . . . . . . . . . 2
Transportation . . . . . . . . . . . . . . . . . . . 7
Regulation and Rates . . . . . . . . . . . . . . . . 7
Competition and Marketing. . . . . . . . . . . . . . 10
Construction and Financing Programs. . . . . . . . . 12
Environment. . . . . . . . . . . . . . . . . . . . . 12
Employees. . . . . . . . . . . . . . . . . . . . . . 13
Item 2. Properties. . . . . . . . . . . . . . . . . . . . . . . 13
Item 3. Legal Proceedings . . . . . . . . . . . . . . . . . . . 14
Item 4. Submission of Matters to a Vote of Security Holders . . 15
Additional Item
Executive Officers of the Registrant. . . . . . . . . . 16
PART II
Item 5. Market for the Registrant's Common Equity and Related
Stockholder Matters. . . . . . . . . . . . . . . . . . 17
Item 6. Selected Financial Data . . . . . . . . . . . . . . . . 19
Item 7. Management's Discussion and Analysis of Results of
Operations and Financial Condition . . . . . . . . . . 20
Item 8. Financial Statements and Supplementary Data . . . . . . 32
Item 9. Changes in and Disagreements with Accountants
on Accounting and Financial Disclosure . . . . . . . . 68
PART III
Items
10. - 13. Incorporated by Reference to Proxy Statement . . . . 68
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports
on Form 8-K. . . . . . . . . . . . . . . . . . . . . . 68
SIGNATURES . . . . . . . . . . . . . . . . . . . . . . . . . . 72
NORTHWEST NATURAL GAS COMPANY
PART I
ITEM 1. BUSINESS
General
- -------
Northwest Natural Gas Company (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. The Company is principally engaged in the distribution of
natural gas to customers in western Oregon and southwestern
Washington, including the Portland metropolitan area.
Basic industries served by the Company include pulp,
paper and other forest products; the processing of farm and food
products; lumber and plywood; the production of various mineral
products; the manufacture of electronic, electrochemical and
electrometallurgical products; metal fabrication and casting; and
the production of machine tools, machinery and textiles. The
City of Portland, Oregon is the principal retail and
manufacturing center in the Columbia River Basin. It is a major
port and growing nucleus for trade with Pacific Rim nations such
as Japan and Korea.
The Company has four subsidiaries, each of which is
incorporated in the State of Oregon: Oregon Natural Gas
Development Corporation (Oregon Natural), NNG Financial
Corporation (Financial Corporation), NNG Energy Systems, Inc.
(Energy Systems) and Pacific Square Corporation (Pacific Square).
Oregon Natural is engaged in natural gas exploration,
development and production in Oregon and other western states,
and, through its wholly-owned subsidiary, Canor Energy Ltd.
(Canor), an Alberta Corporation, also engages in gas and oil
exploration, development and production in Alberta and
Saskatchewan, Canada. Oregon Natural also holds an equity
investment in a Boeing 737-300 aircraft. (See Part I, Item 2,
and Part II, Item 8, Note 2 and Note 11.)
Financial Corporation holds financial investments as a
limited partner in four solar electric generating plants, four
wind power electric generation projects and a hydroelectric
project, all located in California, and in a low-income housing
project in Portland. Financial Corporation also arranges short-
term financing for the Company's operating subsidiaries. (See
Part II, Item 8, Note 11.)
Energy Systems, through its wholly-owned subsidiary,
Agrico Cogeneration Corporation (Agrico), formerly owned a 25
megawatt cogeneration plant near Fresno, California. In
December 1991, Agrico filed a voluntary petition for
reorganization under Chapter 11 of the United States Bankruptcy
Code. In November 1992, Agrico entered into a settlement with
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Pacific Gas & Electric Company (PG&E), the utility which
purchased plant energy and capacity from Agrico, and Wellhead
Electric Company (Wellhead), the contract operator of the Agrico
plant, with respect to PG&E's claimed overpayments to Agrico for
power purchased in 1990 and 1991. In January 1994, the
California Public Utilities Commission's order approving Agrico's
settlement with PG&E and Wellhead became final, and the U.S.
Bankruptcy Court entered its order confirming Agrico's
reorganization plan. The Court's order and the reorganization
plan became final and the sale of Agrico's assets to Wellhead
closed in February 1994. (See Part I, Item 3, and Part II,
Item 8, Note 3.)
Pacific Square is engaged in real estate management,
principally in connection with two office buildings in Portland
and other Company-owned properties adjacent to those buildings.
Pacific Square has entered into an agreement to sell its
interests in the partnership that owns these buildings. (See
Part I, Item 2, and Part II, Item 8, Note 2 and Note 12.)
Service Area
- ------------
The Oregon Public Utility Commission (OPUC) has
allocated to the Company as its exclusive service area a major
portion of western Oregon, including most of the fertile
Willamette Valley and the coastal area from Astoria to Coos Bay.
The Company also holds certificates from the Washington Utilities
and Transportation Commission (WUTC) granting it exclusive rights
to serve portions of three Washington counties bordering the
Columbia River. Gas service is provided in 95 cities, together
with neighboring communities, in 16 Oregon counties, and in nine
cities and neighboring communities in three Washington counties.
The Company's service areas have a population of about 2,600,000,
including about 78 percent of the population of the State of
Oregon.
Gas Supply
- ----------
General
-------
The Company meets the needs of its core market
(residential, commercial and firm industrial) customers through
natural gas purchases from a variety of suppliers. The Company
has a diverse portfolio of short-, medium- and long-term firm gas
supply contracts, and, during periods of peak demand, supplements
this supply with gas from storage facilities which are either
owned by or contractually committed to the Company.
Natural gas for the Company's core market is
transported by Northwest Pipeline Corporation (NPC) under a
contract expiring September 30, 2013, providing for the delivery
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of firm requirements of up to 2,460,440 therms(1) per day. NPC's
rates for this service are established by the Federal Energy
Regulatory Commission (FERC) under NPC's primary firm
transportation rate schedule, as amended or superseded from time
to time.
Commencing in April 1993, the Company added 500,000
therms per day of firm transportation capacity for its core
market through participation in an expansion of NPC's system, and
an expansion of Pacific Gas Transmission's (PGT) pipeline through
central Oregon, southeastern Washington and northern Idaho. In
combination, this additional firm transportation capacity
provides a connection through Alberta Natural Gas Company Ltd.'s
(ANG) system to producing regions of Alberta, Canada.
The cost of gas to supply the Company's core market
consists of amounts paid to suppliers of the gas commodity and
peaking services plus transportation charges paid to pipelines in
the United States and Canada. While the rates for pipeline
transportation and peaking services are regulated, the prices of
gas purchased under the supply contracts are not. Although both
gas commodity and pipeline costs have increased, the Company has
been able to minimize the effect of such increases on core market
prices by taking advantage of medium-term fixed price supply
contracts negotiated in 1991, and by negotiating off-system sales
agreements which partially offset pipeline costs in periods when
the core market does not require full utilization of firm
pipeline capacity.
The Company supplies many of its larger industrial
interruptible customers (those customers with full or partial
dual fuel capabilities) through gas transportation service,
delivering gas purchased by these customers directly from
suppliers.
Core Market System Supply
-------------------------
The Company purchases gas for its core market from a
variety of suppliers located in the western United States and
Canada. At December 31, 1993, the Company had 19 contracts with
15 suppliers with original terms of from four months to 15 years
which provided for a maximum of 2,718,250 therms of firm gas per
- -----------------------
[FN]
(1) For gas quantities expressed in therms, 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. MMBtu means one million Btu's, or 10 therms.
For gas quantities expressed in cubic feet, unless otherwise
indicated, all volumes are stated at a pressure base of
14.73 pounds per square inch absolute at 60 degrees
Fahrenheit, and in some instances are rounded to the nearest
major multiple. Mcf means one thousand cubic feet, Mmcf
means one million cubic feet and Bcf means one billion cubic
feet.
-3-
day during the peak winter season and 1,804,060 therms per day
during the non-peak season. About three-fourths of this supply
comes from Canada and the remainder from the United States,
including a small portion which is locally produced in Oregon.
The terms of the Company's principal purchase
agreements are summarized as follows:
An agreement expiring November 1, 2003 with CanWest Gas
Supply, Inc. (CanWest), an aggregator for gas producers in
British Columbia, Canada, entitles the Company to purchase up to
approximately 960,000 therms of firm gas per day. This agreement
contains a demand and commodity pricing structure and a provision
for annual renegotiations of the commodity price to reflect
then-prevailing market prices. The demand charges reflect the
reservation of firm transportation space on the Westcoast Energy,
Inc. pipeline system in British Columbia. These demand charges
are subject to change as approved by the Canadian National Energy
Board (NEB) in rate proceedings similar to those conducted in the
United States by the FERC. Under this agreement, the Company
also has the ability to purchase gas between May 1 and October 31
each year for injection into storage facilities at a commodity
price, to be renegotiated annually, substantially below the
commodity price for gas for current use. This contract contains
a pro rata market share commitment and minimum purchase
obligations.
An agreement also expiring November 1, 2003 with Amoco
Canada Petroleum Company, Ltd., on terms similar to the CanWest
agreement, entitles the Company to purchase up to approximately
83,300 therms of firm gas per day. This gas is aggregated from
production in Alberta and the Canadian Yukon and Northwest
Territories. This contract contains a pro rata market share
commitment and minimum purchase obligations.
An agreement with Poco Petroleums, Ltd. (Poco), a
Canadian producer, expiring September 30, 2003, entitles the
Company to purchase up to 155,160 therms per day during the
winter and up to 110,000 therms per day during the summer. The
gas is produced in Alberta and makes use of the Company's added
capacity from transportation on the PGT and ANG systems.
Two agreements expiring September 30, 2003 with
Westcoast Gas Services entitle the Company to purchase up to
140,000 therms per day year-round, plus up to 92,750 therms per
day of winter season supply. This gas is produced in Alberta and
makes use of the Company's new capacity on the PGT and ANG
systems. Pricing for supplies under this agreement can be
renegotiated annually. The current pricing arrangement includes
demand charges for upstream capacity on the Canadian pipeline
systems, a monthly reservation charge and a fixed commodity
price.
An agreement expiring October 31, 1996 with Poco
entitles the Company to purchase up to 200,000 therms of firm gas
-4-
per day. This agreement contains a demand and commodity pricing
structure, a provision for annual renegotiations of the commodity
price, minimum purchase obligations and a pro rata market share
commitment. The demand charge is subject to NEB regulation.
This gas is produced in Alberta and British Columbia.
An agreement expiring September 30, 2000 with Summit
Resources Ltd. entitles the Company to purchase up to 77,580
therms per day during the winter and up to 50,000 therms per day
during the summer. This gas is produced in Alberta and makes use
of the Company's added capacity from transportation on the PGT
and ANG systems. Pricing for supplies under this agreement can
be renegotiated annually. The current pricing arrangement
includes demand charges for upstream capacity on NOVA Corporation
of Alberta's system and commodity charges that are separated into
three tiers.
An agreement expiring October 31, 1994 with Natural Gas
Clearinghouse, one of the largest independent gas marketers in
the United States, entitles the Company to purchase up to 100,000
therms of firm gas per day. This gas is produced in the United
States Rocky Mountain region. The pricing structure for this
agreement contains a monthly reservation charge plus a commodity
charge based on monthly trade indices. Prices are renegotiated
annually. This contract contains a pro rata market share
commitment.
An agreement with Nahama & Weagant Energy Company
(NWEC) expiring January 1, 1995 entitles the Company to purchase
all of the production from the wells at Mist, Oregon that
previously had been under contract with Atlantic Richfield
(ARCO). Although production from these wells continues to
decline, it provides a supply delivered within the Company's
service territory. Production from these wells averages nearly
50,000 therms per day and is priced based on the Company's
weighted average cost of gas.
An agreement with NWEC expiring December 31, 1994
entitles the Company to purchase all of the production from new
wells at Mist. Production from these wells currently provides
the Company with more than 70,000 therms per day. Pricing is
based on an average of monthly spot price indices adjusted for
delivery to the Company's service territory.
During 1993, new purchase agreements for firm gas were
entered into with Vastar Resources, Inc. for 200,000 therms per
day; with Coastal Gas Marketing Company for 180,000 therms per
day; with Enron Gas Marketing for 100,000 therms per day; with
Grand Valley Gas Company for 100,000 therms per day; with
Universal Resources for 50,000 therms per day; and with Union
Pacific Fuels for 100,000 therms per day. These agreements are
similarly structured, as follows: each is for a four-month term,
from November 1, 1993 through February 28, 1994; each provides
volumes based on a combination of reservation charges and indexed
commodity prices; and all but one has a minimum volume obligation
-5-
at a fixed price. All of the gas purchased under these
agreements is produced in the United States Rocky Mountain and
San Juan Basin regions.
The Company also purchases small volumes of gas on the
spot (30 days or less) market as necessary to supplement its firm
core market supplies, to extend the deliverability of its storage
resources and to take advantage of available favorable pricing
opportunities. During 1993, less than one percent of the
Company's purchases for its core market was from this source.
The Company manages gas purchases for its core market
in a manner that will meet customers' needs at reasonable prices.
The Company 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. Future gas
costs, generally, will track prevailing market conditions for
supplies of similar reliability.
Peaking Supplies
----------------
During peak demand periods, the Company supplements its
firm gas supplies through Company-owned or contracted peaking
facilities in which gas can be stored during periods of low
demand for redelivery during periods of peak demand. In addition
to enabling the Company to meet its peak demand, these facilities
make it possible to lower the cost of gas by allowing the Company
to reduce its pipeline transportation contract demand and to
purchase gas for storage during the summer months when purchase
prices are generally at their lowest.
The Company has contracts with NPC for firm storage
services from the underground gas storage field at Jackson
Prairie and the liquefied natural gas (LNG) facility at Plymouth,
Washington which together provide a daily deliverability of
831,380 therms and a total seasonal capacity of 13,082,647 therms
through October 2004. In addition, the Company has contracted
with NPC for an additional daily deliverability of 94,670 therms
and an additional 2,779,970 therms of seasonal capacity from the
Jackson Prairie storage field through April 1996.
The Company owns and operates two LNG plants which it
uses to liquefy gas during the summer months for redelivery into
its system during the peak winter season. These two plants, one
located in Portland and the other near Newport, Oregon, provide a
maximum daily deliverability of 1,800,000 therms and a total
seasonal capacity of 17,000,000 therms. The LNG plants provide a
cost-effective winter peaking resource of high reliability and
flexibility.
The Company also owns and operates an underground gas
storage facility at Mist, Oregon. This facility has a maximum
daily deliverability of 1,000,000 therms and a total seasonal
working gas capacity of about 70,000,000 therms, or about 15
-6-
percent of the Company's annual core customer usage. These
underground gas storage facilities provide a reliable, cost-
effective winter supply that is available for a much longer
period than the LNG plants.
In January 1993, the Company and Portland General
Electric Company (PGE) entered into an agreement expiring in 2010
that provides the Company with a cost-effective winter peaking
supply and PGE with needed firm pipeline transportation. With
certain limitations, the Company may interrupt gas deliveries to
PGE, use that gas for the Company's own markets, and compensate
PGE by paying PGE's cost for replacement fuel oil. The daily
volume is 300,000 therms, increasing to a maximum of 760,000
therms in November 1995. This agreement makes it possible for
the Company to recover the full cost of firm transportation
capacity while obtaining firm gas deliveries during peak load
periods at a cost that is competitive with other peaking
services.
Transportation
- --------------
By 1992, most of the Company's large industrial
interruptible sales customers had switched from sales service to
transportation service. Since 1992, about half of these
customers have returned to sales service, primarily because the
Company's industrial sales rates were lower than those customers'
costs of purchasing and shipping their own gas. The ability of
industrial customers to switch between sales service and
transportation service has assisted the Company in retaining most
of these customers and has not had a material effect on the
Company's results of operations. (See "Competition and Marketing"
and Part II, Item 7.)
Regulation and Rates
- --------------------
The Company 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 1993, approximately
90.0 percent of the Company's gas deliveries and 94.6 percent of
its utility operating revenues were derived from Oregon and the
balance from Washington. The Company is exempt from the
provisions of the federal Natural Gas Act by order of the Federal
Power Commission.
The Company's most recent general rate case in Oregon,
which was effective in 1989, authorized rates designed to produce
a return on common equity of 13.25 percent. The most recent
general rate increase in Washington, which was effective in 1986,
authorized rates also designed to produce a return on common
equity of 13.25 percent. Actual revenues resulting from the
OPUC's and WUTC's general rate orders are dependent on weather,
economic conditions, competition and other factors affecting gas
usage in the Company's service area. The Company has no plans to
-7-
file general rate cases in either Oregon or Washington in 1994.
The Company's returns on average common equity from consolidated
operations were 5.8 percent in 1992 and 13.7 percent in 1993.
In Oregon, the Company has a Purchased Gas Cost
Adjustment (PGA) tariff under which the Company's net income
derived from Oregon operations is affected only 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 the Company's gas requirements for the
12-month period ended each June 30. Any resulting rate
adjustments, derived from gas prices negotiated for the gas
supply contract year commencing on the following November 1, are
made effective on the following December 1.
The PGA tariff also provides that 80 percent of any
difference between actual gas commodity costs and related costs
incorporated into rates will be deferred for amortization in
subsequent periods. If actual gas commodity costs exceed those
incorporated in rates, the Company subsequently will adjust its
rates upward to recover 80 percent of the deficiency from core
market customers. Similarly, if actual commodity costs are lower
than those reflected in rates, rates will be adjusted downward to
refund to core market customers 80 percent of such gas commodity
cost savings.
In Washington, the Company is permitted to track
increases and decreases in its cost of purchased gas coincidental
with their incurrence, with the result that net income is not
directly affected by changes in purchased gas costs.
In April 1992, the FERC issued Order No. 636 and
subsequently largely affirmed that order on rehearing in Order
Nos. 636-A and 636-B. These orders required significant changes
in the structure of service provided by interstate pipelines and
required such pipelines to restructure or "unbundle" their
services and eliminate their role as gas merchants. In October
1992, NPC, the primary interstate pipeline serving the Company,
made a filing with the FERC to comply with Order No. 636 and
filed a general rate case seeking FERC approval to increase its
rates. The impact of these filings, as approved by the FERC, was
an increase in the Company's annual cost of interstate pipeline
service of approximately $16.5 million effective April 1, 1993.
NPC's rate increase also included the cost of its $432 million
"Phase I Expansion" completed in April 1993, under which the
Company subscribed to 500,000 therms per day of new firm
capacity, and reflected a change in NPC's rate design to the
FERC-mandated "straight fixed-variable" method, which collects
all fixed costs through monthly demand charges.
In April 1993, the Company filed with the OPUC for rate
increases averaging 6.2 percent in its residential, commercial
and industrial firm schedules to offset the Company's higher
costs for interstate pipeline capacity approved by the FERC for
-8-
NPC. The OPUC approved these rate increases effective May 1,
1993. Effective June 1, 1993, the WUTC approved rate increases
averaging 6.7 percent for the Company's Washington customers to
offset the same cost increases.
In August 1993, the Company filed with the OPUC for
rate increases averaging 3 percent. The OPUC approved the
increases effective October 1, 1993. These rate increases were
due to the removal of temporary rate discounts in effect since
November 1990 to refund to customers gas cost savings and
pipeline rate refunds resulting from NPC's transition to "open
access" transportation.
In November 1993, the Company filed for rate increases
under its PGA tariffs averaging 3.7 percent for Oregon customers
and 7.6 percent for Washington customers. The OPUC and WUTC
approved these increases for their respective states effective
December 1, 1993. These rate increases passed through to
customers the effect of higher gas costs, and removed temporary
rate discounts related to prior gas cost savings which had
applied to rates for firm gas service since December 1992.
In connection with filings by the Company each year
under the PGA tariff, the OPUC has reviewed the Company's
earnings as determined for a recently-completed 12-month period,
normalized for average weather conditions and certain other
adjustments to revenues or expenses as applied in the Company's
last general rate case. The OPUC has taken the position that it
may reduce the amount of a rate increase requested to offset
higher gas costs if its review of normalized earnings were to
show that the resulting return on equity would exceed a
reasonable range for the Company under then-current financial
conditions. Based upon such a review in 1993, the Company and
the OPUC staff negotiated an agreement whereby the Company
reduced the revenue increase requested pursuant to its November
1993 PGA filing by about $2,334,000 per year. The Company
expects the OPUC to conduct a similar review in connection with
its PGA filing to be effective in December 1994, but cannot
predict whether the effect, if any, of such a review on future
earnings would be material.
In Oregon, the Company has an Interruptible Sales
Adjustment (ISA) tariff schedule which levels margin (sales price
less cost of gas) fluctuations resulting from the volatility of
sales to large industrial interruptible customers caused by price
competition between natural gas and residual fuel oil. Under the
ISA tariff schedule, the Company's rates are increased or
decreased at least annually to compensate for deviations in
actual industrial interruptible margins from assumed base
margins. If the actual margin is below the base margin for any
month, the Company's rates applicable to core market customers
are adjusted upward to recover 80 percent of the margin
deficiency, plus interest. Likewise, if the actual margin is
above the base margin, rates subsequently are adjusted downward
to return 80 percent of the margin excess, plus interest. At
-9-
year-end 1993, the ISA account had a credit (refund) balance of
$2.4 million. This tariff schedule enhances the Company's
opportunity to achieve its allowed rate of return and reduces
fluctuations in earnings due to changes in industrial
interruptible sales.
The OPUC and WUTC have approved transportation tariffs
under which the Company may contract with customers to deliver
customer-owned gas. Under these tariffs, revenues from the
transportation of customer-owned gas, except that of large
industrial customers having the capability of bypassing the
Company's system, generally are equivalent to the margins that
would have been realized from sales of Company-owned gas. (See
"Transportation" and "Competition and Marketing".)
The OPUC and WUTC have instituted "least-cost planning"
processes under which utilities develop plans defining
alternative growth scenarios and resource acquisition strategies.
In 1991, the OPUC and WUTC acknowledged and accepted the
Company's submissions of its first Least Cost Plan, and required
further planning during 1992 and 1993, including the development
of demand-side (conservation) resources.
In October 1993, the Company filed its 1993 Integrated
Resource (Least Cost) Plan, with the OPUC and the WUTC. The plan
discusses potential growth in gas demand and describes a range of
possible future supply-side and demand-side resource options to
meet the demand. The plan forecasts growth in peak day load
averaging 2.9 percent per year from 1993 to 2002, 2.3 percent
from 1993 to 2012 and 2 percent from 1993 to 2022. The long-term
resources available to meet this growth include the interstate
pipelines, storage, conservation and long-term industrial
contracts with provisions for the recall of released pipeline
capacity and gas supplies. An updated Least Cost Plan will be
filed in mid-1994 in Oregon and then in Washington.
Competition and Marketing
- -------------------------
Although the Company has no direct competition in the
territory it serves from other natural gas utility distributors,
it competes with NPC to serve large industrial customers; with
oil and, to a lesser extent, electricity, for industrial uses;
with oil, electricity and wood for residential use; and with oil
and electricity for commercial uses. Competition among these
forms of energy is based on price, quality of service, efficiency
and performance. In 1993, the Company maintained its competitive
price advantage over electricity and approximate price parity
with fuel oil in both the residential and commercial markets.
Throughout 1993, natural gas rates continued to be substantially
lower than rates for electricity provided by the investor-owned
utilities which serve approximately 75 percent of the homes in
the Company's Oregon service area. The Company believes that
this rate advantage will continue for the foreseeable future. As
a result of substantial price increases in recent years by the
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Bonneville Power Administration, the wholesale supplier of much
of the electricity sold by publicly-owned electric utilities in
the Pacific Northwest, natural gas for home heating also is more
competitive with electricity provided by public utility
districts.
During 1993, the Company provided gas for spaceheating
to about 85 percent of the new single family homes built within
the reach of the Company's system. The relatively low (estimated
at between 30 and 35 percent) residential (single family and
attached dwelling) saturation of natural gas in the Company's
service territory, 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 conversion market. In 1993, 17,941 net (after
subtracting disconnected or terminated services) residential
customers were added, including 8,710 units of existing
residential housing which were reconnected to the system or were
converted from oil or electric appliances to natural gas. More
than half of these customers also use gas for water heating. In
addition, 1,501 net commercial customers were connected in 1993.
The net total of all new customers added in 1993 was 19,449.
This constituted a growth rate of 5.5 percent, more than double
the national average for local distribution companies as reported
by the American Gas Association.
Residential and commercial volumes increased
26.8 percent to 481.3 million therms in 1993, largely due to
increased heating requirements resulting from colder weather.
For the year 1993, temperatures in the Company's service
territory, as expressed in heating degree days, were 22 percent
colder than those of 1992, and were 3 percent colder than the
20-year average. Residential and commercial revenues in 1993
constituted approximately 80 percent of the Company's total
utility operating revenues which were derived from 46 percent of
the total therms delivered. (See Part II, Item 7.)
Natural gas sales and transportation deliveries to
industrial firm customers during 1993 totalled 99.8 million
therms which was 5.6 percent above the 1992 level of 94.5 million
therms. In 1993, 10 percent of total utility operating revenues
and 10 percent of total therms delivered were derived from
deliveries to industrial firm customers.
Total natural gas sales and transportation deliveries
to industrial interruptible customers decreased 22.0 percent in
1993, from 591.1 million therms in 1992, to 462.5 million therms
in 1993. These deliveries included the transportation of
29.3 million therms to two electric generating plants in 1993,
down from 165.2 million therms transported to the same plants in
1992. In 1993, 10 percent of total utility operating revenues
and 44 percent of total therms delivered were derived from sales
and transportation deliveries to industrial interruptible
customers.
-11-
The Company and most of its largest industrial
customers have entered into high-volume interruptible
transportation agreements to replace agreements that were
scheduled to expire. During 1993, the Company negotiated new
agreements with these customers on a case-by-case basis with
terms extending from two years to ten years. These agreements
are designed to provide rates that are competitive with costs for
alternative fuels, such as heavy oil, by reducing the per-therm
transportation rate. They also are designed to provide rates
competitive with "bypass" (direct connection to interstate
pipelines) by applying fixed charges that vary with each
customer's distance from NPC's facilities. These agreements
prohibit bypass during their terms.
In November 1993, the Company's second largest
industrial customer, the James River Corporation plant at Camas,
Washington, switched to NPC for the delivery of gas, thus
bypassing the Company's system. This customer accounted for
about 2.7 percent of total deliveries and 0.2 percent of total
revenues in 1992.
The Company does not expect a significant number of its
other large customers to bypass its system in the foreseeable
future since these customers typically are served under tariffs
which are designed to be competitive with capital and operating
costs of direct connections to NPC's system. (See Part II,
Item 7.)
In February 1994, the OPUC authorized the Company to
enter into agreements with industrial customers, without prior
regulatory approval, providing for the Company to release, at
negotiated rates, rights to portions of its firm pipeline
capacity and natural gas transportation services. In its order
authorizing the Company to enter into such agreements, the OPUC
concluded that rate flexibility was warranted because competition
for such services exists. The OPUC's order, which implements
legislation adopted by the Oregon legislature in 1993, allows the
Company to compete effectively in this market. Eighty percent of
all positive net revenues (gross revenues less the actual cost of
gas or pipeline capacity) generated from these agreements will be
credited to core customer gas costs.
Construction and Financing Programs
- -----------------------------------
See Part II, Item 7, Management's Discussion and
Analysis of Results of Operations and Financial Condition.
Environment
- -----------
The Company is subject to air, water and other
environmental regulation by state and federal authorities and has
complied in all material respects with applicable regulations.
Compliance with these regulations has had no material effect upon
-12-
the capital expenditures, earnings or the competitive position of
the Company.
The Company owns property in Linnton, Oregon and
previously owned property in Salem, Oregon that were former sites
of gas manufacturing plants. Both sites are under investigation
for potential remediation. (See Part II, Item 7, and Item 8,
Note 12.)
Employees
- ---------
At year-end 1993, the Company had 1,293 employees, of
which 932 were members of the Office and Professional Employees
International Union, Local No. 11. These union employees
approved a five-year Joint Accord covering wages, benefits and
working conditions effective April 1, 1992.
ITEM 2. PROPERTIES
The Company's natural gas distribution system consists
of 9,313 miles of mains, as well as 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. The
Company also holds all necessary permits for the crossing of the
Willamette River and a number of small rivers by its mains.
The Company 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. (See below.) District offices are maintained on
owned or leased premises at convenient points in the distribution
system. The Company owns LNG facilities in Portland and near
Newport, Oregon, and also owns two natural gas reservoirs at
Mist, Oregon.
The Company considers all of its properties currently
used in its operations, both owned and leased, to be well
maintained, in good operating condition, and adequate for its
present and foreseeable future needs.
The Company's Mortgage and Deed of Trust constitutes a
first mortgage lien on substantially all of the real property
constituting its utility plant.
Oregon Natural holds interests in United States oil and
gas leases covering 52,606 net acres. These interests are
located in western Oregon, California, Sweetwater County,
Wyoming, and La Plata and Rio Blanco Counties in Colorado. Canor
owns interests in 19 gas properties and six oil properties in
-13-
southern Alberta and southern Saskatchewan covering mineral
rights on 124,052 net acres. Most Canadian gas production is
sold under long-term contracts to markets in both Canada and the
United States. Oregon Natural also holds an equity investment in
a Boeing 737-300 aircraft.
Energy Systems formerly owned a 25 megawatt
combined-cycle cogeneration system near Fresno, California
through its wholly-owned subsidiary, Agrico, which filed a
voluntary petition for reorganization under Chapter 11 of the
U.S. Bankruptcy Code in December 1991. The U.S. Bankruptcy Court
confirmed Agrico's reorganization plan in January 1994, allowing
the sale of Agrico's assets to Wellhead Electric Company, the
contract operator of the Agrico facility, to close in February
1994. (See Part I, Item 3, and Part II, Item 7, and Item 8,
Note 2 and Note 3.)
Pacific Square, the Company's subsidiary engaged in
real estate management, owns a one-half interest in One Pacific
Square, a 227,000 square foot office building in Northwest
Portland, through a partnership known as Pacific Square
Associates. The Company's corporate headquarters occupy about
63 percent of this building which is 100 percent leased. Pacific
Square Associates, in partnership with the Portland Metropolitan
Chamber of Commerce, owns a 31,000 square foot office building
adjacent to One Pacific Square. This building is fully leased.
In January 1994, Pacific Square entered into an agreement to sell
all of its partnership interests in the two buildings to Hillman
Properties Northwest (Hillman), Pacific Square's joint venture
partner. Under the agreement, Hillman will purchase Pacific
Square's interests in the Pacific Square Associates partnership
and assume all of the partnership's joint obligations. The
transaction is expected to close by the end of April 1994.
ITEM 3. LEGAL PROCEEDINGS
The Company previously reported that Agrico had entered
into a conditional settlement with PG&E and Wellhead with respect
to PG&E's claimed overpayments to Agrico for power purchased in
1990 and 1991. (See Part II, Item 8 of the Company's Annual
Report on Form 10-K for the fiscal year ended December 31, 1992.)
In December 1993, this settlement was approved by the California
Public Utilities Commission. In January 1994, the U.S.
Bankruptcy Court confirmed Agrico's reorganization plan,
including the terms of the settlement with PG&E and Wellhead.
Following such confirmation, in February 1994, Agrico's assets
were sold to Wellhead in a transaction that will not have a
material effect on 1994 earnings. Under the terms of the sale to
Wellhead, Energy Systems received $860,000 in cash and
$2.4 million in notes in return for its secured debt interests in
Agrico. In March 1994, Energy Systems provided a fund of
$150,000 from the cash proceeds for pro rata distribution to
Agrico's unsecured creditors. (See Part II, Item 8, Note 3.)
-14-
The Company is party to certain legal actions in which
claimants seek material amounts. Although it is impossible to
predict the outcome with certainty, based upon the opinions of
legal counsel, management does not expect disposition of these
matters to have a material adverse effect on the Company's
financial position or results of operations.
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 December 31, 1993.
-15-
ADDITIONAL ITEM. EXECUTIVE OFFICERS OF THE COMPANY
Age at
December 31, Positions held during
Name 1993 last five years
- ------------------ ---------- ---------------------------------------
Robert L. Ridgley 59 President and Chief Executive Officer
(1985- ); Director (1984- ); Chairman
of the Executive Committee of the Board
(1985- ).
Bruce R. DeBolt 46 Senior Vice President, Finance, and
Chief Financial Officer (1990- );
Senior Vice President, Finance and
Administration (1987-90); General
Counsel (1983-90).
Dwayne L. Foley 48 Senior Vice President, Operations and
Information Services (1992- );
Senior Vice President, Gas
Operations and Information Services
(1990-92); Vice President, Gas
Supply and Pipeline Relations
(1985-90).
Paul L. Hathaway 59 Senior Vice President, Districts and
Administrative Services (1992- );
Senior Vice President, Marketing,
Districts and Administrative
Services (1990-92); Senior Vice
President, Market Services and Human
Resources (1987-90).
Michael S. McCoy 50 Senior Vice President, Customer Services
Division (1992- );
Vice President, Operations (1990-
92); Vice President, Districts
(1984-90).
Bruce B. Samson 58 Senior Vice President, Public Affairs
(1990- ); General Counsel (1990- );
Senior Vice President, Regulatory
Affairs (1990); President-Public
Policy, U. S. WEST Communications
(1989); Vice President-Legal, U. S.
WEST Communications (1987-88).
Diana J. Johnston 49 Vice President, Human Resources
(1992- );
Manager, Customers Office
Department (1989-92);
Superintendent, Stores Section
(1987-89).
C. J. Rue 48 Secretary (1982- ); Assistant
Treasurer (1987- ).
D. James Wilson 54 Treasurer and Controller (1987- ).
Each executive officer serves successive annual terms; present
terms end May 26, 1994.
There are no family relationships among the Company's executive
officers.
-16-
PART II
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED
STOCKHOLDER MATTERS
(a) The outstanding common stock of the Company is
traded in the over-the-counter market and its price and volume
data are reported by the National Association of Securities
Dealers Automated Quotation (NASDAQ) system. The Company's common
stock is included in the NASDAQ National Market System through
which the high, low and closing transaction prices, as well as
volume data, are reported.
The Company's common stock is included on the Federal
Reserve Board's list of over-the-counter securities determined to
be subject to margin requirements under the Board's regulations.
The quarterly high and low closing trades for the
Company's common stock, as quoted on the NASDAQ National Market
System and published by the Wall Street Journal, were as follows:
-------------------
1993 1992
------------------- ------------------
Quarter Ended High Low High Low
- ------------- ------- ------- ------- -------
March 31 $31-1/2 $28-1/2 $31 $27-1/2
June 30 34 30-3/4 30-1/2 26-1/2
September 30 38 34 33 29
December 31 36-3/4 32 33-3/4 28-1/4
The closing quotation for the common stock on
December 31, 1993 was $34-1/4. On December 31, 1992 the closing
quotation was $28-1/2.
The Company's convertible preference stock $2.375
Series is traded in the over-the-counter market. Because of the
small number of shares of this series outstanding trading is
infrequent. The quarterly high and low closing bid price
quotations reported by NASDAQ were as follows:
Bid Prices
------------------------------------------
1993 1992
----------------- -----------------
Quarter Ended High Low High Low
- ------------- ---- --- ---- ---
March 31 $51 $47-1/2 $48-1/4 $44-1/4
June 30 55-1/4 49-3/4 47-3/4 43
September 30 59 55-1/4 51 47-3/4
December 31 59 52-1/2 51 47-1/2
The closing quotations for the convertible preference
stock on December 31, 1993 and December 31, 1992 were $53-1/2
Bid, $57-1/2 Ask and $47-1/2 Bid, $51-1/2 Ask, respectively.
Outstanding shares are convertible into shares of common stock at
-17-
a rate of 1.6502 shares of common stock for each share of
convertible preference stock.
(b) As of January 31, 1994 there were 13,181 holders of
record of the Company's common stock and 138 holders of record of
its convertible preference stock.
(c) The Company 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 1993 1992
------------ ---- -----
February 15 $0.43 $0.43
May 15 0.44 0.43
August 16 0.44 0.43
November 15 0.44 0.43
----- -----
Total per share $1.75 $1.72
===== =====
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 necessarily be
dependent upon the Company's earnings, its financial condition
and other factors.
The Company'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
the Company's common stock at the current market price.
Shareholders also may invest cash on a monthly basis in
additional shares at the current market price. The Plan was
amended effective January 1, 1994 to allow shareholders to invest
up to $50,000 per calendar year. Previously shareholders were
allowed to invest up to $5,000 per quarter. During 1993, with
about 50 percent of the Company's shareholders participating,
dividend reinvestments and optional cash investments under the
Plan aggregated $5.2 million and resulted in the issuance of
154,900 shares of common stock. During the sixteen years the
Plan has been available the Company has issued and sold 2,676,800
shares of common stock which produced $49.1 million in additional
capital.
-18-
Item 6. SELECTED FINANCIAL DATA
The following table sets forth selected financial data concerning the Company's
operations and financial condition.
Operating revenues and cost of
sales ($000): 1993 1992 1991 1990 1989
---- ---- ---- ---- ----
Sales revenues:
Residential $168,217 $124,834 $142,056 $129,830 $121,938
Commercial 103,476 78,614 90,263 84,463 81,710
Industrial - firm 31,340 24,867 25,222 24,603 21,502
- interruptible 18,884 6,920 3,352 5,273 5,352
-------- -------- -------- -------- --------
Total gas revenues 321,917 235,235 260,893 244,169 230,502
Transportation 17,892 25,564 29,424 30,423 29,143
Unbilled revenues 5,153 2,603 (9,362) 9,268 322
Other 2,890 2,781 118 66 (905)
-------- ------- -------- -------- -------
Total utility operating
revenues 347,852 266,183 281,073 283,926 259,062
Cost of gas 138,833 101,733 107,398 110,605 103,306
-------- -------- -------- -------- --------
Net utility operating
revenues 209,019 164,450 173,675 173,321 155,756
Non-utility net operating
revenues 10,865 8,000 11,664 8,905 1,862
-------- -------- -------- ------- -------
Net operating revenues $219,884 $172,450 $185,339 $182,226 $157,618
======== ======== ======== ======== ========
Net income $ 37,647 $ 15,775 $ 14,377 $ 30,724 $ 28,420
Preferred and preference stock
dividend requirements 3,488 2,560 2,593 2,729 2,814
-------- -------- -------- -------- --------
Earnings applicable to
common stock $ 34,159 $ 13,215 $ 11,784 $ 27,995 $ 25,606
======== ======== ======== ======== ========
Average common shares
outstanding (000) 13,074 11,909 11,698 11,522 10,799
Primary earnings per share
of common stock $2.61 $1.11* $1.01* $2.43 $2.37
===== ===== ===== ===== =====
Dividends per share of
common stock $1.75 $1.72 $1.69 $1.65 $1.61
===== ===== ===== ===== =====
Total assets - at end of
period ($000) $849,036 $731,834 $731,494 $687,835 $611,386
======== ======== ======== ======== ========
Capitalization - at end of period ($000):
Common stock equity $258,565 $241,538 $216,280 $219,446 $206,424
Preference stock 26,633 26,766 1,869 2,025 2,320
Redeemable preferred stock 17,041 28,218 29,148 30,102 31,539
Long-term debt 272,931 253,766 252,995 215,230 220,503
-------- -------- -------- -------- --------
Total capitalization $575,170 $550,288 $500,292 $466,803 $460,786
======== ======== ======== ======== ========
Gas sales and transportation deliveries (000 therms):
Residential 267,818 206,131 233,079 208,940 201,144
Commercial 209,642 169,406 189,384 173,508 170,143
Industrial - firm 80,588 67,847 65,535 62,252 54,761
- interruptible 66,370 22,399 13,155 13,554 14,816
-------- -------- -------- -------- --------
Total gas sales 624,418 465,783 501,153 458,254 440,864
Transportation 415,367 595,397 591,171 532,703 556,713
Unbilled therms 3,844 4,163 (16,943) 18,774 3,950
--------- --------- --------- ---------- ---------
Total volumes delivered 1,043,629 1,065,343 1,075,381 1,009,731 1,001,527
========= ========= ========= ========= =========
Customers (average for period):
Residential 320,186 303,585 288,610 274,069 261,207
Commercial 41,906 40,481 38,954 37,286 35,539
Industrial - firm 388 374 366 350 333
- interruptible 122 75 57 91 142
Transportation 100 153 173 177 88
------- ------- ------- ------- -------
Total customers 362,702 344,668 328,160 311,973 297,309
======= ======= ======= ======= =======
Customer statistics:
Heat requirements**
Actual degree days 4,452 3,662 4,248 4,208 4,310
20-year average degree days 4,313 4,354 4,379 4,391 4,409
Average annual use per customer in therms:
Residential 844 685 812 769 777
Commercial 5,029 4,214 4,874 4,670 4,813
Gas purchased cost per therm
(cents) 23.11 23.76 21.91 22.67 25.25
* Includes loss of $0.24 per share in 1992 and $1.23 per share in 1991 on
Agrico Cogeneration Corporation. (See Part II, Item 8, Note 3 to the
Consolidated Financial Statements.)
** 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.
19
Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF
OPERATIONS AND FINANCIAL CONDITION
Northwest Natural Gas Company's (Northwest Natural)
consolidated wholly-owned subsidiaries consist of Oregon Natural
Gas Development Corporation (Oregon Natural); NNG Energy Systems,
Inc. (Energy Systems); NNG Financial Corporation (Financial
Corporation); and Pacific Square Corporation (Pacific Square)
(see "Subsidiary Operations" below and Note 2 to the Consolidated
Financial Statements). Together, Northwest Natural and these
subsidiaries are referred to herein as the "Company."
The following is management's assessment of the
Company's financial condition including the principal factors
that impact results of operations. The discussion refers to the
consolidated activities of the Company for the three years ended
December 31, 1993.
Earnings and Dividends
- -----------------------
The Company earned $2.61 per share in 1993, compared to
$1.11 per share in 1992 and $1.01 per share in 1991. The
improved 1993 performance was due to cooler weather, customer
growth and improved subsidiary performance. The Company's
earnings for 1992 were depressed by the effects of record-setting
warm weather and a loss related to Agrico Cogeneration
Corporation (Agrico), a subsidiary of Energy Systems. The
Company's earnings for 1991 also were depressed by a charge which
related to Agrico.
The Company earned $2.72 per share from utility
operations in 1993, compared to $1.41 per share and $2.56 per
share in 1992 and 1991, respectively. Weather conditions in the
Company's service territory in 1993 were 22 percent colder than
in 1992 and 5 percent colder than in 1991.
The Company incurred a loss equivalent to $0.11 per
share from subsidiary operations in 1993, compared to losses
equivalent to $0.30 per share and $1.55 per share in 1992 and
1991, respectively (see "Subsidiary Operations" below).
1993 was the 38th consecutive year in which the
Company's dividends paid have increased. In 1993, dividends paid
on common stock were $1.75, up 1.7 percent from a year ago and
3.6 percent higher than 1991. The indicated annual dividend rate
is $1.76 per share.
Results of Operations
- ---------------------
Regulatory Matters
------------------
In April 1993, Northwest Natural filed with the Oregon
Public Utility Commission (OPUC) for rate increases averaging 6.2
-20-
percent in its residential, commercial, and industrial firm rate
schedules. The OPUC approved the Oregon increases effective
May 1, 1993. Effective June 1, 1993, the Washington Utilities
and Transportation Commission (WUTC) approved rate increases
averaging 6.7 percent for the Company's Washington customers.
The rate increases offset Northwest Natural's higher costs for
interstate pipeline capacity under rates approved by the Federal
Energy Regulatory Commission for Northwest Pipeline Corporation
(NPC), the primary pipeline supplying the Pacific Northwest.
In August 1993, Northwest Natural filed with the OPUC
for rate increases averaging 3 percent. The OPUC approved the
increases effective October 1, 1993. These rate increases were
due to the removal of temporary rate discounts in effect since
November 1990 to distribute gas cost savings and pipeline rate
refunds resulting from the transition to "open access"
transportation by NPC.
In November 1993, Northwest Natural filed with the OPUC
and the WUTC for rate increases which averaged 3.7 percent and
7.6 percent for Oregon and Washington operations, respectively.
The new rates pass through the impact of higher gas costs and
remove temporary rate discounts in place since December 1992 for
the amortization of prior gas cost savings. Both increases were
approved effective December 1, 1993.
None of the above rate increases has a material effect
on net income. The cumulative effect of the increases is not
expected to impair Northwest Natural's competitive position in
its key markets.
Comparison of Gas Operations
-----------------------------
The following table summarizes the composition of
utility gas volumes and revenues for the three years ended
December 31, 1993:
-21-
Thousands 1993 1992 1991
- -----------------------------------------------------------------------------
Gas Sales and Transportation Deliveries (Therms):
- -------------------------------------------------
Residential and commercial
sales 477,460 375,537 422,463
Unbilled volumes 3,844 4,163 (16,943)
--------- --------- ---------
Weather-sensitive volumes 481,304 46% 379,700 36% 405,520 38%
Industrial firm sales 80,588 8% 67,847 6% 65,535 6%
Industrial interruptible
sales 66,370 6% 22,399 2% 13,155 1%
--------- --------- ---------
Total gas sales 628,262 469,946 484,210
Transportation deliveries 415,367 40% 595,397 56% 591,171 55%
--------- ---- --------- ---- --------- ----
Total volumes sold and
delivered 1,043,629 100% 1,065,343 100% 1,075,381 100%
========= ==== ========= ==== ========= ====
Utility Operating Revenues
- --------------------------
Residential and commercial
revenues $271,693 $203,448 $232,319
Unbilled revenues 5,153 2,603 (9,362)
-------- -------- --------
Weather-sensitive revenues 276,846 80% 206,051 77% 222,957 79%
Industrial firm sales revenues 31,340 9% 24,867 9% 25,222 9%
Industrial interruptible sales
revenues 18,884 5% 6,920 3% 3,352 1%
-------- -------- -------
Total gas sales revenues 327,070 237,838 251,531
Transportation revenues 17,892 5% 25,564 10% 29,424 11%
Other revenues 2,890 1% 2,781 1% 118 -
-------- ---- -------- ---- -------- ----
Total utility operating
revenues $347,852 100% $266,183 100% $281,073 100%
======== ==== ======== ==== ======== ====
Cost of gas $138,833 $101,733 $107,398
======== ======== ========
Total number of customers
(end of period) 372,400 353,000 336,400
Residential and Commercial
--------------------------
Typically, 75 percent or more of the Company's annual
utility operating revenues are derived from gas sales to weather-
sensitive residential and commercial customers. Accordingly,
dramatic shifts in temperatures from one period to the next can
significantly impact volumes of gas sold to these customers.
Normal weather conditions are based upon a 20 year average
measured by degree days. Weather conditions were three percent
cooler than normal in 1993, 16 percent warmer than normal in
1992, and three percent warmer than normal in 1991. 1993 was 22
percent colder than 1992. Cooler weather, the addition of 19,400
customers, and the rate increases approved by the OPUC and WUTC
combined to produce a 34 percent increase in revenues from
residential and commercial customers in 1993 compared to 1992 on
therm deliveries to these customers which were 27 percent higher
than in 1992.
-22-
The Company's residential and commercial customer
growth continued at a rapid pace. In the last three years,
almost 52,500 of these customers have been added to the system,
representing an average growth rate of 5.2 percent.
Industrial, Transportation and Other
------------------------------------
Total volumes delivered to industrial firm, industrial
interruptible and transportation customers were 123 million
therms lower in 1993 than in 1992, while corresponding revenues
from such deliveries were $10.8 million higher. The combined net
operating revenue (margin) from industrial firm and interruptible
sales and transportation customers increased from $42.7 million
in 1992 to $44.4 million in 1993. Transportation volumes
declined due to a 136 million therm reduction in deliveries to
an electric generation plant which was served under a low-margin
transportation tariff. This plant is now served primarily by a
new natural gas pipeline which is a joint venture between Oregon
Natural and Portland General Electric Company. Transportation
revenues from this customer were $0.2 million and $2.5 million in
1993 and 1992, respectively. However, due to the effect of a
regulatory balancing mechanism in Oregon, under which the Company
credits 80 percent of the transportation revenues received for
deliveries to this plant to a deferred account for future refunds
to other customers, the reduced volume of deliveries in 1993
resulted in a decrease in margin revenues of only $0.5 million.
Since 1992, approximately half of Northwest Natural's
transportation customers have switched to sales service. These
customers, which have the option of purchasing natural gas from
Northwest Natural or of purchasing gas directly from suppliers
and transporting it on the systems of Northwest Natural and its
pipeline suppliers for a fee, select the option which from time
to time provides the lowest cost. Management believes that the
migration from transportation to sales tariffs by these customers
was primarily due to the fact that, in 1993, Northwest Natural's
industrial sales tariffs have been lower than the cost to these
customers of purchasing and shipping their own gas. The increase
in revenue attributable to this migration was offset by an
increase in the cost of gas, since transportation rate schedules
are designed to provide the same margin as industrial sales
tariffs and thus had little effect on the Company's income from
operations.
Industrial sales and transportation deliveries remained
relatively stable during 1992 and 1991, at 686 million therms in
1992 compared to 670 million therms in 1991. Related revenues
were $57 million in 1992, essentially unchanged from 1991.
Transportation revenues decreased $3.9 million between these two
years, although related volumes remained relatively stable,
primarily due to rate reductions in certain transportation
tariffs.
-23-
Unbilled revenues are a recognition of revenues for all
gas consumption through the end of the month for all customers,
regardless of the meter reading date, in order to better match
revenues with associated purchased gas costs.
Other revenues are primarily related to regulatory
balancing accounts (see Note 1 to the Consolidated Financial
Statements).
The Company and most of its large industrial customers
have entered into high-volume interruptible transportation
agreements which are designed to provide rates competitive with
"bypass" (direct connection to interstate pipelines) by applying
fixed charges that vary with each customer's distance from
pipeline facilities. These agreements prohibit bypass during
their terms. However, management believes that, during the
period 1994 to 1998 it might lose from four to six large
industrial customers through bypass. In total, these customers
represented approximately 10 percent of 1993 volumes, but less
than 3 percent of 1993 margin revenues. Given the far greater
effect on margin revenues of temperature fluctuations, economic
conditions and growth in residential and commercial customers,
management believes the impact of bypass will not materially
affect the Company's future results of operations or its
financial position.
Cost of Gas
-----------
The cost of gas sold during 1993 was 36 percent greater
than in 1992. The primary contributing factors were a 34 percent
increase in total volumes sold and a 2 percent increase in the
cost of gas per therm which includes purchased gas cost
adjustments and net storage gas activity. The cost of gas sold
in 1992 was 5 percent lower than in 1991 primarily due to a 3
percent decrease in total volumes sold and a lower average cost
of gas per therm.
Subsidiary Operations
---------------------
Consolidated subsidiary results for the three years
ended December 31, 1993, 1992, and 1991, were losses equivalent
to $0.11 per share, $0.30 per share and $1.55 per share,
respectively. The subsidiaries' results for 1993 reflect a
fourth quarter write-down in the value of unproven gas and oil
reserves equivalent to $0.11 per share and increased federal
income tax expense equivalent to $0.05 per share (see
"Depreciation, Depletion and Amortization" and "Income Taxes"
below).
Results of operations for the individual subsidiaries
for 1993, including the adjustments described above, were a net
loss of $0.4 million for Energy Systems; a net loss of $1.4
million for Oregon Natural; a net loss of $0.4 million for
-24-
Financial Corporation; and net income of $0.7 million for Pacific
Square.
The 1992 and 1991 losses resulted primarily from
charges equivalent to $0.24 per share and $1.23 per share,
respectively, related to Agrico. Future charges, if any, related
to Agrico, are expected to be immaterial (see Note 3 to the
Consolidated Financial Statements).
The following discussion summarizes operating expenses,
interest charges and income taxes.
Operating Expenses
------------------
Operations and Maintenance
--------------------------
Operations and maintenance expenses were $6.5 million,
or 10 percent, higher in 1993 compared to 1992. Utility expenses
constituted $6.2 million of this increase including a $3.1
million, or 10 percent, increase in payroll expenses; a $1.3
million increase in employee benefit costs, including an increase
of $0.7 million resulting from the adoption of Statement of
Financial Accounting Standards (SFAS) No. 106, "Employers'
Accounting for Postretirement Benefits Other than Pensions;" a
$1.2 million increase in the allowance for uncollectible accounts
primarily due to higher residential and commercial gas sales; and
a $0.5 million accrual for estimated environmental investigation
costs (see Note 12 to the Consolidated Financial Statements).
Utility operations and maintenance expenses were $3.4
million, or 6 percent, higher in 1992 than in 1991. Subsidiary
operations and maintenance expenses were $4.7 million, or 45
percent, lower. Higher utility operating and maintenance
expenses resulted primarily from a $1.5 million, or 5 percent,
increase in payroll due to wage and salary increases, a $0.5
million increase in employee benefit costs, and increases in
claims for injuries and damages and weatherization costs of $0.5
million and $0.4 million, respectively. Subsidiary expenses were
lower in 1992 than in 1991 due to a five-month suspension of
Agrico operations during 1992.
Taxes Other Than Income
-----------------------
Taxes other than income increased $4.7 million, or
23 percent, in 1993 compared to 1992 due to a $2.5 million
increase in utility property tax accruals and a $1.8 million
increase in franchise taxes resulting from higher utility
operating revenues. Approximately $0.9 million of the increased
property tax accrual is non-recurring and relates to a dispute
with the OPUC over the amount of prior-year savings on property
taxes which must be refunded to Oregon customers. The balance of
-25-
this increase resulted from property taxes on plant additions
made primarily to serve new customers.
Taxes other than income decreased $0.2 million, or 1
percent, in 1992 compared to 1991. This resulted primarily from
a reduction of $0.6 million in utility franchise taxes which
occurred due to decreased utility operating revenues. This
decrease was offset by a $1.0 million increase in property taxes,
again due to new plant additions made primarily to serve new
customers.
Depreciation, Depletion and Amortization
----------------------------------------
Utility depreciation expense increased $1.9 million, or
7 percent, in 1993 and $1.0 million, or 3.5 percent, in 1992,
primarily due to additional utility plant in service. $0.4
million of the increased 1993 expense related to the removal of
all of the Company's underground gasoline tanks.
Subsidiary depreciation expense increased $4.7 million
in 1993 and decreased $1.6 million in 1992. The 1993 increase
resulted primarily from charges totalling $3.5 million, from the
write-downs of Oregon Natural's unproven gas and oil properties
(see Note 2 to the Consolidated Financial Statements). $1.5
million of the 1992 decrease in depreciation expense resulted
from the suspension of depreciation on Agrico's assets upon its
bankruptcy.
Interest Charges
----------------
Utility interest expense for 1993 decreased $1.3
million compared to 1992. The decrease was a result of debt
refinancings which reduced interest expense by $0.6 million;
$11.5 million lower average outstanding commercial paper
balances; and a decrease in average interest rates for utility
commercial paper from 3.9 percent in 1992 to 3.3 percent in 1993.
Subsidiary interest expense for 1993 decreased $0.3 million
compared to 1992 due to a decrease in interest expense under
Financial Corporation's commercial paper program. Financial
Corporation's average outstanding commercial paper balances
decreased $4.4 million from 1992 to 1993. In addition, Financial
Corporation's average interest rates for commercial paper
decreased from 4.1 percent in 1992 to 3.3 percent in 1993.
Utility interest expense for 1992 was $3.0 million
higher than for 1991. Although total utility debt outstanding
was $4.9 million lower at year end 1992 than at year end 1991,
the average monthly debt balances were higher due to the
increased use of commercial paper in 1992. Commercial paper
borrowing increased as warmer-than-average weather reduced
revenues. The effect of the increased borrowings was partially
offset by a decrease in average interest rates for utility
commercial paper from 6.3 percent in 1991 to 3.9 percent in 1992,
-26-
and a decrease in average interest expense of utility long-term
debt from 9.7 percent in 1991 to 9.3 percent in 1992.
The 1992 increase in utility interest expense was
offset in part by a $2.8 million decrease in subsidiary interest
expense which resulted primarily from the reduction of Financial
Corporation's outstanding commercial paper balances and a
decrease in Financial Corporation's average interest rates for
commercial paper from 6.3 percent in 1991 to 4.1 percent in 1992.
Income Taxes
------------
The effective corporate income tax rates for the three
years ended December 31, 1993, 1992, and 1991 were 37 percent, 31
percent, and 14 percent, respectively, compared to the Company's
statutory tax rates for these periods of 39 percent, 38 percent,
and 38 percent, respectively. The effective income tax rate for
1991 was lower than the Company's statutory tax rate primarily as
a result of non-recurring adjustments that reduced amounts
provided for income taxes in prior years by $4.5 million.
The adoption of SFAS No. 109, "Accounting for Income
Taxes," effective January 1, 1993, did not materially affect
results of operations. However, for 1993, the federal income tax
rate for corporations increased from 34 to 35 percent. The
cumulative effect of the tax rate increase was recorded in the
third quarter of 1993 and resulted in additional income tax
expense of $0.6 million, an increase in deferred tax liabilities
of $3.0 million, and an increase in regulatory assets of
$2.6 million.
Financial Condition
- -------------------
The weather-sensitive nature of gas usage by Northwest
Natural's residential and commercial customers influences the
Company's financial condition, including its financing
requirements, from one quarter to the next. Liquidity
requirements are satisfied primarily through the use of
commercial paper, which is supported by commercial bank lines of
credit (see "Lines of Credit" and "Commercial Paper" below).
Capital Structure
-----------------
The Company's long-term goal is to maintain a capital
structure comprised of 40 to 45 percent common stock equity, 5 to
10 percent preferred and preference stock and 45 to 50 percent
short-term and long-term debt. This target structure is managed
by issuing new debt or equity in response to market conditions
and the status of accumulated earnings. The Company also uses
these sources to meet long-term debt and preferred stock
redemption requirements (see Notes 4 and 6 to the Consolidated
Financial Statements).
-27-
Cash Flows
----------
Operating Activities
--------------------
Cash provided from operating activities was higher in
1993 and 1991 as compared to 1992, primarily due to higher
revenues from gas sales resulting from colder weather. Also, a
portion of the increased cash provided from operating activities
in 1991 was due to the effects of unusually cold weather in
December 1990, which produced substantial increases in the year-
end 1990 balances for accounts receivable, unbilled revenue and
accounts payable. These balances, which were collected in 1991,
provided $26 million of additional funds during 1991.
The Company has lease and purchase commitments related
to its operating activities which will continue to be financed
with cash flows from operations (see Note 12 to the Consolidated
Financial Statements).
Investing Activities
--------------------
Cash requirements for utility construction, primarily
related to system improvements and customer growth, totalled
$70.4 million, up $9.7 million, or 16 percent, from 1992 and up
$12.0 million, or 21 percent, from 1991. The 1993 increase
includes $6.3 million in expenditures related to a project
initiated in 1993 to replace the existing customer information
system. It is estimated that this project will involve a total
investment of about $25 million between 1993 and 1996.
A large part of the Company's utility capital
expenditures is required for utility construction resulting from
customer growth and system improvements. While the Company
finances most of these requirements from cash from operations, it
also uses short-term borrowings and periodically refinances these
borrowings through the sale of long-term debt or equity
securities.
Utility construction expenditures totalling $75 million
are projected for 1994. Over the five year period 1994 through
1998, total utility capital expenditures are estimated at between
$325 and $350 million. It is anticipated that approximately
50 percent of the funds required for these expenditures during
this period will be internally generated, and that the remainder
will be funded through short-term borrowings which will be
refinanced periodically through the sale of long-term debt and
equity securities.
Capital expenditures for the Company's operating
subsidiaries in 1994 are expected to be limited to funds
internally generated by the subsidiaries. In 1993, Oregon
Natural sold and exchanged gas producing properties resulting in
net cash inflows of $2.3 million.
-28-
Investments shown on the Consolidated Balance Sheets
under "Investments and Other" for 1992 included a $5.5 million
restricted cash deposit with a commercial bank which related to
Pacific Square. This deposit was reclassified as a current asset
in 1993 due to the pending sale of Pacific Square's primary real
estate investments to which it relates. The sale of Pacific
Square's investments, which is expected to close in 1994, would
not be at a loss to the Company.
Financing Activities
--------------------
During 1993 and 1992, the Company sold $100 million and
$45 million, respectively, of its Medium-Term Notes. Of the
proceeds from 1993 sales, $82.6 million was used to redeem
higher-cost long-term debt, and the remainder was used to meet
capital requirements for the Company's ongoing construction
program and to reduce short-term borrowing. Of the proceeds from
the 1992 sales, $30 million was used to redeem higher-cost long-
term debt and $15 million was used to reduce short-term
borrowing. As a result of these transactions, the average
interest expense on long-term debt declined from 9.7 percent at
December 31, 1991 to 8.3 percent at December 31, 1993.
Additionally, in order to meet the Company's capital
requirements for its ongoing construction program, to refund
higher-cost Preferred Stock, and to increase its equity ratios,
the Company sold $25 million of Preference Stock and $28.5
million, or 990,000 shares, of Common Stock during the fourth
quarter of 1992. In January 1993, approximately $9 million of
the proceeds from the sale of Preference Stock was used to redeem
all of the outstanding shares of the Company's $8.00 and $2.42
Series of Preferred Stock.
Also in 1993, the Company redeemed all of the
outstanding shares of its $6.875 Series of Preferred Stock (see
Consolidated Statements of Capitalization).
The Company reached an agreement with the sole
shareholder of the $8.75 Series of Preferred Stock, with a total
stated value of $15 million, to issue an equivalent amount of the
$7.125 Series of Preferred Stock in exchange for cancellation of
the $8.75 Series, effective as of December 1, 1993.
Lines of Credit
---------------
Northwest Natural has available through September 30,
1994, lines of credit totalling $80 million consisting of a
primary fixed amount of $40 million plus an excess amount of up
to $40 million available as needed, at Northwest Natural's
option, on a monthly basis. Under the terms of these bank lines,
Northwest Natural pays a commitment fee but is not required to
maintain compensating bank balances. The interest rates on
borrowings under these lines of credit are based on current
-29-
market rates as negotiated. There were no outstanding balances
as of December 31, 1993.
Financial Corporation has available through
September 30, 1994, lines of credit with two commercial banks
totalling $20 million, including $10 million committed and $10
million uncommitted. Financial Corporation pays a fee on the
committed line but not on the uncommitted line; it is not required
to maintain compensating bank balances on either line. The
interest rates on borrowings under these lines of credit also are
based on current market rates as negotiated. Financial
Corporation's lines are supported by the unconditional guaranty
of Northwest Natural. There were no outstanding balances as of
December 31, 1993 under the Financial Corporation bank lines.
Commercial Paper
----------------
The Company's primary source of short-term funds is
commercial paper. Both Northwest Natural and Financial
Corporation issue commercial paper which is supported by the
committed bank lines discussed above. Financial Corporation's
commercial paper is unconditionally guarantied by Northwest
Natural (see Note 7 to the Consolidated Financial Statements).
Agrico Term Loan
----------------
At December 31, 1991, $14.0 million was outstanding
under a term loan agreement between Agrico and United States
National Bank of Oregon (U.S. Bank). Under a settlement
agreement between Energy Systems, U.S. Bank, and Northwest
Natural, U.S. Bank assigned the term loan to Energy Systems in
exchange for payments by Energy Systems and Northwest Natural
totalling $7.2 million. Such payments were made, and the debt
was retired during 1992 (see Note 3 to the Consolidated Financial
Statements).
Ratio of Earnings to Fixed Charges
----------------------------------
For the years ended December 31, 1993, 1992, and 1991,
the Company's ratio of earnings to fixed charges, computed by the
Securities and Exchange Commission method, was 3.22, 1.81, and
1.59, respectively. Earnings consist of net income to which has
been added taxes on income and fixed charges. Fixed charges
consist of interest on all indebtedness, amortization of debt
expense and discount or premium, and the estimated interest
portion of rentals charged to income.
-30-
Environmental Matters
- ---------------------
In June 1992, the City of Salem, Oregon, requested the
Company's participation in its review of an environmental
assessment of riverfront property in Salem that is the proposed
site for a park and other public developments. Within the
property is a block previously owned by the Company which was the
former site of a manufactured gas plant. The Company's corporate
predecessor operated the plant for less than four months in 1929
before closing it upon completion of a pipeline providing gas
transmission from Portland to Salem. The City has determined
that there is environmental contamination on the site, and that a
remediation process involving the Company and at least two other
prior owners of the block will be required. To date the Company
has not obtained sufficient information to determine the extent
of its liability for any such remediation.
The Company owns property in Linnton, Oregon, that is
the former site of a gas manufacturing plant that was closed in
1956. Although limited testing for environmental contamination
has been undertaken by other parties on portions of the site, no
comprehensive studies have been performed. The Company submitted
a work plan for the site to the Oregon Department of
Environmental Quality (ODEQ) in 1987, but those efforts were
suspended at ODEQ's request while the Company and other parties
participated in a joint hydrogeologic study of an area adjacent
to the site. In September 1993, pursuant to ODEQ procedures, the
Company submitted a notice of intent to participate in the ODEQ's
Voluntary Cleanup Program. In January 1994, this site was
formally placed in the program. It is anticipated that the site
investigation will commence during 1994.
In September 1993, the Company recorded an expense of
$500,000 for the estimated costs of consultants' fees, ODEQ
oversight cost reimbursements, and legal fees in connection with
the voluntary investigation at the Linnton site. To date, the
Company has not obtained sufficient information to determine
whether any remediation will be required at this site or, if so,
the extent of its liability for any such remediation. The
Company expects that its costs of investigation and any
remediation for which it may be liable should be recoverable, in
large part, from insurance or through future rates.
-31-
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
TABLE OF CONTENTS
-----------------
Page
----
1. Management's Responsibility for Financial Statements . . . 33
2. Independent Auditors' Report . . . . . . . . . . . . . . . . . 34
3. Consolidated Financial Statements:
Consolidated Statements of Income for the Years Ended
December 31, 1993, 1992 and 1991 . . . . . . . . . . . . . . 35
Consolidated Statements of Earnings Invested in the Business
for the Years Ended December 31, 1993, 1992 and 1991 . . . . 36
Consolidated Balance Sheets, December 31, 1993 and 1992. . . . 37
Consolidated Statements of Cash Flows for the Years Ended
December 31, 1993, 1992 and 1991 . . . . . . . . . . . . . . 39
Consolidated Statements of Capitalization, December 31,
1993 and 1992. . . . . . . . . . . . . . . . . . . . . . . . 40
Notes to Consolidated Financial Statements . . . . . . . . . . 41
4. Quarterly Financial Information (unaudited). . . . . . . . . . 61
5. Supplemental Schedules for the Years Ended December 31, 1993,
1992 and 1991
Schedule V - Property, Plant and Equipment . . . . . . . . . . 62
Schedule VI - Accumulated Depreciation, Depletion and
Amortization of Property, Plant and Equipment. . . . . . . . 65
Schedule IX - Short-term Borrowings. . . . . . . . . . . . . . 66
Schedule X - Supplementary Income Statement Information. . . . 67
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.
-32-
MANAGEMENT'S RESPONSIBILITY FOR FINANCIAL STATEMENTS
----------------------------------------------------
The financial statements in this report were prepared by
management, which is responsible for their objectivity and integrity.
The statements have been prepared in conformity with generally accepted
accounting principles and, where appropriate, reflect informed estimates
based on judgments of management. The responsibility of the Company's
independent auditors is to render an independent report on the financial
statements.
The Company's system of internal accounting controls is
designed to provide reasonable assurance that assets are safeguarded and
transactions are executed in accordance with management's
authorizations, that transactions are recorded to permit the preparation
of financial statements in conformity with orders of regulatory
authorities and generally accepted accounting principles and that
accountability for assets is maintained. The Company's system of
internal controls has provided such reasonable assurances during the
periods reported herein. The system includes written policies,
procedures and guidelines, an organization structure that segregates
duties and an established program for monitoring the system by internal
auditors. In addition, Northwest Natural Gas Company has prepared and
annually distributes to its management employees a Code of Ethics
covering its policies for conducting business affairs in a lawful and
ethical manner. Ongoing review programs are carried out to ensure
compliance with these policies.
The Board of Directors, through its Audit Committee, oversees
management's financial reporting responsibilities. The committee meets
regularly with management, the internal auditors, and representatives of
Deloitte & Touche, the Company's independent auditors. Both internal
and external auditors have free and independent access to the committee
and the Board of Directors. No member of the committee is an employee
of the Company. The committee reports the results of its activities to
the full Board of Directors. Annually, the Audit Committee recommends
the nomination of independent auditors to the Board of Directors for
shareholder approval.
/s/ Robert L. Ridgley
-------------------------------
Robert L. Ridgley
President and
Chief Executive Officer
/s/ Bruce R. DeBolt
-------------------------------
Bruce R. DeBolt
Senior Vice President, Finance,
and Chief Financial Officer
-33-
DELOITTE & TOUCHE
- -----------------------------------------------------------------
3900 US Bancorp Tower Telephone: (503) 222-1341
111 SW Fifth Avenue Facsimile: (503) 224-2172
Portland, Oregon 97204-3698
INDEPENDENT AUDITORS' REPORT
----------------------------
To the Board of Directors and Shareholders
Northwest Natural Gas Company
Portland, Oregon
We have audited the accompanying consolidated financial statements of
Northwest Natural Gas Company and subsidiaries, listed in the
accompanying table of contents to financial statements and financial
statement schedules at Item 8. These financial statements and financial
statement schedules are the responsibility of the Company's management.
Our responsibility is to express an opinion on the financial statements
and financial statement schedules based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards 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. An audit also includes assessing the accounting
principles used and significant estimates made by management, as well as
evaluating the overall financial statement presentation. We believe
that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly,
in all material respects, the consolidated financial position of
Northwest Natural Gas Company and subsidiaries at December 31, 1993 and
1992, and the results of their operations and their cash flows for each
of the three years ended December 31, 1993 in conformity with generally
accepted accounting principles. Also, in our opinion, such financial
statement schedules, when considered in relation to the basic
consolidated financial statements taken as a whole, present fairly in
all material respects the information set forth therein.
As discussed in Notes 8 and 10 to the consolidated financial statements,
the Company changed its method of accounting for income taxes and
postretirement benefits in the year ended December 31, 1993.
/s/ Deloitte & Touche
DELOITTE & TOUCHE
February 25, 1994
-34-
NORTHWEST NATURAL GAS COMPANY
CONSOLIDATED STATEMENTS OF INCOME
(Thousands, Except Per Share Amounts)
Year Ended December 31 1993 1992 1991
- ------------------------------------------------------------------------
NET OPERATING REVENUES:
Revenues:
Utility $347,852 $266,183 $281,073
Other 10,865 8,183 14,865
-------- -------- --------
Total operating revenues 358,717 274,366 295,938
-------- ------- --------
Cost of sales:
Utility 138,833 101,733 107,398
Other - 183 3,201
-------- -------- -------
Total cost of sales 138,833 101,916 110,599
-------- -------- -------
Net operating revenues 219,884 172,450 185,339
-------- -------- -------
OPERATING EXPENSES:
Operations and maintenance 70,723 64,249 65,529
Taxes other than income taxes 25,561 20,865 21,104
Depreciation, depletion and
amortization 39,683 33,035 33,623
Loss on cogeneration facility - 4,575 23,200
-------- ------- --------
Total operating expenses 135,967 122,724 143,456
-------- ------- --------
INCOME FROM OPERATIONS 83,917 49,726 41,883
-------- ------- --------
OTHER INCOME (EXPENSE) 933 (267) 1,406
-------- ------- --------
INTEREST CHARGES:
Interest on long-term debt 22,578 23,001 21,977
Other interest 1,906 3,223 4,266
Amortization of debt discount
and expense 775 511 348
-------- ------- -------
Total interest charges 25,259 26,735 26,591
Allowance for borrowed funds
used during construction and
capitalized interest (152) (2) -
-------- -------- --------
Total interest charges-net 25,107 26,733 26,591
-------- -------- --------
INCOME BEFORE INCOME TAXES 59,743 22,726 16,698
INCOME TAXES 22,096 6,951 2,321
--------- -------- --------
NET INCOME 37,647 15,775 14,377
Preferred and preference stock
dividend requirements 3,488 2,560 2,593
-------- ------- -------
EARNINGS APPLICABLE TO COMMON STOCK $ 34,159 $ 13,215 $ 11,784
======== ======== ========
AVERAGE COMMON SHARES OUTSTANDING 13,074 11,909 11,698
EARNINGS PER SHARE OF COMMON STOCK $2.61 $1.11 $1.01
===== ===== =====
DIVIDENDS PER SHARE OF COMMON STOCK $1.75 $1.72 $1.69
===== ===== =====
- -------------------------------------------------------------------------
See Accompanying Notes to Consolidated Financial Statements.
-35-
NORTHWEST NATURAL GAS COMPANY
CONSOLIDATED STATEMENTS OF EARNINGS INVESTED IN THE BUSINESS
(Thousands of Dollars)
1993 1992 1991
- -------------------------------------------------------------------------
BALANCE AT BEGINNING OF YEAR $77,690 $86,361 $94,325
Net Income 37,647 15,775 14,377
Cash dividends:
Preferred and
preference stock (3,401) (2,525) (2,608)
Common stock (22,853) (20,406) (19,728)
Capital stock expense and other (586) (1,515) (5)
------- ------- -------
BALANCE AT END OF YEAR $88,497 $77,690 $86,361
======= ======= =======
- -------------------------------------------------------------------------
See Accompanying Notes to Consolidated Financial Statements.
-36-
NORTHWEST NATURAL GAS COMPANY
CONSOLIDATED BALANCE SHEETS
(Thousands)
December 31 1993 1992
- ------------------------------------------------------------------------
ASSETS:
PLANT AND PROPERTY IN SERVICE:
Utility plant in service $840,030 $779,274
Less accumulated depreciation 255,282 233,385
-------- --------
Utility plant - net 584,748 545,889
Non-utility property 42,764 44,629
Less accumulated depreciation and depletion 20,646 15,480
-------- --------
Non-utility property - net 22,118 29,149
-------- --------
Total plant and property in service 606,866 575,038
-------- --------
INVESTMENTS AND OTHER:
Investments 32,818 32,818
Restricted cash and long-term notes
receivable 1,756 7,518
------- -------
Total investments and other 34,574 40,336
------- -------
CURRENT ASSETS:
Cash and cash equivalents 4,198 7,537
Accounts receivable - customers 45,340 33,956
Allowance for uncollectible accounts (1,368) (948)
Accrued unbilled revenue 25,890 20,738
Inventories of gas, materials and supplies 16,838 15,797
Prepayments and other current assets 16,412 8,220
-------- --------
Total current assets 107,310 85,300
-------- --------
OTHER REGULATORY TAX ASSETS 62,130 -
DEFERRED DEBITS AND OTHER 38,156 31,160
-------- --------
TOTAL ASSETS $849,036 $731,834
======== ========
- -----------------------------------------------------------------------
See Accompanying Notes to Consolidated Financial Statements.
-37-
NORTHWEST NATURAL GAS COMPANY
CONSOLIDATED BALANCE SHEETS
(Thousands)
December 31 1993 1992
- -----------------------------------------------------------------------
CAPITALIZATION AND LIABILITIES:
CAPITALIZATION (See Consolidated Statements
of Capitalization):
Common stock equity $ 41,728 $ 41,080
Premium on common stock 128,340 122,768
Earnings invested in the business 88,497 77,690
-------- --------
Total common stock equity 258,565 241,538
Preference stock 26,633 26,766
Redeemable preferred stock 17,041 28,218
Long-term debt 272,931 253,766
-------- --------
Total capitalization 575,170 550,288
-------- --------
CURRENT LIABILITIES:
Notes payable 72,548 47,109
Accounts payable 44,318 40,282
Long-term debt due within one year - 2,138
Taxes accrued 6,757 4,790
Interest accrued 4,438 6,792
Other current and accrued liabilities 10,180 9,387
-------- --------
Total current liabilities 138,241 110,498
-------- --------
DEFERRED INVESTMENT TAX CREDITS 14,567 15,603
DEFERRED INCOME TAXES 104,300 34,929
REGULATORY BALANCING ACCOUNTS AND OTHER 16,758 20,516
COMMITMENTS AND CONTINGENT LIABILITIES (Note 12) - -
-------- --------
TOTAL CAPITALIZATION AND LIABILITIES $849,036 $731,834
======== ========
- -------------------------------------------------------------------------
See Accompanying Notes to Consolidated Financial Statements.
-38-
NORTHWEST NATURAL GAS COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Thousands)
Year Ended December 31 1993 1992 1991
- ------------------------------------------------------------------------------
OPERATING ACTIVITIES:
Net income $ 37,647 $ 15,775 $ 14,377
Adjustments to reconcile net income to net
cash provided by (used for) operations:
Depreciation, depletion and amortization 39,683 33,035 33,623
Loss on cogeneration facility - 4,575 23,200
Deferred income taxes and investment
tax credits 6,205 (1,115) (5,784)
Equity in losses of unconsolidated
affiliates 302 1,506 263
Allowance for funds used during
construction and capitalized interest (152) (2) -
Regulatory balancing accounts and
other - net (10,754) (10,776) 1,672
Changes in operating assets and liabilities:
Accounts receivable (10,964) (5,821) 2,964
Accrued unbilled revenue (5,152) (2,603) 9,362
Inventories of gas, materials and
supplies (1,041) 1,052 (419)
Accounts payable 4,036 (3,507) 5,715
Accrued interest and taxes (387) 881 (1,766)
Other current assets and liabilities (1,899) 2,636 2,501
-------- -------- --------
CASH PROVIDED BY OPERATING ACTIVITIES 57,524 35,636 85,708
-------- -------- --------
INVESTING ACTIVITIES:
Acquisition and construction of
utility plant assets (70,404) (60,709) (58,362)
Investment in non-utility plant (955) (11,907) (4,936)
Investments and other (40) (8,697) (3,122)
--------- -------- --------
CASH USED IN INVESTING ACTIVITIES (71,399) (81,313) (66,420)
--------- -------- --------
FINANCING ACTIVITIES:
Common stock issued 5,720 33,826 4,642
Preference stock issued - 25,000 -
Preferred stock retired (11,177) (930) (954)
Long-term debt:
Issued 100,000 45,000 40,000
Retired (82,606) (30,191) (11,178)
Change in short-term debt 25,439 (41,510) 14,211
Cash dividend payments:
Preferred and preference stock (3,401) (2,525) (2,608)
Common stock (22,853) (20,406) (19,728)
Capital stock expense and other (586) (1,515) (5)
-------- -------- ---------
CASH PROVIDED BY FINANCING ACTIVITIES 10,536 6,749 24,380
-------- -------- ---------
INCREASE (DECREASE) IN CASH AND
CASH EQUIVALENTS (3,339) (38,928) 43,668
CASH AND CASH EQUIVALENTS - BEGINNING OF YEAR 7,537 46,465 2,797
-------- -------- --------
CASH AND CASH EQUIVALENTS - END OF YEAR $ 4,198 $ 7,537 $ 46,465
======== ======== ========
SUPPLEMENTAL DISCLOSURE OF
CASH FLOW INFORMATION:
Cash paid during the year for:
Interest $ 26,838 $ 26,502 $ 26,070
Income taxes $ 11,103 $ 10,141 $ 13,238
- ------------------------------------------------------------------------------
See Accompanying Notes to Consolidated Financial Statements.
-39-
NORTHWEST NATURAL GAS COMPANY
CONSOLIDATED STATEMENTS OF CAPITALIZATION
(Thousands, Except Share Amounts)
December 31 1993 1992
- --------------------------------------------------------------------------------
COMMON STOCK EQUITY:
Common stock - par value $3-1/6
per share; authorized 30,000,000
shares: outstanding - 1993,
13,177,256 shares; 1992,
12,972,725 shares $ 41,728 $ 41,080
Premium on common stock 128,340 122,768
Earnings invested in business 88,497 77,690
-------- --------
Total common stock equity 258,565 45% 241,538 44%
-------- ---- -------- ----
PREFERENCE STOCK, authorized
2,000,000 shares:
$2.375 Series, convertible, stated value
$25 per share; outstanding - 1993,
65,323 shares; 1992, 70,621 shares 1,633 1,766
$6.95 Series, stated value $100 per
share; outstanding - 1993, 250,000
shares; 1992, 250,000 shares 25,000 25,000
-------- --------
Total preference stock 26,633 5% 26,766 5%
-------- ---- -------- ----
REDEEMABLE PREFERRED STOCK, authorized
1,500,000 shares*:
$4.68 Series, outstanding - 1993,
9,301 shares; 1992, 11,211 shares 930 1,121
$4.75 Series, outstanding - 1993,
11,105 shares; 1992, 11,355 shares 1,111 1,136
$6.875 Series, outstanding - 1993,
no shares; 1992, 19,563 shares - 1,956
$7.125 Series, outstanding - 1993,
150,000 shares; 1992, no shares 15,000 -
$8.00 Series, outstanding - 1993,
no shares; 1992, 29,584 shares - 2,958
$8.75 Series, outstanding - 1993,
no shares; 1992, 150,000 shares - 15,000
$2.42 Series, outstanding - 1993,
no shares; 1992, 219,882 shares - 5,497
Premium - 550
-------- --------
Total redeemable preferred stock 17,041 3% 28,218 5%
--------- --- -------- ---
LONG-TERM DEBT:
First Mortgage Bonds
--------------------
8-5/8% Series due 1996 - 11,658
9-3/8% Series due 2011 - 46,000
9-3/4% Series due 2015 50,000 50,000
9.80% Series due 2018 - 24,938
9-1/8% Series due 2019 25,000 25,000
Medium-Term Notes
-----------------
First Mortgage Bonds:
4.80% Series A due 1996 5,000 -
7.38% Series A due 1997 20,000 20,000
7.69% Series A due 1999 10,000 10,000
5.96% Series B due 2000 5,000 -
5.98% Series B due 2000 5,000 -
8.05% Series A due 2002 10,000 10,000
6.40% Series B due 2003 20,000 -
6.34% Series B due 2005 5,000 -
6.38% Series B due 2005 5,000 -
6.45% Series B due 2005 5,000 -
6.50% Series B due 2008 5,000 -
9.05% Series A due 2021 10,000 10,000
7.25% Series B due 2023 20,000 -
7.50% Series B due 2023 4,000 -
7.52% Series B due 2023 11,000 -
Unsecured:
4.90% Series A due 1996 10,000 -
8.69% Series A due 1996 5,000 5,000
7.40% Series A due 1997 5,000 5,000
8.93% Series A due 1998 5,000 5,000
8.95% Series A due 1998 10,000 10,000
8.47% Series A due 2001 10,000 10,000
Convertible Debentures
----------------------
7-1/4% Series due 2012 12,931 13,308
-------- --------
272,931 255,904
Less long-term debt due within
one-year - 2,138
-------- -------
Total long-term debt 272,931 47% 253,766 46%
-------- ---- ------- ----
TOTAL CAPITALIZATION $575,170 100% $550,288 100%
======== ==== ======== ====
- ------------------------------------------------------------------------------
*The $2.42 series has a stated value of $25 per share, all other series have
a stated value of $100 per share.
See Accompanying Notes to Consolidated Financial Statements.
-40-
NORTHWEST NATURAL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
- ---------------------------------------------------------------
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:
- ------------------------------------------------
Organization and Principles of Consolidation
- ---------------------------------------------
The consolidated financial statements include:
Regulated utility:
--Northwest Natural Gas Company (Northwest Natural)
Non-regulated wholly-owned businesses:
--Oregon Natural Gas Development Corporation (Oregon
Natural)
--NNG Financial Corporation (Financial Corporation)
--Pacific Square Corporation (Pacific Square)
--NNG Energy Systems, Inc. (Energy Systems)
Together these businesses are referred to herein as the
"Company." Intercompany accounts and transactions have been
eliminated.
Investments in corporate joint ventures and partnerships in
which the Company's ownership is 50 percent or less are
accounted for by the equity method or the cost method (see
Note 11).
Certain amounts from prior years have been reclassified to
conform with the 1993 presentation.
Industry Regulation
- -------------------
The Company's principal business is the distribution of
natural gas which is regulated by the Oregon Public Utility
Commission (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.
Utility Plant
- -------------
Utility plant for Northwest Natural is stated at original
cost. When a depreciable unit of property is retired, the
cost is credited to utility plant and debited to the
accumulated provision for depreciation together with the
cost of removal, less any salvage. No gain or loss is
recognized upon normal retirement.
Allowance for Funds Used During Construction (AFUDC), a non-
cash item, is calculated using actual commercial paper
interest rates. If commercial paper balances are
insufficient to finance the amount of work in progress, a
-41-
NORTHWEST NATURAL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
- ----------------------------------------------------------------
composite of interest costs of debt, shown as a reduction to
interest charges, and a return on equity funds, shown as
other income, is used to compute AFUDC. This amount is
added to utility plant which is a component of rate base.
While cash is not realized currently from AFUDC, it is
realized in the ratemaking process over the service life of
the related property through increased revenues resulting
from higher rate base and higher depreciation expense. The
Company's weighted average AFUDC rates for 1993 and 1992
were 3.5 percent and 4.5 percent, respectively. No AFUDC
was recorded in 1991.
Northwest Natural's provision for depreciation of utility
property, which is computed under the straight-line,
age-life method in accordance with independent engineering
studies and as approved by regulatory authorities,
approximated 4.1 percent of average depreciable plant in
1993, 4.0 percent for 1992 and 4.2 percent for 1991.
Regulatory Balancing Accounts
- -----------------------------
Regulatory balancing accounts are established pursuant to
orders of the state utility regulatory commissions, in
general rate proceedings or expense deferral proceedings, in
order to provide for recovery of revenues or expenses from,
or refunds to, Northwest Natural's utility customers.
Inventories
- -----------
Northwest Natural's inventories of gas in storage and
materials and supplies are stated at the lower of average
cost or net realizable value.
Income Taxes
- ------------
The Company adopted Statement of Financial Accounting
Standard (SFAS) No. 109, "Accounting for Income Taxes" on
January 1, 1993, with no material effect on earnings (see
Note 8). The Company provides deferred federal income tax
for the timing differences between book depreciation and tax
depreciation under the Accelerated Cost Recovery System
(ACRS) for 1981 - 1985 property additions and Modified
Accelerated Cost Recovery System (MACRS) for post-1985
property additions. Consistent with rate and accounting
instructions of regulatory authorities, deferred income
taxes are not currently collected for those income tax
temporary differences where the prescribed regulatory
accounting methods do not provide for current recovery in
rates.
-42-
NORTHWEST NATURAL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
- ----------------------------------------------------------------
Investment tax credits on utility property additions which
reduce income taxes payable are deferred for financial
statement purposes and are amortized over the life of the
related property. Investment and energy tax credits
generated by non-regulated subsidiaries are amortized over a
period of two to five years.
Unbilled Revenue
- ----------------
Northwest Natural accrues for gas deliveries not billed to
customers from the meter reading dates to month end.
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.
Earnings Per Share
- ------------------
Earnings per share are computed based on the weighted
average number of common shares outstanding each year.
Outstanding stock options are common stock equivalents but
are excluded from primary earnings per share computations
due to immateriality.
2. CONSOLIDATED SUBSIDIARY OPERATIONS:
- ----------------------------------------
Oregon Natural Gas Development Corporation
- ------------------------------------------
Oregon Natural is a natural gas exploration and production
subsidiary of the Company. Approximately $22 million of
Oregon Natural's total assets of $39 million are invested in
its wholly-owned subsidiary, Canor Energy Ltd., which
manages and develops natural gas and oil properties in
Canada.
Oregon Natural accounts for its exploration costs under the
successful-efforts method. Costs to acquire and develop oil
and gas properties are capitalized until the volume of
proved gas reserves is determined. If there are inadequate
gas reserves, the related deferred costs are expensed.
Capitalized costs associated with properties under
development were $1.4 million at December 31, 1993.
-43-
NORTHWEST NATURAL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
- ----------------------------------------------------------------
NNG Financial Corporation
- -------------------------
Financial Corporation provides short-term financing for
Oregon Natural, Pacific Square and Energy Systems and has
several financial investments, including investments as a
limited partner in four solar electric generating systems,
four windpower electric generating projects, a hydroelectric
facility and a low-income housing project (see Note 11).
Pacific Square Corporation
- --------------------------
Pacific Square is a real estate management subsidiary of the
Company. Pacific Square owns a 50 percent interest in a
joint venture partnership that owns and operates the
building in which the Company leases its general offices.
Pacific Square also effectively owns a one-third interest in
another partnership that owns and operates an adjacent
building. Pacific Square has agreed to sell its interests
in these partnerships to its joint venture partner through
transactions expected to close in 1994 (see Note 12). The
sale of Pacific Square's interests as proposed would not be
at a loss to the Company.
NNG Energy Systems, Inc.
- -------------------------
Energy Systems was formed to design, construct, own and
operate cogeneration facilities. Energy Systems' only
subsidiary, Agrico Cogeneration Corporation (Agrico), has
been in reorganization under Chapter 11 of the U.S.
Bankruptcy Code (see Note 3).
-44-
NORTHWEST NATURAL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
- ----------------------------------------------------------------
Summarized financial information for the consolidated subsidiaries
follows:
Consolidated Subsidiaries (Thousands) 1993 1992 1991
- --------------------------------------------------------------------------
Statements of Income for the year ended December 31:
Total Operating Revenues $ 10,865 $ 8,183 $ 14,865
Less cost of sales - 183 3,201
-------- -------- --------
Net Operating Revenues 10,865 8,000 11,664
Operating Expenses:
Operations and maintenance 5,942 5,598 10,264
Taxes other than income taxes 240 153 489
Depreciation, depletion and
amortization 7,986 3,309 4,905
Loss on cogeneration facility* - 4,575 23,200
-------- -------- --------
Total operating expenses 14,168 13,635 38,858
-------- -------- --------
Loss from Operations (3,303) (5,635) (27,194)
Other Expense and Interest Charges* (374) (1,670) (3,230)
-------- -------- --------
Loss Before Income Taxes (3,677) (7,305) (30,424)
Income Tax Benefit 2,188 3,682 12,323
-------- -------- --------
Net Loss $ (1,489) $ (3,623) $(18,101)
======== ======== ========
Balance Sheets as of December 31:
Assets:
Non-utility property $ 39,435 $ 41,048 $ 47,660
Accumulated depreciation and
depletion (18,395) (13,137) (11,044)
Investments and other* 34,731 39,781 34,010
Current assets 34,028 16,001 39,955
-------- -------- --------
Total Assets $ 89,799 $ 83,693 $110,581
======== ======== ========
Capitalization and Liabilities:
Capitalization $ 21,843 $ 24,189 $ 29,005
Current liabilities 42,538 33,940 58,458
Other liabilities 25,418 25,564 23,118
-------- -------- --------
Total Capitalization and
Liabilities $ 89,799 $ 83,693 $110,581
======== ======== ========
- --------------------------------------------------------------------------------
*For additional information regarding subsidiary operations, see Notes 3 and 11.
3. AGRICO COGENERATION CORPORATION:
- -------------------------------------
Agrico is a wholly-owned subsidiary of Energy Systems. In
December 1991, Agrico filed with the United States
Bankruptcy Court for the Eastern District of California a
voluntary petition for reorganization under Chapter 11 of
the U.S. Bankruptcy Code. In view of the uncertainty
-45-
NORTHWEST NATURAL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
- ----------------------------------------------------------------
regarding the financial viability of Agrico, the Company
recorded a write-down of $23.2 million (pre-tax) in 1991,
resulting in an after-tax charge equivalent to $1.23 per
share.
In 1992, Energy Systems and Northwest Natural entered a
settlement agreement with United States National Bank of
Oregon (U.S. Bank) with respect to U.S. Bank's $14 million
secured loan to Agrico. Agrico also entered a conditional
settlement agreement with Pacific Gas & Electric Company
(PG&E), the purchaser of power produced by Agrico, with
respect to PG&E's claimed overpayments to Agrico for power
purchased in 1990 and 1991. Agrico also entered a
conditional agreement with Wellhead Electric Company
(Wellhead), the contract operator of the Agrico facility,
for the sale of Agrico's assets to Wellhead.
Based upon the estimated costs to the Company under the
settlements with U. S. Bank and PG&E, the estimated net
proceeds to be received from the sale of Agrico's assets to
Wellhead, and other elements of a Chapter 11 reorganization
plan, the Company recorded a charge of $4.6 million in 1992,
resulting in an after-tax charge of $2.8 million, or 24
cents per share.
The California Public Utilities Commission approved Agrico's
settlement with PG&E in December 1993, and the U. S.
Bankruptcy Court confirmed Agrico's reorganization plan in
January 1994. The sale of Agrico's assets to Wellhead
closed in February 1994. No material impact to 1994
earnings is expected related to these events.
4. CAPITAL STOCK:
- -------------------
Common Stock
- ------------
At December 31, 1993, Northwest Natural had reserved 98,720
shares of common stock for issuance under the Employee Stock
Purchase Plan, 623,203 shares under its Dividend
Reinvestment and Stock Purchase Plan, 153,985 shares under
its 1985 Stock Option Plan (see Note 5), 107,866 shares for
future conversions of its convertible preference stock and
472,427 shares for future conversions of its 7-1/4 percent
Convertible Debentures.
Preference Stock
- ----------------
The $2.375 Series of Convertible Preference Stock is
convertible into shares of common stock at a conversion rate
of 1.6502 shares of common stock for each share of
preference stock. Subject to certain restrictions, it is
-46-
NORTHWEST NATURAL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
- ----------------------------------------------------------------
callable at stipulated prices, plus accrued dividends. The
$6.95 Series of Preference Stock is not redeemable prior to
December 31, 2002, but is subject to mandatory redemption on
that date.
Redeemable Preferred Stock
- --------------------------
The mandatory preferred stock redemption requirements
aggregate $1,042,000 in 1994 and $1,110,000 in 1995, 1996,
1997 and 1998. These requirements are noncumulative. At
any time the Company is in default on any of its obligations
to make the prescribed sinking fund payments, it may not pay
cash dividends on common stock or preference stock. Upon
involuntary liquidation, all series of redeemable preferred
stock are entitled to their stated value.
Generally, the redeemable preferred stock is callable at
stipulated prices, plus accrued dividends, subject to
certain restrictions. At December 31, 1993, redemption
prices were $100 per share for the $4.68 and $4.75 Series.
Shares of the $7.125 Series are redeemable on or after
May 1, 1998 at a price of $104.75 per share decreasing each
year thereafter to $100 per share on or after May 1, 2008.
The following table shows the changes in the number of
shares of the Company's capital stock and the premium on
common stock for the years 1993, 1992 and 1991:
-47-
NORTHWEST NATURAL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
- ----------------------------------------------------------------
------------Shares------------ Premium
Redeemable on
Thousands, Common Preference Preferred Common
Except Share Data Stock Stock Stock Stock
- -------------------------------------------------------------------------------
Balance, December 31, 1990 11,603,507 80,986 489,522 $ 88,377
Sales to employees 8,899 -- -- 188
Sales to stockholders 141,454 -- -- 3,517
Exercise of stock options - net 7,668 -- -- 24
Conversion of preference stock
to common 10,253 (6,215) -- 123
Conversion of convertible
debentures to common 13,396 -- -- 357
Sinking fund purchases -- -- (24,068) --
Other -- -- -- 13
---------- -------- -------- --------
Balance, December 31, 1991 11,785,177 74,771 465,454 92,599
Sales to the public 990,000 250,000 -- 25,327
Sales to employees 9,350 -- -- 222
Sales to stockholders 157,046 -- -- 4,228
Exercise of stock options - net 19,918 -- -- 183
Conversion of preference stock
to common 6,846 (4,150) -- 82
Conversion of convertible
debentures to common 4,388 -- -- 117
Sinking fund purchases -- -- (23,859) --
Other -- -- -- 10
---------- ------- ------- --------
Balance, December 31, 1992 12,972,725 320,621 441,595 122,768
Sales to employees 9,542 -- -- 249
Sales to stockholders 154,850 -- 150,000 4,724
Exercise of stock options
- net 19,110 -- -- 172
Conversion of preference
stock to common 8,740 (5,298) -- 105
Conversion of convertible
debentures to common 12,289 -- -- 328
Redemptions -- -- (416,873) --
Sinking fund purchases -- -- (4,316) --
Other -- -- -- (6)
---------- ------- ------- --------
Balance, December 31, 1993 13,177,256 315,323 170,406 $128,340
========== ======= ======= ========
- --------------------------------------------------------------------------
5. STOCK OPTION AND PURCHASE PLANS:
- -------------------------------------
Northwest Natural's 1985 Stock Option Plan (Plan) authorizes
an aggregate of 300,000 shares of common stock for issuance
as incentive or non-statutory stock options. These options
may be granted only to officers and key employees of the
Company designated by its Board of Directors.
-48-
NORTHWEST NATURAL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
- ----------------------------------------------------------------
All options granted are at an option price not less than
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 owned by them for at
least one year, at the current market price, to purchase
shares at the option price.
During 1985 and 1990, 150,000 and 86,500 options were
granted under the Plan at option prices of $17.625 and
$24.875, respectively.
Information regarding the Plan is summarized below:
Options
----------------------------
Year Ended December 31 1993 1992 1991
-----------------------------------------------------------
Outstanding, beginning of year 101,326 138,408 158,029
$17.625 Options:
Exchanged by holders (6,184) (7,673) (6,659)
Exercised (9,334) (13,440) (5,362)
$24.875 Options:
Exchanged by holders (4,729) (6,017) (5,294)
Exercised (9,776) (6,652) (2,306)
Expired - (3,300) -
------- ------- -------
Outstanding, end of year 71,303 101,326 138,408
======= ======= =======
Available for grant, end of year 82,682 82,682 79,382
======= ======= =======
--------------------------------------------------------------
Northwest Natural also has an employee stock purchase plan
whereby employees may purchase common stock at 92 percent
of average bid and ask market price on the subscription
date. The subscription date is set annually, and each
employee may purchase up to 600 shares payable through
payroll deduction over a six to twelve month period.
6. LONG TERM DEBT:
- --------------------
The issuance of first mortgage bonds under the Mortgage and
Deed of Trust is limited by property, earnings and other
provisions of the mortgage. The Company's Mortgage and Deed
of Trust constitutes a first mortgage lien on substantially
all of its utility property.
-49-
NORTHWEST NATURAL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
- ----------------------------------------------------------------
The 7-1/4 percent Series of Convertible Debentures may be
converted at any time for 33-1/2 shares of common stock for
each $1,000 face value ($29.85 per share).
The sinking fund requirements and maturities for the five
years ending December 31, 1998, on the long-term debt
outstanding at December 31, 1993, amount to: none in 1994;
$1.0 million in 1995; $21.0 million in 1996; $26.0 million
in 1997; and $16.0 million in 1998.
7. NOTES PAYABLE AND LINES OF CREDIT:
- ---------------------------------------
Northwest Natural has available through September 30, 1994,
lines of credit totalling $80 million consisting of a
primary fixed amount of $40 million plus an excess amount of
up to $40 million available as needed, at Northwest
Natural's option, on a monthly basis. Under the terms of
these bank lines, Northwest Natural pays a commitment fee
but is not required to maintain compensating bank balances.
The interest rates on borrowings under these lines of credit
are based on current market rates as negotiated. There were
no outstanding balances as of December 31, 1993.
Financial Corporation has available through September 30,
1994, lines of credit with two commercial banks totalling
$20 million, including $10 million committed and $10 million
uncommitted. Financial Corporation pays a fee on the
committed line but not on the uncommitted line; it is not
required to maintain compensating bank balances on either
line. The interest rates on borrowings under these lines of
credit also are based on current market rates as negotiated.
Financial Corporation's lines are supported by the
unconditional guaranty of Northwest Natural. There were no
outstanding balances as of December 31, 1993 under the
Financial Corporation bank lines.
Northwest Natural and Financial Corporation issue domestic
commercial paper under agency agreements with a commercial
bank. The amounts and average interest rates of commercial
paper outstanding were as follows at December 31:
1993 1992
---------------- ----------------
Average Average
Millions Amount Rate Amount Rate
-----------------------------------------------------------
Northwest Natural $53.4 3.4% $34.4 3.8%
Financial Corporation 19.1 3.4% 11.9 3.7%
----- -----
Total $72.5 $46.3
===== =====
------------------------------------------------------------
-50-
NORTHWEST NATURAL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
- ----------------------------------------------------------------
Commercial paper issued by Northwest Natural and Financial
Corporation is supported by committed bank lines.
Additionally, Financial Corporation's commercial paper is
supported by the unconditional guaranty of Northwest
Natural.
8. INCOME TAXES:
- -----------------
The Company adopted SFAS No. 109, "Accounting for Income
Taxes," effective January 1, 1993. The adoption of the new
standard results in an increase in net deferred tax
liabilities of $62 million to reflect deferred taxes on
differences previously flowed-through and to adjust existing
deferred taxes to the level required at the current
statutory rate. An offsetting regulatory asset of $62
million was also recorded. The regulatory asset is
primarily based upon differences between the book and tax
basis of utility plant in service and the accumulated
provision for depreciation. It is expected that the
regulatory asset will be recovered in future rates. The
implementation of SFAS No. 109 did not significantly impact
results of operations.
A reconciliation between income taxes calculated at the
statutory federal tax rate and the tax provision reflected
in the financial statements is as follows:
-51-
Thousands 1993 1992 1991
- -------------------------------------------------------------------
Computed income taxes based on
statutory federal income tax
rate (1993-35%; 1992 and 1991-34%) $20,910 $ 7,727 $ 5,677
Increase (reduction) in taxes
resulting from:
Differences between book and tax
depreciation 1,561 1,233 1,566
Current state income tax, net
of federal tax benefit 2,525 711 727
Federal income tax credits (348) - -
Restoration of investment tax credit (1,064) (1,124) (2,026)
Elimination of amounts previously
provided (1,059) (1,229) (4,462)
Real and personal property taxes 113 - 548
Removal costs (320) (335) (578)
Unconsolidated foreign subsidiary
income (496) - -
Other - net 274 (32) 869
------- ------- -------
Total provision for income taxes $22,096 $ 6,951 $ 2,321
======= ======= =======
- ---------------------------------------------------------------------
The provision for income taxes consists of the following:
Thousands 1993 1992 1991
- ---------------------------------------------------------------------
Income taxes currently payable:
Federal $ 13,368 $ 7,577 $ 6,485
State 2,166 375 1,795
Foreign 30 13 (139)
------- ------- -------
Total 15,564 7,965 8,141
------- ------- -------
Deferred taxes - net:
Federal 5,896 (676) (1,805)
State 1,718 616 (1,989)
------- ------ -------
Total 7,614 (60) (3,794)
------- ------ -------
Investment and energy tax credits restored:
From utility operations (800) (800) (800)
From subsidiary operations (282) (154) (1,226)
------- ------ -------
Total (1,082) (954) (2,026)
------- ------ -------
Total provision for income taxes $22,096 $6,951 $ 2,321
======= ====== =======
Percentage of pretax income 36.99% 30.59% 13.90%
======= ====== =======
- --------------------------------------------------------------------
-52-
NORTHWEST NATURAL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
- ----------------------------------------------------------------
The annual provision for deferred income taxes is comprised of the following:
Thousands 1993 1992 1991
- ----------------------------------------------------------------------------
Cost of gas delivered and unbilled $ - $ - $ (1,447)
ACRS and MACRS deductions in excess of
related book depreciation 5,925 8,661 10,199
Revenues and costs deferred for tax purposes 1,528 2,600 (1,718)
Agrico book loss - (1,374) (8,839)
Real and personal property taxes 2,329 (2,328) -
Alternative minimum tax credits - (6,866) -
Elimination of amounts previously provided (2,216) (1,025) (1,740)
Other 48 272 (249)
------- -------- -------
Total $ 7,614 $ (60) $(3,794)
======= ======== =======
- ------------------------------------------------------------------------------
9. EMPLOYEE RETIREMENT PLANS:
- -------------------------------
The Company has two non-contributory defined benefit
retirement plans covering all regular, full-time employees
with more than one year of service. The benefits under the
plans are based upon years of service and the employee's
average compensation during the final years of service. The
Company's funding policy is to make the annual contribution
required by applicable regulations and recommended by its
actuary. Plan assets consist primarily of marketable
securities, corporate obligations, U.S. government
obligations, real estate and cash equivalents.
-53-
NORTHWEST NATURAL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
- ----------------------------------------------------------------
The following table sets forth the amounts recognized in the
Company's financial statements and the combined funded
status of the retirement plans:
Pension Costs for the Year
(Thousands): 1993 1992 1991
-----------------------------------------------------------------
Service cost $ 2,587 $ 2,528 $ 2,098
Interest cost 6,024 5,688 5,109
Return on assets (17,762) (8,797) (16,336)
Net amortization and deferral 9,526 1,215 9,045
-------- -------- --------
Annual pension cost (benefit) $ 375 $ 634 $ (84)
======== ======== ========
-----------------------------------------------------------------
Vested benefit obligation $ 69,859 $ 62,152 $ 55,304
Total accumulated benefit
obligation $ 70,618 $ 62,971 $ 55,802
-----------------------------------------------------------------
Funded status as of December 31:
Plan assets at fair value $108,579 $ 94,595 $ 88,472
Projected benefit obligation
for service rendered to date 86,814 77,278 69,074
-------- -------- --------
Funded status 21,765 17,317 19,398
Unrecognized net gain (21,417) (15,895) (16,601)
Unrecognized net asset at
transition (2,310) (2,706) (3,102)
Unrecognized prior service costs 4,413 3,531 1,690
-------- -------- --------
Prepaid pension cost $ 2,451 $ 2,247 $ 1,385
======== ======== ========
Total cash contribution $ 579 $ 1,496 $ 810
======== ======== ========
------------------------------------------------------------------
Discount rate 7.50% 8.00% 8.00%
===== ===== =====
Expected long-term rate
of return on plan assets 9.00% 9.00% 9.00%
===== ===== =====
Rate for compensation increases 5.13% 5.13% 5.13%
===== ===== =====
-------------------------------------------------------------------
Effective January 1, 1994, the Company changed the assumed
discount rate used in determining the funded status of the
plans from 8.00 percent to 7.50 percent. The new discount
rate was used in determining the funded status of the plans
at year-end 1993 and will be used to determine annual
pension cost in 1994.
The Company has a qualified "Retirement K Savings Plan"
under Internal Revenue Code Section 401(k) and a non-
qualified "Executive Deferred Compensation Plan", for
eligible employees. These plans are designed to enhance the
existing retirement program of employees and to assist them
-54-
NORTHWEST NATURAL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
- ----------------------------------------------------------------
in strengthening their financial security by providing an
incentive to save and invest regularly. Company
contributions to these plans in 1993, 1992 and 1991 were
$450,000, $315,000 and $290,000, respectively.
The Company has a non-qualified supplemental retirement plan
for eligible executive officers which it is funding with
trust-owned life insurance. The amount of coverage is
designed to provide sufficient returns to recover all costs
of the plan if assumptions made as to mortality experience,
policy earnings, and other factors are realized. Expenses
related to the plan were $840,000, $883,000 and $894,000 in
1993, 1992 and 1991, respectively.
10. POSTRETIREMENT HEALTH CARE AND LIFE INSURANCE BENEFITS:
- ------------------------------------------------------------
The Company currently provides continued health care and
life insurance coverage after retirement for exempt
employees. These benefits and similar benefits for active
employees are provided by insurance companies and related
premiums are based on the amount of benefits paid during the
year.
Effective January 1, 1993, the Company adopted SFAS No. 106,
"Employers' Accounting for Postretirement Benefits Other
than Pensions." SFAS No. 106 requires the Company to accrue
the estimated cost of retiree benefit payments during the
years of employees' active service. The Company previously
expensed the cost of these benefits, which are principally
health care, as premiums were paid. SFAS No. 106 allows
recognition of the cumulative effect of the liability in the
year of adoption or amortization of the obligation over a
period of up to 20 years. The Company elected to recognize
this obligation of approximately $11,300,000 over a period
of 20 years. The Company's cash flows are not affected by
implementation of this Statement, but implementation
decreased income from operations for 1993 by $715,000.
The incremental costs of approximately $1,110,000 per year
(pre-tax) relating to SFAS No. 106 are not currently
included in the Company's rates. The staff of the OPUC has
recommended that the portion of these costs allocated to
Oregon (approximately 95 percent) be authorized for recovery
in rates only pursuant to a general rate case filing, and
has recommended against the use of deferred accounting
treatment for their recovery. The Company is charging the
Oregon portion of these costs to expense. The WUTC has
approved deferred accounting treatment for the portion of
these costs allocated to Washington (approximately 5
percent), pending final approval for recovery in a general
rate case filing. The Company will continually review its
-55-
NORTHWEST NATURAL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
- ----------------------------------------------------------------
need for general rate cases covering these and other
expenses but has no present plans to file a general rate
case in Oregon or Washington.
In 1993, 1992 and 1991, the Company recognized $1,751,000,
$671,000 and $588,000, respectively, as the cost of
postretirement health care and life insurance benefits. The
following table sets forth the health care plan's status at
December 31, 1993:
Accumulated postretirement benefit obligation (Thousands):
----------------------------------------------------------
Retirees $ 6,675
Fully eligible active plan participants 260
Other active plan participants 4,815
--------
Total accumulated postretirement
benefit obligation 11,750
Fair value of plan assets -
--------
Accumulated postretirement benefit obligation
in excess of plan assets 11,750
Unrecognized transition obligation (10,716)
Unrecognized gain 76
--------
Accrued postretirement benefit cost $ 1,110
========
Net postretirement benefit cost (Thousands):
--------------------------------------------
Service cost - benefits earned during
the period $ 255
Return on plan assets (if any) -
Interest cost on accumulated postretirement
benefit obligation 932
Amortization of transition obligation 564
--------
Net postretirement benefit cost $ 1,751
========
------------------------------------------------------------
The assumed health care cost trend rate used in measuring
the accumulated postretirement benefit obligation for pre-
Medicare eligibility is 12 percent for 1994; 10 percent for
1995; then decreasing over the next 10 years to 5 percent.
The rate for HMO plan and post-Medicare eligibility is
9 percent for 1994-5, decreasing over the next 10 years to
5 percent. A one-percentage-point change in the assumed
health care cost trend rate for each year would adjust the
accumulated postretirement benefit obligation as of
December 31, 1993 and net postretirement health care cost by
approximately 16 percent. The assumed discount rate used in
determining the accumulated postretirement benefit
obligation was 7.5 percent.
-56-
NORTHWEST NATURAL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
- ----------------------------------------------------------------
11. INVESTMENTS:
- -----------------
The following table summarizes the Company's year-end
investments in affiliated entities accounted for under the
equity and cost methods, and its investment in a leveraged
lease.
Thousands 1993 1992
------------------------------------------------------------
Electric generation (solar and
wind-power) $21,043 $22,757
Aircraft leveraged lease 9,079 8,264
Automated meter-reading technology 1,301 1,352
Gas pipeline and other 1,395 445
------- -------
Total investments and other $32,818 $32,818
======= =======
-----------------------------------------------------------
Financial Corporation has invested in four solar electric
generation plants located near Barstow, California. Power
generated by these stations is sold to Southern California
Edison Company. Financial Corporation's ownership interests
in these projects range from 4.0 percent to 5.3 percent.
Financial Corporation also has invested in four U. S.
Windpower Partners electric generating projects, with
facilities located near Livermore and Palm Springs,
California. The wind-generated power is sold to PG&E and
Southern California Edison Company under long-term
contracts. Financial Corporation's ownership interests in
these projects range from 8.5 percent to 41 percent.
In 1987, Oregon Natural purchased a Boeing 737-300 aircraft
which was leased to Continental Airlines for 20 years under
a leveraged lease agreement.
In 1990, the Company invested in a developer of automated
meter-reading devices, with facilities located in Spokane,
Washington. The Company's ownership interest is 10 percent.
-57-
NORTHWEST NATURAL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
- ----------------------------------------------------------------
12. COMMITMENTS AND CONTINGENT LIABILITIES:
- --------------------------------------------
Lease Commitments
-----------------
Future lease commitments are: $5.2 million in 1994;
$4.9 million in 1995; $4.2 million in 1996; $4.0 million in
1997; and $1.8 million in 1998. Thereafter, total
commitments amount to $12.0 million. These commitments
principally relate to the lease of the Company's office
headquarters and computer systems. The pending sale of the
Company's investment in the partnership which owns and
operates its office headquarters building (see Note 2) will
not affect the Company's lease which extends through 2006,
with options to extend beyond that date. Rent paid by the
Company to the partnership was $2.8 million in 1993, and
$2.2 million in 1992 and 1991.
Total rental expense for 1993, 1992 and 1991 was
$5.2 million, $4.4 million and $4.5 million, respectively.
Purchase Commitments
--------------------
The Company has signed agreements providing for the
availability of firm pipeline capacity. Under these
agreements, the Company must make fixed monthly payments for
contracted capacity. The pricing component of the monthly
payment is established, and subject to change, by U.S. or
Canadian regulatory bodies. The aggregate amount of such
required payments was as follows at December 31, 1993:
Commitments (Thousands)
------------------------------------------------------------
1994 $ 58,961
1995 62,123
1996 77,232
1997 74,237
1998 74,012
Thereafter 874,867
----------
Total 1,221,432
Less: Amount representing interest 504,957
----------
Total at present value $ 716,475
==========
------------------------------------------------------------
The Company's total payments of fixed charges under these
agreements in 1993, 1992 and 1991 were $46.7 million, $34.7
million and $32.5 million, respectively. In addition, the
-58-
NORTHWEST NATURAL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
- ----------------------------------------------------------------
Company is required to pay per-unit charges based on the
actual quantities shipped under the agreements. In certain
of the Company's 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.
The Company has contracted with an external vendor for the
development of a customer information system for a fixed
contract price of $12 million to be incurred over four years
as follows: $3.6 million in 1993; $4.7 million in 1994;
$0.7 million in 1995; and $3.0 million in 1996.
Environmental Matters
---------------------
In June 1992, the City of Salem, Oregon, requested the
Company's participation in its review of an environmental
assessment of riverfront property in Salem that is the
proposed site for a park and other public developments.
Within the property is a block previously owned by the
Company which was the former site of a manufactured gas
plant. The Company's corporate predecessor operated the
plant for less than four months in 1929 before closing it
upon completion of a pipeline providing gas transmission
from Portland to Salem. The City has determined that there
is environmental contamination on the site, and that a
remediation process involving the Company and at least two
other prior owners of the block will be required. To date
the Company has not obtained sufficient information to
determine the extent of its liability for any such
remediation.
The Company owns property in Linnton, Oregon, that is the
former site of a gas manufacturing plant that was closed in
1956. Although limited testing for environmental
contamination has been undertaken by other parties on
portions of the site, no comprehensive studies have been
performed. The Company submitted a work plan for the site
to the Oregon Department of Environmental Quality (ODEQ) in
1987, but those efforts were suspended at ODEQ's request
while the Company and other parties participated in a joint
hydrogeologic study of an area adjacent to the site. In
September 1993, pursuant to ODEQ procedures, the Company
submitted a notice of intent to participate in the ODEQ's
Voluntary Cleanup Program. In January 1994, this site was
formally placed in the program. It is anticipated that the
site investigation will commence during 1994.
In September 1993, the Company recorded an expense of
$500,000 for the estimated costs of consultants' fees, ODEQ
oversight cost reimbursements, and legal fees in connection
with the voluntary investigation at the Linnton site. To
date, the Company has not obtained sufficient information to
-59-
NORTHWEST NATURAL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
- ----------------------------------------------------------------
determine whether any remediation will be required at this
site or, if so, the extent of its liability for any such
remediation. The Company expects that its costs of
investigation and any remediation for which it may be liable
should be recoverable, in large part, from insurance or
through future rates.
Litigation
----------
The Company is party to certain legal actions in which
claimants seek material amounts. Although it is impossible
to predict the outcome with certainty, based upon the
opinions of legal counsel, management does not expect
disposition of these matters to have a materially adverse
effect on the Company's financial position or results of
operations.
13. FAIR VALUE OF FINANCIAL INSTRUMENTS:
- -----------------------------------------
The estimated fair values of the Company's financial
instruments have been determined by the Company using
available market information and appropriate valuation
methodologies. The following is a list of financial
instruments whose carrying values are sensitive to market
conditions:
December 31, 1993 December 31, 1992
-------------------- -------------------
Carrying Estimated Carrying Estimated
Thousands of Dollars Amount Fair Value Amount Fair Value
- ----------------------------------------------------------------
Preference stock $ 26,633 $ 26,698 $ 26,766 $ 28,354
Redeemable preferred
stock 17,041 16,573 28,218 26,947
Long-term debt 272,931 301,358 255,904 283,280
- ----------------------------------------------------------------
-60-
NORTHWEST NATURAL GAS COMPANY
QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
------------Quarter Ended-----------
Dollars (Thousands
Except Per Share) Mar. 31, June 30, Sept. 30, Dec. 31, Total
- -----------------------------------------------------------------------------
1992
Operating revenues 90,326 47,791 38,811 97,438 274,366
Net operating revenues 56,291 30,827 26,859 58,473 172,450
Net income (loss) 13,130 (3,232) (7,785) 13,662 15,775
Earnings (loss) per share 1.06 (0.33) (0.71) 1.08 1.11*
1993
Operating revenues 128,714 61,789 47,451 120,763 358,717
Net operating revenues 82,116 40,141 30,805 66,822 219,884
Net income (loss) 24,653 2,767 (4,423) 14,650 37,647
Earnings (loss) per share 1.82 0.15 (0.40) 1.05 2.61*
- -------------------------------------------------------------------------------
*Quarterly earnings per share are based upon the average number of
common shares outstanding during each quarter. Because the average
number of shares outstanding has increased in each quarter shown, the
sum of quarterly earnings does 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.
-61-
NORTHWEST NATURAL GAS COMPANY
SCHEDULE V - PROPERTY, PLANT AND EQUIPMENT
YEAR ENDED DECEMBER 31, 1993
(Thousands of Dollars)
Balance at Balance
Beginning Additions Retire- Other at End of
Classification of Period at Cost ments Changes* Period
- -------------------------------------------------------------------------------------
Utility - gas:
Intangibles $ 39 $ 718 $ - $ 9,085 $ 9,842
Land and land rights 6,876 68 - - 6,944
Structures and improvement 14,863 2,743 - - 17,606
Generating plant equipment 388 - - - 388
Distribution 382,731 29,165 2,139 - 409,757
Customers' installations 268,325 26,311 5,063 - 289,573
General equipment 45,673 5,124 2,742 (9,080) 38,975
Holders 51,962 440 - (5) 52,397
Petroleum gas equipment (butane plant) 3 - - - 3
Natural gas equipment (gate stations
and mixing equipment) 1,254 1 - - 1,255
Property held for future use 803 - - - 803
Construction work in progress 1,330 6,130 - - 7,460
-------- ------- ------ ------- --------
Utility plant - gas 774,247 70,700 9,944 - 835,003
Gas stored underground - long-term 5,027 - - - 5,027
-------- ------- ------ ------- --------
Total utility property, plant and
equipment (including intangibles) $779,274 $70,700 $9,944 $ 0 $840,030
======== ======= ====== ======= ========
Non-utility:
Land $ 125 $ - $ - $ - $ 125
Structures 1,002 - - - 1,002
Storage tanks 2,202 - - - 2,202
GELP conversion burners 252 - 252 - -
Subsidiaries' property 41,048 955 134 (2,434) 39,435
-------- ------- ------ ------- --------
Total non-utility property,
plant and equipment $ 44,629 $ 955 $ 386 $(2,434) $ 42,764
======== ======= ====== ======= ========
___________________
*Includes transfers and reclassifications.
-62-
NORTHWEST NATURAL GAS COMPANY
SCHEDULE V - PROPERTY, PLANT AND EQUIPMENT
YEAR ENDED DECEMBER 31, 1992
(Thousands of Dollars)
Balance at Balance
Beginning Additions Retire- Other at End of
Classification of Period at Cost ments Changes* Period
- -------------------------------------------------------------------------------------------------
Utility - gas:
Intangibles $ 39 $ - $ - $ - $ 39
Land and land rights 6,360 516 - - 6,876
Structures and improvement 13,527 1,336 - - 14,863
Generating plant equipment 388 - - - 388
Distribution 355,706 27,778 755 2 382,731
Customers' installations 245,917 24,123 1,713 (2) 268,325
General equipment 42,376 4,325 1,028 - 45,673
Holders 51,480 482 - - 51,962
Petroleum gas equipment (butane plant) 3 - - - 3
Natural gas equipment (gate stations
and mixing equipment) 1,246 2 (6) - 1,254
Property held for future use - 803 - - 803
Construction work in progress - 1,330 - - 1,330
-------- ------- ------ -------- --------
Utility plant - gas 717,042 60,695 3,490 - 774,247
Gas stored underground - long-term 5,027 - - - 5,027
-------- ------- ------ -------- --------
Total utility property,
plant and equipment
(including intangibles) $722,069 $60,695 $3,490 $ - $779,274
======== ======= ====== ======== ========
Non-utility:
Land $ 125 $ - $ - $ - $ 125
Structures 1,002 - - - 1,002
Storage tanks 2,202 - - - 2,202
GELP conversion burners 276 - 24 - 252
Subsidiaries' property 47,660 8,743 3,502 (11,853) 41,048
-------- ------- ------ -------- --------
Total non-utility property,
plant and equipment $ 51,265 $ 8,743 $3,526 $(11,853) $ 44,629
======== ======= ====== ======== ========
_____________________
*Includes write-down of cogeneration plant, transfers and reclassifications.
-63-
NORTHWEST NATURAL GAS COMPANY
SCHEDULE V - PROPERTY, PLANT AND EQUIPMENT
YEAR ENDED DECEMBER 31, 1991
(Thousands of Dollars)
Balance at Balance
Beginning Additions Retire- Other at End of
Classification of Period at Cost ments Changes* Period
- -------------------------------------------------------------------------------------------------
Utility - gas:
Intangibles $ 39 $ - $ - $ - $ 39
Land and land rights 6,007 353 - - 6,360
Structures and improvement 12,605 965 - (43) 13,527
Generating plant equipment 388 - - - 388
Distribution 333,860 23,354 1,515 7 355,706
Customers' installations 223,624 23,583 1,281 (9) 245,917
General equipment 34,590 9,267 1,478 (3) 42,376
Holders 48,909 2,559 35 47 51,480
Petroleum gas equipment (butane plant) 9 - 6 - 3
Natural gas equipment (gate stations
and mixing equipment) 1,237 35 27 1 1,246
Construction work in progress 2,369 (2,369) - - --
-------- ------- ------ -------- --------
Utility plant - gas 663,637 57,747 4,342 - 717,042
Gas stored underground - long-term 5,027 - - - 5,027
-------- ------- ------ -------- --------
Total utility property, plant and
equipment (including intangibles) $668,664 $57,747 $4,342 $ - $722,069
======== ======= ====== ======== ========
Non-utility:
Land $ 125 $ - $ - $ - $ 125
Structures 1,002 - - - 1,002
Storage tanks 2,202 - - - 2,202
GELP conversion burners 307 - 31 - 276
Subsidiaries' property 66,680 5,181 23 (24,178) 47,660
-------- ------- ------ -------- --------
Total non-utility property,
plant and equipment $ 70,316 $ 5,181 $ 54 $(24,178) $ 51,265
======== ======= ====== ======== ========
______________________
*Includes write-down of cogeneration plant, transfers and reclassifications.
-64-
NORTHWEST NATURAL GAS COMPANY
SCHEDULE VI - ACCUMULATED DEPRECIATION, DEPLETION AND
AMORTIZATION OF PROPERTY, PLANT AND EQUIPMENT
YEARS ENDED DECEMBER 31, 1993, 1992 AND 1991
(Thousands of Dollars)
Additions
Balance at Charged to Balance
Beginning Costs and Retire- Other at End of
of Period Expenses ments Changes* P1eriod
- --------------------------------------------------------------------------------------------------
Year ended December 31, 1993
- - accumulated depreciation**
Utility - gas $233,385 $31,697 $ 9,944 $ 144 $255,282
Non-utility - parent 2,343 - 252 160 2,251
Non-utility - subsidiary 13,137 7,986 134 (2,594) 18,395
-------- ------- ------- ------- --------
Total $248,865 $39,683 $10,330 $(2,290) $275,928
======== ======= ======= ======= ========
Year ended December 31, 1992
- - accumulated depreciation**
Utility - gas $207,165 $29,726 $3,490 $ (16) $233,385
Non-utility - parent 2,117 - 24 250 2,343
Non-utility - subsidiary 11,044 3,309 2,179 963 13,137
-------- ------- ------ ------- --------
Total $220,326 $33,035 $5,693 $ 1,197 $248,865
======== ======= ====== ======= ========
Year ended December 31, 1991
- - accumulated depreciation**
Utility - gas $183,404 $28,718 $4,342 $ (615) $207,165
Non-utility - parent 1,946 - 20 191 2,117
Non-utility - subsidiary 8,077 4,905 23 (1,915) 11,044
-------- ------- ------ ------- --------
Total $193,427 $33,623 $4,385 $(2,339) $220,326
======== ======= ====== ======= ========
_____________________
*Includes write-down of cogeneration plant, plus removal costs, less salvage credits.
**Accumulated depreciation is maintained for all tangible property, operating and non-operating.
-65-
NORTHWEST NATURAL GAS COMPANY
SCHEDULE IX - SHORT-TERM BORROWINGS
YEARS ENDED DECEMBER 31, 1993, 1992 AND 1991
(Thousands of Dollars)
Weighted
Weighted Average Average
Average Maximum (Daily) (Daily)
Balance Interest Rate Amount Outstanding Interest
at End at End of Outstanding During Rate During
of Period of Period at Month End Period Period
- -----------------------------------------------------------------------------------------------------
Year ended December 31, 1993:
Commercial Paper $72,548 3.4% $81,015 $39,965 3.3%
Bank Borrowings - - - $ 7 3.8%
Other Borrowings - - - $ 66 8.9%
Year ended December 31, 1992:
Commercial Paper $46,335 3.7% $96,259 $55,840 3.9%
Bank Borrowings - - $ 4,500 $ 52 4.7%
Other Borrowings $ 774 9.0% $ 774 $ 34 9.0%
Year ended December 31, 1991:
Commercial Paper $88,619 5.2% $88,619 $58,374 6.3%
The weighted average interest rate during each year is computed by dividing the interest
expense during the period by the average daily debt balance.
-66-
NORTHWEST NATURAL GAS COMPANY
SCHEDULE X - SUPPLEMENTARY INCOME STATEMENT INFORMATION
YEARS ENDED DECEMBER 31, 1993, 1992 AND 1991
(Thousands of Dollars)
1993 1992 1991
- ---------------------------------------------------------------------------------------------
Taxes other than federal income and state excise taxes:
Ad valorem $13,974 $11,509 $10,551
Business and franchise taxes and license fees 7,533 5,770 6,419
Payroll 2,878 2,623 2,684
Other 936 810 961
Miscellaneous subsidiary taxes 240 153 489
------- ------- -------
Total $25,561 $20,865 $21,104
======= ======= =======
Maintenance and repairs, depreciation and amortization are reported on Statements of Income.
Advertising costs are insignificant.
-67-
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
ACCOUNTING AND FINANCIAL DISCLOSURE
None.
PART III
(Item 10. Directors and Executive Officers of the
Registrant; Item 11. Executive Compensation; Item 12.
Security Ownership of Certain Beneficial Owners and
Management; and Item 13. Certain Relationships and
Related Transactions.)
Information called for by Part III (Items 10., 11.,
12. and 13.) is incorporated herein by reference to the Company's
definitive proxy statement, "Item (1) - Election of Directors,
Executive Compensation and Compensation Pursuant to Certain
Plans." See the Additional Item included in Part I for
information concerning executive officers of the Company.
PART IV
Item 14. 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
Supplementary Schedules is incorporated by
reference to Item 8.
2. List of Exhibits filed:
*(3a.) Restated Articles of Incorporation,
as filed and effective June 24, 1988
and amended December 8, 1992 and
December 1, 1993 (incorporated herein
by reference to Exhibit 4(a) to File
No. 33-51271).
(3b.) Bylaws as amended December 16, 1993.
*(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,
68-
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); and Supplemental
Indenture No. 19 to the Mortgage and
Deed of Trust (incorporated herein by
reference to Exhibit 4(c) in File No.
33-64014).
(4a.(1)) Copy of Supplemental Indenture No. 20
to the Mortgage and Deed of Trust,
dated as of June 1, 1993.
*(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.
(4f.) Officers' Certificate dated June 18,
1993 creating Series B of the
Company's Unsecured Medium-Term
Notes.
(10j.) Transportation Agreement, dated
June 29, 1990, between the Company
and Northwest Pipeline Corporation.
*(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
-69-
No. 0-994).
(10j.(2)) Firm Transportation Service
Agreement, dated November 10, 1993,
between the Company and Pacific Gas
Transmission Company.
(11) Statement re computation of fully-
diluted per share earnings.
(12) Statement re computation of ratios.
(23) Independent Auditors' Consent.
Executive Compensation Plans and Arrangements:
----------------------------------------------
*(10a.) Employment agreement, dated
October 27, 1983, between the Company
and an executive officer
(incorporated herein by reference to
Exhibit (10a.) to Form 10-K for 1989,
File No. 0-994).
*(10b.) Executive Supplemental Retirement
Income Plan, 1989 Republication,
effective January 1, 1989
(incorporated herein by reference to
Exhibit (10b.) to Form 10-K for 1988,
File No. 0-994).
*(10c.) 1985 Stock Option Plan, as amended
effective January 1, 1987
(incorporated herein by reference to
Exhibit (10c.) to Form 10-K for 1992,
File No. 0-994).
*(10e.) Executive Deferred Compensation Plan,
1990 Restatement, effective
January 1, 1990 (incorporated herein
by reference to Exhibit (10e.) to
Form 10-K for 1990, File No. 0-994).
*(10e.-1) Amendment No. 1 to Executive Deferred
Compensation Plan (incorporated by
reference to Exhibit (10e.-1) to Form
10-K for 1991, File No. 0-994).
*(10f.) Directors Deferred Compensation Plan,
1988 Restatement, effective
January 1, 1988 (incorporated herein
by reference to Exhibit (10g.) to
Form 10-K for 1987, File No. 0-994).
-70-
*(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
July 1, 1991 (incorporated herein by
reference to Exhibit (10i.) to Form 10-K
for 1991, File No. 0-994).
*(10k.) Executive Annual Incentive Plan,
effective March 1, 1990, as amended
effective January 1, 1992 (incorporated
herein by reference to Exhibit (10k.) to
Form 10-K for 1991, File No. 0-994).
*(10l.) Employment agreement dated November 27,
1989, between the Company and an
executive officer (incorporated herein
by reference to Exhibit (10l.) to
Form 10-K for 1991, 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.
(b) Reports on Form 8-K.
No Current Reports on Form 8-K were filed during the
quarter ended December 31, 1993.
[FN]
___________________________________
*Incorporated herein by reference as indicated.
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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 28, 1994 By /s/ Robert L. Ridgley
----------------------- -----------------------------
Robert L. Ridgley, 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/ Robert L. Ridgley Principal Executive Officer March 28, 1994
- ---------------------- and Director
Robert L. Ridgley
President and Chief Executive Officer
/s/ Bruce R. DeBolt Principal Financial Officer March 28, 1994
- ---------------------
Bruce R. DeBolt
Senior Vice President, Finance,
and Chief Financial Officer
/s/ D. James Wilson Principal Accounting Officer March 28, 1994
- -----------------------
D. James Wilson
Treasurer and Controller
/s/ Mary Arnstad Director )
- ---------------------- )
Mary Arnstad )
)
/s/ Thomas E. Dewey, Jr. Director )
- ------------------------ )
Thomas E. Dewey, Jr. )
)
/s/ Tod R. Hamachek Director )
- ------------------------ )
Tod R. Hamachek )
)
/s/ Richard B. Keller Director )
- ------------------------ )
Richard B. Keller )
)
/s/ Wayne D. Kuni Director )
- ------------------------ )
Wayne D. Kuni )
)
/s/ Dwight A. Sangrey Director ) March 28, 1994
- ------------------------ )
Dwight A. Sangrey )
)
/s/ Melody C. Teppola Director )
- ------------------------ )
Melody C. Teppola )
)
/s/ Russell F. Tromley Director )
- ------------------------ )
Russell F. Tromley )
)
/s/ Benjamin R. Whiteley Director )
- ------------------------ )
Benjamin R. Whiteley )
)
Director )
- ------------------------ )
William R. Wiley )
)
/s/ Carlton Woodard Director )
- ------------------------ )
Carlton Woodard )
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