UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
[ X ] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended September 30, 1998
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
Commission File Number 2-35965
NORTH SHORE GAS COMPANY
(Exact name of registrant as specified in its charter)
Illinois 36-1558720
(State or other jurisdiction of (IRS Employer
incorporation or organization) Identification No.)
24th Floor, 130 East Randolph Drive, Chicago, Illinois 60601-6207
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code:(312)240-4000
Securities registered pursuant to Section 12(b) of the Act: None
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark whether the registrant (1) has filed all
reports required to be filed by Section 13 or 15(d) of the
Securities Exchange Act of 1934 during the preceding 12 months
(or for such shorter period that the registrant was required to
file such reports), and (2) has been subject to such filing
requirements for the past 90 days. Yes [ X ] No [ ]
Indicate by check mark if disclosure of delinquent filers
pursuant to Item 405 of Regulation S-K (Section229.405 of this chapter)
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 ]
State the aggregate market value of the voting stock held by non-
affiliates of the registrant:
None.
Indicate the number of shares outstanding of each of the issuer's
classes of common stock, as of the latest practicable date:
Common Stock, without par value, 3,625,887 shares
outstanding at October 31, 1998.
Documents Incorporated by Reference
None
CONTENTS
Page
Item No. No.
Part I
1. Business 3
2. Properties 7
3. Legal Proceedings 7
4. Submission of Matters to a Vote of Security Holders 7
Part II
5. Market for the Company's Common Stock and Related
Stockholder Matters 8
6. Selected Financial Data 9
7. Management's Discussion and Analysis of Results
of Operations and Financial Condition 10
7A. Quantitative and Qualitative Disclosure about
Market Risk 17
8. Financial Statements and Supplementary Data 17
9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure 34
Part III
10. Directors and Executive Officers of the Company 34
11. Executive Compensation 36
12. Security Ownership of Certain Beneficial Owners and
Management 41
13. Certain Relationships and Related Transactions 42
Part IV
14. Exhibits, Financial Statement Schedules, and Reports
on Form 8-K 43
Signatures 45
Exhibit Index 46
North Shore Gas Company
ANNUAL REPORT ON FORM 10-K
FISCAL YEAR ENDED SEPTEMBER 30, 1998
PART I
ITEM 1. BUSINESS
GENERAL
North Shore Gas Company (Company), an operating public
utility, is engaged primarily in the purchase, storage,
distribution, sale, and transportation of natural gas. It has
about 143,000 residential, commercial, and industrial retail sales
and transportation customers within its service area of
approximately 275 square miles, located in Northeastern Illinois.
It serves 54 communities and adjacent areas, including those
situated along Lake Michigan from Winnetka, Illinois, to the
Illinois-Wisconsin state line. This area, with an estimated
population of about 460,000, contains residential concentrations
and a diversity of industrial and commercial establishments, as
well as some farm lands. The Company had 246 employees at
September 30, 1998.
At September 30, l998, the common stock of the Company and of
its utility affiliate, The Peoples Gas Light and Coke Company
(Peoples Gas), was wholly owned by Peoples Energy Corporation
(Peoples Energy).
COMPETITION AND DEREGULATION
The Company holds certificates of public convenience and
necessity issued by the Illinois Commerce Commission (Commission)
for the conduct by the Company of its operations in the territory
that it serves. It holds a license agreement from Lake County,
Illinois, and, with minor exceptions, franchises from all of the
incorporated cities and villages in its service territory. The
franchises are of various terms and expiration dates and are
generally subject to various other conditions, restrictions, or
limitations not deemed materially burdensome.
Absent extraordinary circumstances, potential competitors are
barred from constructing competing gas distribution systems in the
Company's service territory by a judicial doctrine known as the
"first in the field" doctrine. In addition, the high cost of
installing duplicate distribution facilities would render the
construction of a competing system impractical.
Competition in varying degrees exists between natural gas and
other fuels or forms of energy available to consumers in the
Company's service area.
On December 16, 1997, the State of Illinois enacted legislation
to restructure the electric market in Illinois. Under the
legislation, approximately one-third of non-residential electric
customers, including customers with very large loads, will be able
to purchase electric power from the supplier of their choice
beginning on October 1, 1999. All non-residential customers will
have this choice by December 31, 2000. All residential customers
will be given the choice by May 1, 2002. Customers who buy their
electricity from a supplier other than the local electric utility
will be required to pay transition charges to the utility through
the year 2006. These charges are intended to compensate the
electric utilities for revenues lost because of customers buying
electricity from other suppliers. The legislation also allows an
electric utility to issue bonds, in aggregate amounts up to 50% of
its Illinois jurisdictional capitalization, to be financed by a
specific charge to its customers. An electric utility also may
transfer up to 15% of its assets to an affiliated or unaffiliated
entity without approval from the Commission. In return for these
and other benefits, electric utilities are required to reduce their
rates to residential customers. The state's two largest electric
utilities, including the utility that serves northeastern Illinois,
have reduced their residential rates by 15% on August 1, 1998 and
must reduce by another 5% on May 1, 2002. The legislation does
not require electric utilities to divest their power generation
assets. However, subject to certain capacity restrictions, electric
utilities can divest assets without Commission approval. It is too
early to determine what effects this restructuring of the electric
market will have on the competitive position of the Company.
In addition to restructuring the electric market, the
legislation provides for additional funding for assistance to low-
income energy users, including customers of the Company. The
legislation creates a fund, financed by charges to electric and gas
customers of public utilities and participating municipal utilities
and electric co-ops, which supplements currently available federal
energy assistance.
On October 26, 1998, the Company made a filing with the
Commission under which the price for natural gas would be set at a
fixed level for at least the next five years. Under the current
system, the Company makes purchases in the open, unregulated gas
market and passes those costs, as incurred, onto customers through
a monthly gas charge. While the Company makes no profit on the
gas, the market price and the price customers pay can fluctuate
significantly due to the effects of supply and demand. Under the
current system, the customer bears the full risk of the market.
The proposed fixed-price gas charge would protect the Company's
customers from the market fluctuations and from increases in gas
costs due to inflation and other market forces. The proposal
reflects a fixed gas price of 34.70 cents per therm for customers
of the Company. This fixed unit price is comparable to the average
price paid by the Company's customers over the last two years.
By eliminating the monthly price fluctuations, the Company could
shield customers from price increases, although gas bills would
still reflect customers' increased usage during colder weather. As
the Company would assume and manage this risk, it would have an
opportunity to earn a profit on this initiative.
The Commission has eight months to review the filing, during
which period, the Company may update its proposal. At the
conclusion of the review, the Commission may modify the proposal.
However, the Company has the right to accept the outcome or reject
it and continue under the current system.
A substantial portion of the gas that the Company delivers to
its customers consists of gas that the Company's customers purchase
directly from producers and marketers rather than from the Company.
These direct customer purchases have little effect on net income
because the Company provides transportation service for such gas
volumes and recovers margins similar to those applicable to
conventional gas sales.
A pipeline may seek to provide transportation service directly
to end-users. Such direct service by a pipeline to an end-user
would bypass the local distributor's service and reduce the
distributor's earnings. However, the Company's pipeline suppliers
have not undertaken any service bypassing the Company. The Company
has a bypass rate approved by the Commission which allows the
Company to renegotiate rates with customers that are potential
bypass candidates. (See Other Matters - Large Volume Gas Service
Agreements in Item 7.)
SALES AND RATES
The Company sells natural gas having an average heating value of
approximately 1,000 British thermal units (Btu's) per cubic foot.*
Sales are made and service rendered by the Company pursuant to a
rate schedule on file with the Commission containing various
service classifications largely reflecting customers'
* All volumes of natural gas set forth in this report are stated
on a 1,000 Btu (per cubic foot) billing basis.
(100 cubic feet = 1 therm; 10 therms = 1 Dekatherm - Dth)
different uses and levels of consumption. The Gas Charge is
determined in accordance with the provisions in Rider 2, Gas
Charge, to recover the costs incurred by the Company to purchase,
transport, manufacture, and store gas supplies. The level of the
Gas Charge under the Company's rate schedule is adjusted monthly to
reflect increases or decreases in natural gas supplier charges,
purchased storage service costs, transportation charges, and
liquefied petroleum gas costs. In addition, under the tariffs of
the Company, the difference for any month between costs recoverable
through the Gas Charge and the revenues billed to customers under
the Gas Charge is refunded to or recovered from customers.
Consistent with these tariff provisions, such difference for any
month is recorded either as a current liability or a current asset
(with a contra entry to Gas Costs). (See Note 1L of the Notes to
Consolidated Financial Statements.)
The business of the Company is influenced by seasonal weather
conditions because a large element of the Company's customer load
consists of space heating. Weather-related deliveries can,
therefore, have a significant positive or negative impact on net
income. (For discussion of the effect of the seasonal nature of
gas revenues on cash flow, see Liquidity in Item 7.)
The basic marketing plan of the Company is to maintain its
existing share in all market segments and develop opportunities
emerging from changes in the utility environment and technological
equipment advances for new, expanded, or current natural gas
applications, including cogeneration, prime movers, natural gas-
fueled vehicles, and natural gas air-conditioning.
STATE LEGISLATION AND REGULATION
The Company is subject to the jurisdiction of and regulation by
the Commission, which has general supervisory and regulatory powers
over practically all phases of the public utility business in
Illinois, including rates and charges, issuance of securities,
services and facilities, systems of accounts, investments, safety
standards, transactions with affiliated interests, as defined in
the Illinois Public Utilities Act, and other matters.
FEDERAL LEGISLATION AND REGULATION
By order entered on December 6, 1968 (Holding Company Act
Release No. 16233), the Securities and Exchange Commission,
pursuant to Section 3(a)(1) of the Public Utility Holding Company
Act of 1935 (Act), exempted Peoples Energy and its subsidiary
companies as such (including the Company) from the provisions of
the Act, other than Section 9(a)(2) thereof.
Most of the gas distributed by the Company is transported to the
Company's distribution system by interstate pipelines. In their
provision of gas services (gathering, transportation and storage
services, and gas supply) pipelines are regulated by the Federal
Energy Regulatory Commission (FERC) under the Natural Gas Act and
the Natural Gas Policy Act of 1978. (See "Sales and Rates" and
"Current Gas Supply" in Item 1.)
ENVIRONMENTAL MATTERS
The Company is subject to federal and state environmental laws.
The Company is conducting environmental investigations and work at
certain sites that are the location of former manufactured gas
plant operations. (See Note 2A of the Notes to Consolidated
Financial Statements.) In addition, the Company has received a
demand for payment of environmental response costs at a former
mineral processing site in Denver, Colorado. (See Note 2B of the
Notes to Consolidated Financial Statements.) Also, the Company was
informed by the Illinois Environmental Protection Agency (IEPA)
that it was not in compliance with certain provisions of the
Illinois Environmental Protection Act which prohibit water
pollution within the State of Illinois. (See Note 2C of the Notes
to Consolidated Financial Statements.)
CURRENT GAS SUPPLY
The Company has entered into various long-term and short-term
firm gas supply contracts. When used in conjunction with contract
storage and Company-owned peak-shaving facilities, such supply is
deemed sufficient to meet current and foreseeable peak and annual
market requirements.
Although the Company believes North American supply to be
sufficient to meet U.S. market demands for the foreseeable future,
it is unable to quantify or otherwise make specific representations
regarding national supply availability.
The following tabulation shows the Company's expected design
peak-day availability of gas in thousands of dekatherms (MDth)
during the 1998-1999 heating season:
Design Peak-Day Year of
Availability Contract
Source (MDth) Expiration
Firm direct purchases (1) 132 1999-2001
Liquefied petroleum gas (2) 40
Storage gas:
Leased (3) 125 1999-2000
Peoples-Manlove (4) 63 (5)
Customer-owned gas (6) 55
Total expected design
peak-day availability 415
(1)Consists of firm gas purchases from non-pipeline suppliers
delivered utilizing firm pipeline transportation. The majority
of the gas purchase contracts are negotiated annually. The
terms of the transportation contracts vary, with the longest
term being 10 years.
(2)Reflects derating of capacity, as accepted by the Commission
Staff in Docket 91-0581.
(3)Consists of leased storage services required to meet design day
requirements with a contract length of 2 years.
(4)Manlove Field, Peoples Gas' underground storage facility
located near Champaign, Illinois, has a seasonal top-gas
capacity (excluding volumes required to support late-season
peaking requirements) of approximately 27,000 MDth, of which
approximately 1,566 MDth is dedicated to the Company. For the
1998-99 heating season, the Company has a contract for a
maximum daily deliverability of 63 MDth.
(5)The contract with Peoples Gas was for an initial term expiring
May 1, 1990. However, by its terms, the contract continues in
effect unless canceled by either party upon 120 days notice
prior to April 30 of any year thereafter.
(6)Consists of gas supplies purchased directly from producers and
marketers by the Company's commercial, industrial, and larger
residential customers.
The sources of gas supply (including gas transported for
customers) in MDth for the Company for the three fiscal years ended
September 30, 1998, 1997, and 1996, were as follows:
1998 1997 1996
Gas purchases 21,837 27,226 27,940
Liquefied petroleum gas produced 3 20 151
Customer-owned gas-received 12,355 12,618 12,777
Underground storage-net 28 (123) 468
Exchange gas-net 1,030 (151) (104)
Company use, franchise requirements,
and unaccounted-for gas (383) (546) (983)
Total (a) 34,870 39,044 40,249
(a) See "Gas Sold and Transported" in Item 6.
ITEM 2. PROPERTIES
All of the principal plants and properties of the Company have
been maintained in the ordinary course of business and are believed
to be in satisfactory operating condition. The following is a
brief description of the principal plants and operating units of
the Company.
The distribution system of the Company, at September 30, 1998,
consisted of approximately 2,100 miles of distribution mains and
necessary pressure regulators, approximately 129,000 services (pipe
connecting the mains with piping on the customers' premises), and
approximately 146,000 meters installed on customers' premises.
Also, the Company's transmission system consists of approximately
15 miles of transmission pipeline. In addition, the Company has
liquefied petroleum gasification and storage facilities. It also
owns and has a substantial investment in office and service
buildings, garages, repair shops, and motor vehicles, together with
the equipment, tools, and fixtures necessary to conduct utility
business.
Most of the principal plants and properties of the Company,
other than mains, services, meters, regulators, and cushion gas in
underground storage, are located on property owned in fee.
Substantially all gas mains are located in public streets, alleys,
and highways, or under property owned by others under grants of
easements. Meters and house regulators in use and a portion of
services are located on premises being served.
Substantially all of the physical properties now owned or
hereafter acquired by the Company are subject to (a) the first-
mortgage lien of the Company's mortgage to U.S. Bank Trust,
National Association, as Trustee, to secure the principal amount of
the Company's outstanding first mortgage bonds and (b) in certain
cases, other exceptions and defects that do not interfere with the
use of the property.
ITEM 3. LEGAL PROCEEDINGS
See Note 2 of the Notes to Consolidated Financial Statements.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
PART II
ITEM 5. MARKET FOR THE COMPANY'S COMMON STOCK AND RELATED
STOCKHOLDER MATTERS
The Company is a wholly owned subsidiary of Peoples Energy.
ITEM 6. SELECTED FINANCIAL DATA (a)
<TABLE>
For fiscal years ended September 30, 1998 1997 1996 1995 1994
OPERATING RESULTS (thousands)
<S> <C> <C> <C> <C> <C>
Operating Revenues:
Residential $111,377 $129,335 $125,502 $104,034 $130,654
Commercial 16,405 19,385 18,769 14,677 21,834
Industrial 3,715 4,360 4,299 3,321 6,392
Transportation (b) 11,796 14,800 14,212 13,188 11,185
Other 913 995 1,027 1,309 1,060
Total Operating Revenues 144,206 168,875 163,809 136,529 171,125
Less- Gas costs 73,043 92,307 86,304 72,815 105,042
- Revenue taxes 9,122 10,794 10,751 9,158 10,962
- Other 1,067 - - - -
Net Operating Revenues $ 60,974 $ 65,774 $ 66,754 $ 54,556 $ 55,121
Net Income applicable to common stock $ 12,986 $ 14,814 $ 16,347 $ 9,048 $ 10,378
Dividends declared on common stock $ 10,878 $ 13,525 $ 11,748 $ 5,947 $ 7,107
ASSETS AT YEAR-END (thousands)
Property, plant and equipment $304,487 $295,631 $284,896 $272,869 $259,375
Less - Accumulated depreciation 107,590 100,957 93,821 86,950 80,639
Net Property, Plant and Equipment $196,897 $194,674 $191,075 $185,919 $178,736
Total assets $251,263 $230,694 $237,500 $234,633 $234,364
Capital expenditures - construction $ 10,841 $ 12,003 $ 13,286 $ 14,901 $ 12,595
CAPITALIZATION AT YEAR-END (thousands)
Common equity $ 94,777 $ 92,669 $ 91,380 $ 86,781 $ 83,680
Long-term debt 64,604 64,604 64,664 72,724 76,925
Total Capitalization $159,381 $157,273 $156,044 $159,505 $160,605
CAPITALIZATION AT YEAR-END (percent)
Common equity 59 59 59 54 52
Long-term debt 41 41 41 46 48
Total Capitalization 100 100 100 100 100
GAS SOLD AND TRANSPORTED (MDth)
Gas Sales:
Residential 18,739 21,578 22,789 19,062 20,228
Commercial 2,993 3,531 3,698 2,873 3,641
Industrial 755 846 930 702 1,005
Transportation (b) 12,383 13,089 12,832 12,468 11,964
Total Gas Sales and Transportation 34,870 39,044 40,249 35,105 36,838
Margin per Dth delivered $ 1.75 $ 1.68 $ 1.66 $ 1.55 $ 1.50
NUMBER OF CUSTOMERS (average)
Residential 132,057 129,488 126,454 122,591 119,190
Commercial 8,250 8,164 7,831 7,674 7,656
Industrial 898 892 857 820 802
Transportation (b) 1,865 1,659 1,677 1,626 1,479
Total Customers 143,070 140,203 136,819 132,711 129,127
DEGREE DAYS 5,564 6,806 7,080 5,897 6,701
Percent of normal (6,536) 85 104 108 90 103
(a) The Company is a wholly owned subsidiary of Peoples Energy;
therefore, per-share data are omitted.
(b) Includes commercial, industrial, and larger residential customers.
</TABLE>
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS
AND FINANCIAL CONDITION
RESULTS OF OPERATIONS
Net Income
In 1998, net income decreased $1.8 million, to $13.0 million,
principally a result of weather that was 18 percent warmer than the
prior year. Increases in labor costs and depreciation expense also
contributed to the decline in net income. These effects were
offset in part, by a decrease in pension expense (see Note 4A of
the Notes to Consolidated Financial Statements) and a decline in
the costs associated with outside professional services.
In 1997, net income applicable to common stock decreased $1.5
million, to $14.8 million, primarily a result of the prior period's
gain on the expiration of gas storage contracts. Also hindering
fiscal 1997's comparative results were decreased gas deliveries
due to weather that was four percent warmer than the previous
fiscal year and conservation, increased computer support services
associated with the implementation of the new customer information
system and increased depreciation expense. Partially offsetting
these effects were a decrease in pension expense, a full year's
effect of the Company's November 1995 rate increase and decreased
net interest expense.
A summary of variations affecting income between years is
presented below, with explanations of significant differences
following:
Fiscal 1998 Fiscal 1997
over 1997 over 1996
Amount Amount
(000's) Percent (000's) Percent
Net operating revenues (a) $(4,800) (7.3) $ (980) (1.5)
Operation and maintenance expenses (2,235) (8.3) (2,064) (7.1)
Depreciation expense 190 2.4 234 3.1
Income taxes (1,079) (11.9) 642 7.6
Other income and deductions (79) (1.6) (1,755) (56.6)
Net income applicable to common stock (1,828) (12.3) (1,533) (9.4)
(a) See Management's Discussion and Analysis of Results of Operations and
Financial Condition - Net Operating Revenues.
Net Operating Revenues
Gross revenues of the Company are affected by changes in the
unit cost of the Company's gas purchases and do not include the
cost of gas supplies for customers who purchase gas directly from
producers and marketers rather than from the Company. The direct
customer purchases have little effect on net income because the
Company provides transportation service for such gas volumes and
recovers margins similar to those applicable to conventional gas
sales. Except for the effect of customer conservation that may
result from substantial increases in the commodity cost of gas
supplies, changes in the unit cost of gas do not significantly
affect net income because the Company's tariffs provide for dollar-
for-dollar recovery of gas costs. (See Note 1L of the Notes to
Consolidated Financial Statements.) The Company's tariffs also
provide for dollar-for-dollar recovery of the cost of revenue taxes
and certain customer charges imposed by the state and various
municipalities.
Since income is not significantly affected by changes in revenue
from customers' gas purchases from producers or marketers rather
than from the Company, changes in gas costs (except for the effect
of customer conservation that may result from substantial increases
in the commodity cost of gas supplies), or changes in
revenue taxes and certain customer charges imposed by the state and
various municipalities, the following discussion pertains to "net
operating revenues" (operating revenues, net of gas costs, revenue
taxes and certain customer charges). The Company considers net
operating revenues to be a more pertinent measure of operating
results than gross revenues.
In 1998, net operating revenues decreased $4.8 million, to $61.0
million. Natural gas deliveries decreased 4.2 bcf, to 34.9 bcf,
due mainly to the effect of El Nino which caused weather to be 18
percent warmer than 1997 and 15 percent warmer than normal.
In 1997, net operating revenues decreased $980,000 to $65.8
million. Natural gas deliveries decreased 1.2 bcf, to 39.0 bcf,
due to weather that was four percent warmer than in 1996 and
conservation. Net operating revenues decreased approximately $1.1
million ($664,000 after income taxes) as a result of warmer weather
and conservation. However, a full year's effect of the Company's
rate increase improved net operating revenues by approximately
$520,000 ($314,000 after income taxes).
See Other Matters - Operating Statistics for details of selected
financial and operating information by gas service classification.
Operation and Maintenance Expenses
Operation and maintenance expenses decreased $2.2 million, to
$24.8 million, in 1998, due principally to reductions in pension
costs ($611,000), environmental costs recovered through rates
($589,000) and in a variety of other non-labor expenses. These
effects were offset, in part, by increased labor costs ($347,000).
In 1997, operation and maintenance expenses decreased $2.1
million, to $27.1 million, due chiefly to an $814,000 decrease in
pension expense caused by changes in settlement accounting
attributed to employees choosing early retirement and actuarial
assumptions (see Note 4A of the Notes to Consolidated Financial
Statements), reductions in costs associated with liability
insurance premiums and claim settlements ($674,000), and lower
reengineering expenses ($433,000).
Depreciation Expense
Depreciation expense increased $190,000, to $8.1 million, and
$234,000, to $7.9 million, in 1998 and 1997, respectively, due
largely to depreciable property additions.
Income Taxes
Income taxes, exclusive of the $157,000 included in other income
and deductions, decreased $1.1 million, in 1998, due primarily to
lower pre-tax income.
In 1997, income taxes, exclusive of the $183,000 included in
other income and deductions, increased $642,000, to $9.0 million,
due mainly to higher pre-tax income.
Other Income and Deductions
In 1998 other income and deductions increased $79,000, from the
prior period due to higher other interest expense and lower other
income.
In 1997, other income and deductions increased $1.8 million from
the prior year, due chiefly to the prior period's gain associated
with the expiration of natural gas storage contracts. Partially
offsetting this increase were reductions in interest expense on
long-term debt, resulting from the Company's early redemption of
first mortgage bonds, and other interest expense.
Other Matters
Effect of Weather. Weather variations affect the volumes of gas
delivered for heating purposes and, therefore, can have a
significant positive or negative impact on net income, cash
position, and coverage ratios.
Accounting Standards. The Company adopted Statement of Position
(SOP) 96-1, "Environmental Remediation Liabilities," in fiscal
1998. (See Note 1N of the Notes to the Consolidated Financial
Statements.)
Large-Volume Gas Service Agreements. The Company has entered into
gas service contracts with certain large-volume customers under a
specific rate schedule approved by the Commission. These contracts
were negotiated to overcome the potential threat of bypassing the
utility's distribution system. The impact on the net income of the
Company as a result of these contracts is not material.
Fixed Gas Charge Filing. On October 26, 1998, the Company made a
filing with the Commission under which the price for natural gas
would be set at a fixed level for at least the next five years. By
eliminating the monthly price fluctuations, the Company could
shield customers from price increases, although gas bills would
still reflect customers' increased usage during colder weather. As
the Company would assume and manage this risk, it would have an
opportunity to earn a profit on this initiative. (See Competition
and Deregulation in Item 1.)
Operating Statistics. The following table represents gas
distribution margin components:
For fiscal years ended September 30, 1998 1997 1996
Operating Revenues (thousands):
Gas sales
Residential $111,377 $129,335 $125,502
Commercial 16,405 19,385 18,769
Industrial 3,715 4,360 4,299
131,497 153,080 148,570
Transportation
Residential 1,282 2,782 1,852
Commercial 5,829 5,016 6,307
Industrial 4,179 5,128 5,683
Contract Pooling 506 1,874 370
11,796 14,800 14,212
Other 913 995 1,027
Total Operating Revenues 144,206 168,875 163,809
Less- Gas Costs 73,043 92,307 86,304
- Revenue Taxes 9,122 10,794 10,751
- Other 1,067 - -
Net Operating Revenues $ 60,974 $ 65,774 $ 66,754
Deliveries (MDth):
Gas Sales
Residential 18,739 21,578 22,789
Commercial 2,993 3,531 3,698
Industrial 755 846 930
22,487 25,955 27,417
Transportation (a)
Residential 638 2,756 1,415
Commercial 5,635 3,936 5,145
Industrial 6,110 6,397 6,272
12,383 13,089 12,832
Total Gas Sales and Transportation 34,870 39,044 40,249
Margin per Dth delivered $ 1.75 $ 1.68 $ 1.66
(a) Volumes associated with contract pooling service are included
in the respective customer classes.
LIQUIDITY
Source of Funds. The Company has access to outside capital markets
and to internal sources of funds that together provide sufficient
resources to meet capital requirements. It does not anticipate any
changes that would materially alter its current liquidity position.
Due to the seasonal nature of gas usage, a major portion of cash
collections occurs between December and May. Because of timing
differences in the receipt and disbursement of cash and the level
of construction requirements, the Company may borrow on a short-
term basis. Short-term borrowings are repaid with cash from
operations, other short-term borrowings, or refinanced on a
permanent basis with debt or equity, depending on capital market
conditions and capital structure considerations.
Credit Lines. Peoples Gas has lines of credit of $129.4 million of
which the Company may borrow up to $30 million. At
September 30, 1998, Peoples Gas and the Company had unused credit
available from banks of $120.4 million. (See Note 9 of the Notes
to Consolidated Financial Statements.)
Cash Flow Activities. Net cash provided by operating activities
increased $8.1 million in 1998, primarily due to changes in other
deferred credits and payables. These effects were partially offset
by changes in other assets. In 1997, net cash provided by
operating activities decreased by $7.6 million, due chiefly to
changes in accounts payable and gas in storage. Partially
offsetting these items were increases in net receivables and other
assets. In 1996, net cash provided by operating activities
increased $4.8 million, due primarily to changes resulting from
increased net income, due mainly to colder weather and the rate
increase, and from accounts payable, partially offset by other
assets and gas sales revenue refundable.
Net cash used in investing activities for 1998, 1997, and 1996
mainly represents the level of capital expenditures in the
respective years.
Net cash used in financing activities for 1998 and 1997
primarily reflects dividends paid on common stock. In 1996, net
cash used in financing activities reflects the redemption of
previously issued debt and higher dividends paid on common stock
due to the increase in net income.
Indenture Restrictions. The Company's indenture relating to its
first mortgage bonds contains provisions and covenants restricting
the payment of cash dividends and the purchase or redemption of
capital stock. At September 30, 1998, such restrictions amounted
to $11.6 million out of total retained earnings of $70.0 million.
(See Note 3 of the Notes to Consolidated Financial Statements.)
Interest Coverage. The fixed charges coverage ratios for the
Company for fiscal 1998, 1997, and 1996 were 5.07, 5.74, and 5.62,
respectively. The decrease for fiscal 1998 is due to lower pre-tax
income resulting from warmer weather. The increase for fiscal year
1997 is due to lower interest expense on bank loans, amounts
refundable to customers and long-term debt. The ratio for fiscal
year 1996 reflects the redemption of long-term debt and higher
pre-tax income resulting from colder weather and the Commission
approved rate increase. (See Results of Operations - Net Income.)
Debt Ratings. The long-term debt of the Company is rated Aa2 by
Moody's Investors Service and AA- by Standard & Poor's Corporation.
Moody's upgraded its rating from Aa3 in November 1997. Standard &
Poor's Corporation last changed its rating in 1985. The commercial
paper of the Company has the top rating from the major rating
agencies.
Environmental Matters. The Company is conducting environmental
investigations and work at certain sites that were the location of
former manufactured gas operations. (See Note 2A of the Notes to
Consolidated Financial Statements.)
In 1994, the Company received a demand from a responsible party
under the Comprehensive Environmental Response, Compensation and
Liability Act of 1980, as amended (CERCLA), for reimbursement,
indemnification and contribution for response costs incurred at a
former mineral processing site in Denver, Colorado. The Company
filed a declaratory judgment action in the District Court for the
Northern District of Illinois asking the court to declare
that the Company is not liable for response costs relating to the
site. The defendant filed a counterclaim for costs incurred by the
defendant with respect to the site. In 1997, the District Court
granted the Company's motion for summary judgement, declaring that
the Company is not liable for any response costs in connection with
the Denver site. On August 5, 1998, the U.S. Court of Appeals,
Seventh Circuit, reversed the District Court's decision and
remanded the case for determination of what liability, if any, the
former entity has and therefore the Company has for activities at
the site. (See Note 2B of the Notes to Consolidated Financial
Statements.)
On November 14, 1995, the Illinois Attorney General filed a
complaint in the Circuit Court of Cook County naming the Company
and four other parties as defendants. The complaint alleges
violations of certain provisions of the Illinois Environmental
Protection Act which prohibit water pollution within the Sate
of Illinois. The complaint alleges that the violations are the
result of a gasoline release that occurred in Wheeling, Illinois,
in June 1992 when a contractor who was installing a pipeline for
the Company accidentally struck a gasoline pipeline owned by West
Shore Pipeline Company. The Company is contesting this suit.
(See Note 2C of the Notes to Consolidated Financial Statements.)
Year 2000. The Company obtains its information technology services
from or through Peoples Gas. The Company began its efforts to
assess the Year 2000 compliance of its mainframe computer systems
in March 1996. The Company has since developed a comprehensive
Year 2000 readiness plan that incorporates all of the information
technology systems, including computer hardware and software, and
its embedded systems equipment, including telecommunications
equipment used by the Company. The plan also includes a review of
the Year 2000 compliance efforts of its key suppliers and customers
and Year 2000 contingency planning.
For all internal information technology systems developed for
the Company by Peoples Gas, Year 2000 compliance efforts proceed
through the following phases: inventory, assessment, remediation,
testing, and implementation. Rather than completing each phase for
all systems prior to proceeding to the next phase, the Company
progresses through all phases on a system-by-system basis,
gradually implementing each fully-compliant system.
The Year 2000 compliance phases utilize a combination of
consultants and employees of Peoples Gas. Once a fully-tested
application has been implemented, Peoples Gas employees follow
established procedures to maintain the compliance of the
implemented systems. Peoples Gas also has retained a quality
assurance expert to ensure that any subsequent modifications to the
application do not impact its compliant status.
As of September 30, 1998, 18 of the Company's 37 mainframe
applications have been fully remediated, tested and implemented,
two are in the testing phase, and nine have been (or are in the
process of being) eliminated. The eight remaining mainframe
applications are scheduled to be replaced by the Company's new
mainframe customer information system and are not expected to be
remediated. Additionally, 36 mainframe system modules have been
remediated and are now in the testing phase. Many of the non-
mainframe applications, spreadsheets and interfaces used by the
Company have also reached the implementation stage; and most others
are in the remediation phase. The Company expects to implement all
critical internal systems (other than the customer information
system to be used by Peoples Gas and the Company) by no later than
March 31, 1999; complete implementation of all non-critical
internal systems by April 30, 1999; and complete installation and
testing of the customer information system by the end of fiscal
year 1999.
As part of its Year 2000 Project, the Company has also contacted
the vendors of its licensed or purchased hardware and software to
determine the Year 2000 compliance status of their products. As of
September 30, 1998, the Company has received responses from 85% of
the vendors and is in the process of replacing, upgrading or
eliminating non-compliant vendor products as appropriate. The
Company also plans to have certain products, such as its desktop
computer inventory, compliant-tested in order to minimize the risks
associated with reliance on vendor representations.
The Company is in the process of determining whether its
embedded systems equipment is Year 2000 compliant. It has
completed an inventory of all equipment containing embedded
systems, including telecommunications equipment and facilities.
The Company has also contracted with a consultant that has
significant utility and engineering expertise to assist with the
embedded systems efforts. The Company is currently in the process
of determining the Year 2000 compliance status of the inventory and
expects to complete this assessment by January 1999. During the
assessment phase, the Company will also begin testing, repairing or
replacing any critical equipment identified as not Year 2000
compliant. Its timetable for implementing compliant equipment will
depend on the availability of compliant equipment.
The Company currently has a written conceptual contingency plan
to address risks to it created by its or third parties' systems and
embedded technology that are not Year 2000 compliant. It has
engaged the consultant referenced above to assist in developing
detailed and comprehensive business continuity and contingency
plans to address possible failures in the area of embedded systems
equipment. These plans are scheduled to be completed by December
1998. The Company also plans to further develop its contingency
plans with respect to information technology-related failures and
critical supplier failures.
The Company has contacted its key suppliers to determine their
Year 2000 compliance efforts. It has received written assurances
from many key suppliers that they are making the necessary Year
2000 efforts, and it is in the process of following up with other
key suppliers that did not respond to written inquiries.
Essential elements of the business of the Company are dependent
on certain key third parties (for example, pipeline suppliers,
banks, electric utilities and telecommunication companies). A
material failure by any such key third party could significantly
disrupt the Company's business. Peoples Gas is in the process of
detailing and finalizing contingency plans to address potential
disruptions that may be caused by third parties.
Peoples Gas currently estimates that it will incur expenses of
approximately $1.6 million through fiscal year 1999 to complete its
Year 2000 compliance efforts, in addition to the $4.0 million
already incurred through September 30, 1998 and an appropriate
portion of these expenses has been and/or will be billed to the
Company. This estimate does not include costs to repair or replace
critical embedded systems equipment that is non-compliant, which
has yet to be determined. Management does not expect the cost of
its' Year 2000 compliance efforts to have a material adverse impact
on the financial position or results of operations of Peoples Gas
or the Company.
Market Risk Management. The Company utilizes long-term debt as a
primary source of capital. While both fixed and variable rate debt
maybe utilized by the Company, all of the Company's existing
long-term debt instruments carry a fixed rate of interest,
subject to certain restrictions on optional redemptions, the
fixed rate debt instruments can be refinanced at lower interest
rates if the Company deems it to be economical. (See Note 10 of
the notes to Consolidated Financial Statements.)
CAPITAL RESOURCES
Capital Spending. Capital expenditures for additions,
replacements, and improvements to the utility plant were $10.8
million in 1998, $12.0 million in 1997, and $13.3 million in 1996.
In fiscal 1998 and 1997 expenditures decreased $1.2 and $1.3
million, respectively, from prior years. Both years reflect the
Company's commitment to its cost containment program.
While capital expenditures for fiscal 1999 are estimated to be
$15.2 million, an increase of $4.4 million from 1998, the 1999
amount reflects a level that is consistent with the financial goals
and needs of the Company.
There are no sinking fund requirements for long-term debt due in
fiscal 1999. (See Note 10A of the Notes to Consolidated Financial
Statements.)
The Company anticipates that future cash needs for capital
expenditures and sinking fund requirements and maturities will be
met through internally generated funds, intercompany loans from
Peoples Energy, borrowing arrangements with banks and/or the
issuance of commercial paper on an interim basis, and periodic long-
term financing involving first mortgage bonds or equity from
Peoples Energy.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK
Quantitative and Qualitative Disclosure about Market Risk is reported
under "Management's Discussion and Analysis of Financial Condition
and Results of Operations - Market Risk Management."
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Page
Statement of Management's Responsibility 17
Report of Independent Public Accountants 18
Consolidated Statements of Income for fiscal years ended
September 30, 1998, 1997, and 1996 19
Consolidated Statements of Retained Earnings for fiscal
years ended September 30, 1998, 1997, and 1996 19
Consolidated Balance Sheets at September 30, 1998 and 1997 20
Consolidated Capitalization Statements at September 30, 1998
and 1997 21
Consolidated Statements of Cash Flows for fiscal years ended
September 30, 1998, 1997, and 1996 22
Notes to Consolidated Financial Statements 23
STATEMENT OF MANAGEMENT'S RESPONSIBILITY
The financial statements and other financial information
included in this report were prepared by management, who is
responsible for the integrity and objectivity of the presented
data. The consolidated financial statements of the Company and its
subsidiaries were prepared in conformity with generally accepted
accounting principles and necessarily include some amounts that are
based on the best estimates and judgments of management.
The Company maintains internal accounting systems and related
administrative controls, along with internal audit programs, that
are designed to provide reasonable assurance that the accounting
records are accurate and assets are safeguarded from loss or
unauthorized use. Consequently, management believes that the
accounting records and controls are adequate to produce reliable
financial statements.
Arthur Andersen LLP, the Company's independent public
accountants approved by Peoples Energy's shareholders, as a part of
its audit of the financial statements, selectively reviews and
tests certain aspects of internal accounting controls solely to
determine the nature, timing, and extent of audit tests.
Management has made available to Arthur Andersen LLP all of the
Company's financial records and related data and believes that all
representations made to the independent public accountants during
its audit were valid and appropriate.
The Audit Committee of the Board of Directors of Peoples Energy,
comprised of five outside directors, meets periodically with
management, the internal auditors, and Arthur Andersen LLP, jointly
and separately, to assure that appropriate responsibilities are
discharged. These meetings include discussion and review of
accounting principles and practices, internal accounting controls,
audit results, and the presentation of financial information in the
annual report of Peoples Energy.
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To North Shore Gas Company:
We have audited the accompanying consolidated balance sheets
and consolidated capitalization statements of North Shore Gas
Company (an Illinois corporation, hereinafter referred to as the
Company and a wholly owned subsidiary of Peoples Energy
Corporation) and subsidiary companies at September 30, 1998 and
1997, and the related consolidated statements of income, retained
earnings, and cash flows for each of the three years in the period
ended September 30, 1998. These financial statements and the
schedule referred to below are the responsibility of the Company's
management. Our responsibility is to express an opinion on these
financial statements and schedule 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, the financial statements referred to above
present fairly, in all material respects, the financial position of
the Company and subsidiary companies at September 30, 1998 and
1997, and the results of their operations and cash flows for each
of the three years in the period ended September 30, 1998, in
conformity with generally accepted accounting principles.
Our audits were made for the purpose of forming an opinion on
the basic financial statements taken as a whole. The financial
statement schedule listed in Item 14(a)2 is presented for purposes
of complying with the Securities and Exchange Commission's rules
and is not part of the basic financial statements. The financial
statement schedule has been subjected to the auditing procedures
applied in the audit of the basic financial statements and, in our
opinion, fairly states, in all material respects, the financial
data required to be set forth therein in relation to the basic
financial statements taken as a whole.
ARTHUR ANDERSEN LLP
Chicago, Illinois
October 30, 1998
CONSOLIDATED STATEMENTS OF INCOME
North Shore Gas Company
For fiscal years ended September 30, 1998 1997 1996
(Thousands)
Operating Revenues:
Gas sales $131,497 $153,080 $148,570
Transportation 11,796 14,800 14,212
Other 913 995 1,027
Total Operating Revenues 144,206 168,875 163,809
Operating Expenses:
Gas costs 73,043 92,307 86,304
Operation 21,949 24,131 25,893
Maintenance 2,880 2,933 3,235
Depreciation 8,053 7,863 7,629
Taxes- Income 7,967 9,046 8,404
- State and local revenue 9,122 10,794 10,751
- Other 3,273 2,133 2,147
Total Operating Expenses 126,287 149,207 144,363
Operating Income 17,919 19,668 19,446
Other Income and (Deductions):
Interest income 376 447 414
Interest on long-term debt (4,625) (4,627) (4,937)
Other interest expense (565) (441) (804)
Income taxes (157) (183) (1,750)
Miscellaneous - net (see Note 7) 38 (50) 3,978
Total Other Income and Deductions (4,933) (4,854) (3,099)
Net Income Applicable to Common Stock $ 12,986 $ 14,814 $ 16,347
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
North Shore Gas Company
For fiscal years ended September 30, 1998 1997 1996
(Thousands)
Balance at Beginning of Year $67,912 $66,623 $62,024
Add - Net Income 12,986 14,814 16,347
Deduct- Dividends declared on common stock 10,878 13,525 11,748
Balance at End of Year $70,020 $67,912 $66,623
The Notes to Consolidated Financial Statements are an integral part of
these statements.
<TABLE>
CONSOLIDATED BALANCE SHEETS
North Shore Gas Company
At September 30, 1998 1997
(Thousands)
Assets
Capital Investments:
<S> <C> <C>
Property, plant and equipment, at original cost $304,487 $295,631
Less - Accumulated depreciation 107,590 100,957
Net property, plant and equipment 196,897 194,674
Other investments 22 21
Total Capital Investments - Net 196,919 194,695
Current Assets:
Cash and cash equivalents 4,666 344
Receivables -
Customers, net of allowance for uncollectible
accounts of $705 and $898, respectively 3,811 4,960
Other 828 1,707
Accrued unbilled revenues 2,629 2,634
Materials and supplies, at average cost 2,729 2,976
Gas in storage, at last-in, first-out cost 9,917 10,003
Gas costs recoverable through rate adjustments 614 1,836
Regulatory assets (see Note 1H) 1,208 2,320
Prepayments 317 246
Total Current Assets 26,719 27,026
Other Assets:
Non-current regulatory assets (see Note 1H) 23,895 6,204
Deferred charges 3,730 2,769
Total Other Assets 27,625 8,973
Total Assets $251,263 $230,694
Capitalization and Liabilities
Capitalization (see Consolidated Capitalization Statements) $159,381 $157,273
Current Liabilities:
Interim loans - 2,110
Accounts payable 22,953 18,884
Dividends payable on common stock 2,429 5,511
Customer gas service and credit deposits 5,705 5,634
Accrued taxes 1,305 1,952
Gas sales revenue refundable through rate adjustments 1,163 411
Accrued interest 2,034 2,037
Total Current Liabilities 35,589 36,539
Deferred Credits and Other Liabilities:
Deferred income taxes - primarily accelerated depreciation (see Note 5C) 23,052 20,416
Investment tax credits being amortized over
the average lives of related property 3,437 3,592
Other 29,804 12,874
Total Deferred Credits and Other Liabilities 56,293 36,882
Total Capitalization and Liabilities $251,263 $230,694
The Notes to Consolidated Financial Statements are an integral
part of these statements.
</TABLE>
CONSOLIDATED CAPITALIZATION STATEMENTS
North Shore Gas Company
At September 30, 1998 1997
(Thousands, except number of shares)
Common Stockholder's Equity:
Common stock, without par value -
Authorized 5,000,000 shares
Outstanding 3,625,887 shares $ 24,757 $ 24,757
Retained earnings (see Consolidated Statements
of Retained Earnings) 70,020 67,912
Total Common Stockholder's Equity 94,777 92,669
Long-Term Debt:
Exclusive of sinking fund payments and maturities
due within one year
First and Refunding Mortgage Bonds -
8% Series J, due November 1, 2020 24,699 24,699
6-3/8% Series K, due October 1, 2022 24,905 24,905
6.37% Series L, due May 1, 2003 15,000 15,000
Total Long-Term Debt 64,604 64,604
Total Capitalization $159,381 $157,273
The Notes to Consolidated Financial Statements are an integral part of these
statements.
<TABLE>
<CAPTION>
CONSOLIDATED STATEMENTS OF CASH FLOWS
North Shore Gas Company
For fiscal years ended September 30, 1998 1997 1996
(Thousands)
Operating Activities:
<S> <C> <C> <C>
Net Income $12,986 $14,814 $16,347
Adjustments to reconcile net income to net cash:
Depreciation 8,053 7,863 7,629
Deferred income taxes and investment tax credits - net 1,691 126 (425)
Change in other deferred credits and other liabilities 17,719 319 1,168
Change in deferred charges (18,652) 2,081 (1,670)
Other - - 11
Change in current assets and liabilities:
Receivables - net 2,028 2,277 (3,776)
Accrued unbilled revenues 5 1,146 (1,064)
Materials and supplies 247 (867) 89
Gas in storage 86 (376) 8,769
Gas costs recoverable 1,222 664 1,573
Regulatory assets 1,112 5,217 (4,295)
Payables 4,069 (8,045) 12,640
Customer gas service and credit deposits 71 365 (295)
Accrued taxes (647) (345) 1,028
Gas sales revenue refundable 752 (2,778) (7,756)
Accrued interest (3) - 266
Prepayments (71) 125 (24)
Net Cash Provided by Operating Activities 30,668 22,586 30,215
Investing Activities:
Capital expenditures - construction (10,841) (12,003) (13,286)
Other assets 566 633 482
Other capital investments (1) (1) -
Net Cash Used in Investing Activities (10,276) (11,371) (12,804)
Financing Activities:
Interim loans - net (2,110) 185 1,925
Retirement of long-term debt - (60) (12,060)
Dividends paid on common stock (13,960) (11,385) (9,971)
Net Cash Used in Financing Activities (16,070) (11,260) (20,106)
Net Increase (Decrease) in Cash and Cash Equivalents 4,322 (45) (2,695)
Cash and Cash Equivalents at Beginning of Year 344 389 3,084
Cash and Cash Equivalents at End of Year $ 4,666 $ 344 $ 389
The Notes to Consolidated Financial Statements are an integral part of
these statements.
</TABLE>
North Shore Gas Company
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
1A Principles of Consolidation
All subsidiaries are included in the consolidated financial
statements. All significant intercompany transactions have been
eliminated in consolidation. Certain items previously reported for
years prior to 1998 have been reclassified to conform with the
current-year presentation.
1B Use of Estimates
The preparation of financial statements in conformity with
generally accepted accounting principles requires management to
make estimates and assumptions that affect the reported amounts of
assets and liabilities and disclosure of contingent liabilities at
the date of the financial statements and the reported amounts of
revenues and expenses during the reporting period. Actual results
could differ from those estimates.
1C Concentration of Credit Risk
The Company provides natural gas service to about 143,000
customers within approximately 275 square miles in Northeastern
Illinois. Credit risk for the Company is spread over a diversified
base of residential, commercial, and industrial customers.
The Company encourages customers to participate in its long-
standing budget payment program that allows the cost of higher gas
consumption levels associated with the heating season to be spread
over a 12-month billing cycle. Customers' payment records are
continually monitored and credit deposits are required, when
appropriate, to minimize uncollectible write-offs.
1D Revenue Recognition
Gas sales and transportation revenues are recorded on the accrual
basis for all gas delivered during the month, including an estimate
for gas delivered but unbilled at the end of each month.
1E Property, Plant and Equipment
Property, plant and equipment is stated at original cost and
includes appropriate amounts of capitalized labor costs, payroll
taxes, employee benefit costs, administrative costs, and an
allowance for funds used during construction.
1F Accounts Payable
The Company utilizes controlled disbursement banking arrangements
under which certain bank accounts have negative book balances due
to checks in transit. The negative balances are classified as
Accounts Payable.
1G Maintenance and Depreciation
The Company charges the cost of maintenance and repairs of
property and minor renewals and improvements of property to
maintenance expense. When depreciable property is retired, its
original cost is charged to the accumulated provision for
depreciation.
The provision for depreciation substantially reflects the
systematic amortization of the original cost of depreciable
property over estimated useful lives on the straight-line method.
Additionally, actual dismantling cost, net of salvage, is included
in the provision for depreciation in the month incurred. The
amounts provided are designed to cover not only losses due to wear
and tear that are not restored by maintenance, but also losses due
to obsolescence and inadequacy.
The provision for depreciation, expressed as an annual
percentage of original cost of depreciable property, is as follows:
For fiscal years ended
September 30, 1998 1997 1996
Provision for depreciation 3.1% 3.1% 3.1%
1H Regulated Operations
The Company's utility operations are subject to regulation by
the Commission. Regulated operations are accounted for in
accordance with Statement of Financial Accounting Standards (SFAS)
No. 71, "Accounting for the Effects of Certain Types of
Regulation." This standard controls the application of generally
accepted accounting principles for companies whose rates are
determined by an independent regulator such as the Commission.
Regulatory assets represent certain costs that are expected to be
recovered from customers through the ratemaking process. When
incurred, such costs are deferred as assets in the balance sheet
and subsequently recorded as expenses when those same amounts are
reflected in rates.
The following regulatory assets were reflected in Current Assets
and Other Assets in the Consolidated Balance Sheets at September
30, 1998 and 1997:
1998 1997
(Thousands)
Environmental costs, net of recoveries (see Note 2A) $25,008 $6,899
Transition costs from pipeline supplier - 1,422
Rate case expenses 6 82
Discount, premium, expenses, and loss on reacquired bonds 87 113
Other 2 8
Total regulatory assets $25,103 $8,524
1I Income Taxes
The Company follows the liability method of accounting for
deferred income taxes. Under the liability method, deferred income
taxes have been recorded using currently enacted tax rates for the
differences between the tax basis of assets and liabilities and the
basis reported in the financial statements. Due to the effects of
regulation on the Company, certain adjustments made to deferred
income taxes are, in turn, debited or credited to regulatory assets
or liabilities. (See Note 5C.)
Each Company within the consolidated group nets its income tax
related regulatory assets and liabilities. At September 30, 1998
and 1997, net regulatory income tax liabilities recorded in Other
Liabilities amounted to $5.0 million and $5.2 million,
respectively.
Investment tax credits have been deferred and are being
amortized through credits to income over the book lives of related
property.
The preceding deferred-tax and tax-credit accounting conforms
with regulations of the Commission.
1J Gas in Storage
Storage injections are priced at the fiscal-year average of
costs of supply. Withdrawals from storage are priced on the last-
in, first-out (LIFO) cost method. The estimated current
replacement cost of gas in inventory, at September 30, 1998 and
1997, exceeded the LIFO cost by approximately $12.8 million and
$16 million, respectively.
1K Statement of Cash Flows
For purposes of the balance sheet and the statement of cash
flows, the Company considers all short-term liquid investments with
maturities of three months or less to be cash equivalents.
Income taxes and interest paid (excluding capitalized interest)
were as follows:
For fiscal years ended 1998 1997 1996
September 30,
(Thousands)
Income taxes paid $6,209 $9,053 $9,435
Interest paid 5,064 4,889 5,119
1L Recovery of Gas Costs
Under the tariffs of the Company, the difference for any month
between costs recoverable through the Gas Charge and revenues
billed to customers under the Gas Charge is refunded to or
recovered from customers. Consistent with these tariff provisions,
such difference for any month is recorded either as a current
liability or as a current asset (with a contra entry to Gas Costs).
For each gas utility, the Commission conducts annual proceedings
regarding the reconciliation of revenues from the Gas Charge and
related costs incurred for gas. In such proceedings, costs
recovered by a utility through the Gas Charge are subject to
challenge. Such proceedings regarding the Company for fiscal years
1997 and 1998 are currently pending before the Commission. (See
Competition and Deregulation in Item 1.)
1M Recovery of Costs of Environmental Activities Relating to
Former Manufactured Gas Operations
The Company is recovering the costs of environmental activities
relating to its former manufactured gas operations, including
carrying charges on the unrecovered balances, under a rate
mechanism approved by the Commission. For each utility with such a
rate mechanism, the Commission conducts annual proceedings
regarding the reconciliation of revenues from the rate mechanism
and related costs. In such proceedings, costs recovered by a
utility through the rate mechanism are subject to challenge. No
such proceedings are currently pending before the Commission.
1N Accounting Standards
The Company adopted SOP 96-1, "Environmental Remediation
Liabilities," in fiscal 1998. The application of the statement did
not have a material effect on the Company's financial condition or
results of operations.
2. ENVIRONMENTAL MATTERS
2A Former Manufactured Gas Plant Operations
The Company, its predecessors, and certain former affiliates
operated facilities in the past at multiple sites for the purpose
of manufacturing gas and storing manufactured gas (Manufactured Gas
Sites). In connection with manufacturing and storing gas, various
by-products and waste materials were produced, some of which might
have been disposed of rather than sold. Under certain laws and
regulations relating to the protection of the environment, the Company
might be required to undertake remedial action with respect to some
of these materials. One of the Manufactured Gas Sites is discussed
in more detail below. The Company, under the supervision of the IEPA,
is conducting investigations of two additional Manufactured Gas Sites.
These investigations may require the Company to perform additional
investigation and remediation. The investigations are in a
preliminary stage and are expected to occur over an extended period
of time.
In 1990, the Company entered into an Administrative Order on
Consent (AOC) with the United States Environmental Protection
Agency (EPA) and the IEPA to implement and conduct a remedial
investigation/feasibility study (RI/FS) of a Manufactured Gas Site
located in Waukegan, Illinois, where manufactured gas and coking
operations were formerly conducted (Waukegan Site). The RI/FS is
comprised of an investigation to determine the nature and extent of
contamination at the Waukegan Site and a feasibility study to
develop and evaluate possible remedial actions. The Company
entered into the AOC after being notified by the EPA that the
Company, General Motors Corporation (GMC) and Outboard Marine
Corporation were each a potentially responsible party (PRP) under
CERCLA with respect to the Waukegan Site. A PRP is potentially
liable for the cost of any investigative and/or remedial work that
the EPA determines is necessary. Other parties identified as PRPs
did not enter into the AOC. Under the terms of the AOC, the
Company is responsible for the cost of the RI/FS. The Company
believes, however, that it will recover a significant portion of
the costs of the RI/FS from other entities. GMC has agreed to
share equally with the Company in funding of the RI/FS cost,
without prejudice to GMC's or the Company's right to seek a lesser
cost responsibility at a later date.
The Company is accruing and deferring the costs it incurs in
connection with all of the Manufactured Gas Sites, including
related legal expenses, pending recovery through rates or from
insurance carriers or other entities. At September 30, 1998, the
total of the costs deferred by the Company, net of recoveries and
amounts billed to other entities, was $25.0 million. This amount
includes the Company's best estimate of the costs of investigating
and remediating the Manufactured Gas Sites. This estimate is based
upon a comprehensive review by the Company and its outside
consultants of potential costs associated with conducting
investigative and remedial actions at the Manufactured Gas Sites as
well as the likelihood of whether such action will be necessary.
While the Company intends to seek contribution from other entities
for the costs incurred at the sites, the full extent of such
contributions cannot be determined at this time.
The Company has filed suit against a number of insurance
carriers for the recovery of environmental costs relating to its
former manufactured gas operations. The suit asks the court to
declare, among other things, that the insurers are liable under
policies in effect between 1937 and 1986 for costs incurred or
to be incurred by the Company in connection with two Manufactured
Gas Sites in Waukegan. The Company is also asking the court to
award damages stemming from the insurers' breach of their
contractual obligation to defend and indemnify the Company against
these costs. At this time, management cannot determine the
timing and extent of the Company's recovery of costs from its
insurance carriers. Accordingly, the costs deferred at
September 30, 1998 have not been reduced to reflect recoveries
from insurance carriers.
Costs incurred by the Company for environmental activities
relating to former manufactured gas operations will be recovered
from insurance carriers or other entities or through rates for
utility service. Accordingly, management believes that the costs
incurred by the Company in connection with former manufactured gas
operations will not have a material adverse effect on the financial
position or results of operations of the Company. The Company is
recovering the costs of environmental activities relating to its
former manufactured gas operations, including carrying charges on
the unrecovered balances, under a rate mechanism approved by the
Commission. At September 30, 1998, it had recovered $7.2 million
of such costs through rates.
2B Former Mineral Processing Site in Denver, Colorado
In 1994, the Company received a demand from the S.W. Shattuck
Chemical Company, Inc. (Shattuck), a responsible party under
CERCLA, for reimbursement, indemnification, and contribution for
response costs incurred at a former mineral processing site in
Denver, Colorado. Shattuck is a wholly owned subsidiary of
Salomon, Inc. (Salomon). The demand alleges that the Company is a
successor to the liability of a former entity that was allegedly
responsible during the period 1934-1941 for the disposal of mineral
processing wastes containing radium and other hazardous substances
at the site. The cost of the remedy at the site has been estimated
by Shattuck to be approximately $31 million. Salomon has provided
financial assurance for the performance of the remediation at the
site.
The Company filed a declaratory judgment action against Salomon
in the District Court for the Northern District of Illinois. The
suit asks the court to declare that the Company is not liable for
response costs at the Denver site. Salomon filed a counterclaim
for costs incurred by Salomon and Shattuck with respect to the
site. In 1997, the District Court granted the Company's motion for
summary judgment, declaring that the Company is not liable for any
response costs in connection with the Denver site.
On August 5, 1998, the U.S. Court of Appeals, Seventh Circuit,
reversed the District Court's decision and remanded the case for
determination of what liability, if any, the former entity has and
therefore the Company has for activities at the site.
The Company does not believe that it has liability for the
response costs, but cannot determine the matter with certainty. At
this time, the Company cannot reasonably estimate what range of
loss, if any, may occur. In the event that the Company incurred
liability, it would pursue reimbursement from insurance carriers,
other responsible parties, if any, and through its rates for
utility service.
2C Gasoline Release in Wheeling, Illinois
In June 1995, the Company received a letter from the IEPA
informing the Company that it was not in compliance with certain
provisions of the Illinois Environmental Protection Act which
prohibit water pollution within the State of Illinois. On November
14, 1995, the Illinois Attorney General filed a complaint in the
Circuit Court of Cook County naming the Company and four other
parties as defendants. The complaint alleges that the violations
are the result of a gasoline release that occurred in Wheeling,
Illinois in June 1992, when a contractor who was installing a
pipeline for the Company accidentally struck a gasoline pipeline
owned by West Shore Pipeline Company. The Company is contesting
this suit. The Company believes that a substantial portion of any
cost incurred by the Company in connection with this matter is
recoverable from its insurance carrier. Accordingly, management
does not believe the outcome of this matter will have a material
adverse effect on financial position or results of operations of
the Company.
3. COVENANTS REGARDING RETAINED EARNINGS
The Company's indenture relating to its first mortgage bonds
contains provisions and covenants restricting the payment of cash
dividends and the purchase or redemption of capital stock. At
September 30, 1998, such restrictions amounted to $11.6 million out
of the Company's total retained earnings of $70.0 million.
4. RETIREMENT AND POSTEMPLOYMENT BENEFITS
4A Pension Benefits
The Company participates in two defined benefit pension plans
covering substantially all employees. These plans provide pension
benefits that generally are based on an employee's length of
service, compensation during the five years preceding retirement,
and social security benefits. Annual contributions are made to the
plans based upon actuarial determinations and in consideration of
tax regulations and funding requirements under federal law.
The Company also has non-qualified pension plans that provide
employees with pension benefits in excess of qualified plan limits
imposed by federal tax law.
Net pension cost for all plans for fiscal 1998, 1997, and 1996
included the following components:
1998 1997 1996
(Millions)
Service cost - benefits earned during year $ 0.8 $0.8 $1.0
Interest cost on projected benefit obligations 2.0 1.9 2.0
Actual return on plan assets (gain) (5.4) (6.0) (3.9)
Net amortization and deferral 2.8 3.7 1.7
Settlement accounting (0.7) (0.3) 0.1
Net pension cost $(0.5) $0.1 $0.9
In 1998 and 1997 the Company recognized a net gain of $700,000
and $300,000 respectively, and a net loss of $100,000 in 1996 from
the settlement of portions of pension plan obligations.
The calculation of pension cost assumed a long-term rate of
return on assets of 9.0 percent for 1998 and 1997, and 8.5 percent
for 1996. The settlement accounting cost for all years was
determined using a discount rate of 7.5 percent and assumed future
compensation increases of 4.5 percent per year.
The following table shows the estimated funded status of the
Company's pension plans at September 30, 1998 and 1997:
1998 1997
(Millions)
Plan assets at market value $34.9 $31.3
Actuarial present value of plan benefits:
Vested 18.4 18.2
Non-vested 3.3 2.7
Accumulated benefit obligation 21.7 20.9
Effect of projected future compensation increases 7.1 5.8
Projected benefit obligation 28.8 26.7
Excess of plan assets over projected benefit obligation 6.1 4.6
Less:
Unrecognized transition asset 0.3 0.3
Unrecognized prior service cost (0.2) (0.2)
Unrecognized net gain 6.5 5.4
Non-qualified plan contributions 7-1-98 to 9-30-98 0.1 -
Recognition of non-qualified plan
additional minimum liability - (0.1)
Accrued pension liability $(0.4) $(1.0)
The projected benefit obligation and plan assets at September
30, 1998 and 1997, are based on a July 1 measurement date using a
discount rate of 7.0 percent for 1998 and 7.5 percent for 1997 and
assumed future compensation increases of 4.5 percent per year.
Plan assets consist primarily of marketable equity and fixed-income
securities.
4B Other Postretirement Benefits
The Company also provides certain health care and life insurance
benefits for retired employees. Substantially all employees may
become eligible for such benefit coverage if they reach retirement
age while working for the Company. The plans are funded based upon
actuarial determinations and in consideration of tax regulations
and funding requirements under federal law. The Company accrues
the expected costs of such benefits during the employees' years of
service.
Net postretirement benefit cost for all plans for fiscal 1998,
1997, and 1996 included the following components:
1998 1997 1996
(Millions)
Service cost - benefits earned during year $0.3 $0.3 $0.3
Interest cost on projected benefit obligation 0.8 0.7 0.7
Actual return on plan assets (gain) (0.7) (0.5) (0.2)
Amortization of transition obligation 0.4 0.4 0.4
Net amortization and deferral 0.4 0.3 0.1
Net postretirement benefit cost $1.2 $1.2 $1.3
The calculation of postretirement benefit cost assumed a long-
term rate of return on assets of 9.0 percent for 1998 and 1997 and
7.5 percent for 1996.
Of the above total postretirement costs recognized for fiscal
years 1998, 1997, and 1996, $500,000, $600,000, and $600,000,
respectively, were funded through trust funds for future benefit
payments.
The following table sets forth the estimated funded status for
the postretirement health care and life insurance plans at
September 30, 1998 and 1997:
1998 1997
(Millions)
Plan assets at market value $3.8 $2.8
Accumulated postretirement benefit obligation (APBO):
Retirees 6.0 6.5
Fully eligible active plan participants 0.8 0.8
Other active plan participants 2.6 2.7
Total APBO 9.4 10.0
Deficiency of plan assets over the APBO (5.6) (7.2)
Less:
Unrecognized transition obligation (5.4) (6.8)
Unrecognized net gain 0.6 0.4
Contributions: July 1 to September 30 0.8 0.8
Accrued postretirement benefit asset (liability) $ - $ -
The total APBO and plan assets at September 30, 1998 and 1997,
are based on a July 1 measurement date using a discount rate of 7.0
percent for 1998 and 7.5 percent for 1997 and assumed future
compensation increases of 4.5 percent per year. Plan assets
consist primarily of marketable equity and fixed-income securities.
For measurement purposes, a health care cost trend rate of 7.9
percent was assumed for fiscal 1998, and that rate thereafter will
decline gradually to 4.75 percent in 2003 and subsequent years. The
health care cost trend rate assumption has a significant effect on the
amounts reported. Increasing the assumed health care cost trend rate
by one percentage point for each future year would have increased the
APBO at September 30, 1998, by $800,000 and the aggregate of service
and interest cost components of the net periodic postretirement
benefit cost by $100,000 annually.
5. TAX MATTERS
5A Provision for Income Taxes
Total income tax expense as shown on the Consolidated Statements of
Income is composed of the following:
For fiscal years ended September 30, 1998 1997 1996
(Thousands)
Current:
Federal $5,314 $7,519 $ 8,715
State 1,120 1,584 1,864
Total current income taxes 6,434 9,103 10,579
Deferred:
Federal 1,450 162 (278)
State 382 111 11
Total deferred income taxes 1,832 273 (267)
Investment tax credits - net:
Federal (180) (189) (189)
State 39 42 31
Total investment tax credits - net (141) (147) (158)
Total provision for income taxes $8,125 $9,229 $10,154
5B Tax Rate Reconciliation
<TABLE>
<CAPTION>
The following is a reconciliation between the computed federal
income tax expense (tax rate of 35 percent times pre-tax book income)
and the total provision for federal income tax expenses:
For fiscal years ended September 30, 1998 1997 1996
Percent Percent Percent
of of of
Amount Pre-tax Amount Pre-tax Amount Pre-tax
(000's) Income (000's) Income (000's) Income
<S> <C> <C> <C> <C> <C> <C>
Computed federal income
tax expense $6,849 35.00 $7,807 35.00 $8,608 35.00
Amortization of deferred taxes (153) (0.78) (155) (0.70) (182) (0.74)
Other, net (112) (0.58) (160) (0.73) (178) (0.74)
Total provision for federal
income taxes $6,584 33.64 $7,492 33.57 $8,248 33.52
</TABLE>
5C Deferred Income Taxes
Set forth in the table below are the temporary differences which
gave rise to the net deferred income tax liabilities (see Note 1I):
At September 30, 1998 1997
(Thousands)
Deferred tax liabilities:
Property - accelerated depreciation and
other property related items $25,302 $23,910
Other 2,323 995
Total deferred income tax liabilities 27,625 24,905
Deferred tax assets:
Net regulatory liabilities -
income tax amounts (1,972) (2,062)
Unamortized investment credits (1,363) (1,427)
Other (1,238) (1,000)
Total deferred income tax assets (4,573) (4,489)
Net deferred income tax liabilities $23,052 $20,416
6. ASSETS SUBJECT TO LIEN
The Indenture of Mortgage, dated April 1, 1955, as supplemented,
securing the first mortgage bonds issued by the Company,
constitutes a direct, first-mortgage lien on substantially all
property owned by the Company.
7. OTHER INCOME AND DEDUCTIONS - MISCELLANEOUS
For fiscal years ended September 30, 1998 1997 1996
(Thousands)
Amortization of (gain) loss on reacquired bonds $11 $(125) $ (93)
Interest on amounts recoverable from customers 23 42 224
Gain on expiration of gas storage contracts - - 3,717
Other 4 33 130
Total other income and deductions - miscellaneous $38 $ (50) $3,978
8. CAPITAL COMMITMENTS
Total contract and purchase order commitments of the Company at
September 30, 1998, amounted to approximately $1.1 million.
9. SHORT-TERM BORROWINGS AND CREDIT LINES
At September 30, 1998 1997
(Thousands)
Bank Loans
Peoples Gas
8.50% due March 27, 1998 $ - $ 700
Commercial Paper
North Shore Gas
due October 1, 1997 $ - $ 2,110
Peoples Gas
due October 1, 1998 $ 2,300 $ -
due October 23, 1998 6,600 -
Letters of Credit
Peoples Gas $ 100 $ 100
Available lines of credit
Unused bank lines $120,400 $126,490
Short-term cash needs of the Company and Peoples Gas are met
through intercompany loans from Peoples Energy, bank loans, and/or
the issuance of commercial paper. The outstanding total amount of
bank loans, letters of credit and commercial paper issuances cannot
at any time exceed total bank credit then in effect.
At September 30, 1998 and 1997, Peoples Gas and the Company had
combined lines of credit totaling $129.4 million. Of these
amounts, the Company could borrow up to $30 million. Agreements
covering $92 million of the total at September 30, 1998 will expire
on August 29, 1999; the agreement covering the remaining $37.4
million will expire on January 31, 2000. Such lines of credit
cover projected short-term credit needs of Peoples Gas and the
Company and support the long-term debt treatment of Peoples Gas'
adjustable-rate mortgage bonds. Payment for the lines of credit is
by fee.
10. LONG-TERM DEBT
10A Sinking Fund Requirements and Maturities
At September 30, 1998, long-term debt sinking fund requirements
and maturities for the next five years are:
Fiscal Amount
Year (thousands)
1999 -
2000 -
2001 -
2002 -
2003 15,000
10B Fair Value of Financial Instruments
At September 30, 1998, the carrying amount of the Company's long-
term debt of $64.6 million had an estimated fair value of
$66.8 million. At September 30, 1997, the carrying amount of the
Company's long-term debt of $64.6 million had an estimated fair
value of $67.6 million. The estimated fair value of the Company's
long-term debt is based on quoted market prices or yields for
issues with similar terms and remaining maturities. Since the
Company is subject to regulation, any gains or losses related to
the difference between the carrying amount and the fair value of
financial instruments may not be realized by the Company's
shareholder. The carrying amount of all other financial
instruments approximates fair value.
11. QUARTERLY FINANCIAL DATA (Unaudited)
All four quarters of fiscal 1998 reflected weather that was
significantly warmer than during the comparable quarters of fiscal
1997.
Net Income
Operating Operating Applicable to
Fiscal Quarters Revenues Income Common Stock
(Thousands)
1998
Fourth $ 14,071 $ 396 $ (721)
Third 24,321 2,555 1,459
Second 55,715 8,348 7,037
First 50,099 6,619 5,211
1997
Fourth $ 14,597 $ (848) $ (1,975)
Third 25,648 3,615 2,490
Second 77,581 9,855 8,600
First 51,049 7,046 5,699
12. EVENT (UNAUDITED) SUBSEQUENT TO THE AUDITOR'S REPORT
DATED OCTOBER 30, 1998
ENVIRONMENTAL MATTERS
Former Manufactured Gas Plant Operations
The Company has filed suit against a number of insurance
carriers for the recovery of environmental costs relating
to the Company's former manufactured gas operations. In
November 1998, the Company entered into a settlement
agreement with one of its insurance carriers. Given the
regulatory treatment discussed in Note 2A, the settlement
will not have an effect on income.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
ACCOUNTING AND FINANCIAL DISCLOSURE
Not applicable.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE COMPANY
IDENTIFICATION OF DIRECTORS
Company
Name, Principal Occupation, Age at Directorship
and Other Directorships 11-01-98 Since
Donald M. Field 48 1998
Executive Vice President of the Company,
Peoples Energy, and Peoples Gas; Director of
Peoples Gas.
James Hinchliff 58 1985
Senior Vice President and General Counsel
of the Company, Peoples Energy,
and Peoples Gas; Director of Peoples Gas.
James M. Luebbers 52 1998
Vice President and Controller
of the Company, Peoples Energy,
and Peoples Gas; Director of Peoples Gas.
Thomas M. Patrick 52 1997
President and Chief Operating Officer of
the Company, Peoples Energy, and Peoples Gas;
Director of Peoples Energy and Peoples Gas.
Richard E. Terry 61 1982
Chairman of the Board and Chief Executive
Officer of the Company, Peoples Energy, and
Peoples Gas; Director of Peoples Energy
and Peoples Gas. Mr. Terry is also a
director of Harris Bankcorp, Inc., Harris Trust
and Savings Bank, Bankmont Financial Corp.,
and Amsted Industries.
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE COMPANY
(Continued)
IDENTIFICATION OF EXECUTIVE OFFICERS
Position at Age at Position
Name November 01, 1998 11-01-98 Held Since
Katherine A. Donofrio Vice President 41 1997
Willard S. Evans, Jr. Vice President 43 1997
Donald M. Field Executive Vice President 48 1998
Joan T. Gagen Vice President 47 1994
James Hinchliff Senior Vice President and 58 1989
General Counsel
John C. Ibach Vice President 51 1992
Peter H. Kauffman Assistant General Counsel and Secretary 52 1998
James M. Luebbers Vice President and Controller 52 1998
William E. Morrow Vice President 42 1996
Thomas M. Patrick President and Chief Operating Officer 52 1998
Desiree Rogers Vice President 39 1997
Richard E. Terry Chairman of the Board and 61 1990
Chief Executive Officer
Charles L. Thompson Vice President 51 1998
Directors and executive officers of the Company were elected to
serve for a term of one year or until their successors are duly
elected and qualified, except for Ms. Donofrio, Mr. Evans, and Ms.
Rogers, who were appointed.
There are no family relationships among directors and executive
officers of the Company.
All of the directors and executive officers of the Company have
been continuously employed by the Company and/or its affiliates in
various capacities for at least five years with the exception of
Ms. Rogers.
ITEM 11. EXECUTIVE COMPENSATION
The following tables set forth information concerning annual and long-
term compensation and grants of stock options, stock appreciation rights
(SARs) and restricted stock awards under Peoples Energy's Long-Term
Incentive Compensation Plan. Cash compensation for executive officers,
is paid by Peoples Gas with appropriate amounts billed to the Company for
the time such officers serve the Company. All compensation was paid by
the Company and its affiliates (Peoples Energy and Peoples Gas) for
services in all capacities during the three fiscal years set forth below,
to (1) the Chief Executive Officer and (2) the most highly compensated
executive officer of the Company other than the Chief Executive Officer.
No executive officer's cash compensation paid by the Company for service
to the Company exceeded $100,000.
<TABLE>
<CAPTION>
SUMMARY COMPENSATION TABLE
Long Term Compensation
Annual Compensation Awards
Restricted Stock All Other
Name and Award(s) (1)(2) Options/SARs Compensation
Principal Position Year Salary ($) Bonus ($) ($) (#) (3)($)
<S> <C> <C> <C> <C> <C> <C>
Richard E.Terry 1998 600,000 N/A (4) 192,828 20,600 18,000
Chairman and 1997 548,500 237,900 152,663 17,800 16,455
Chief Executive 1996 473,500 191,600 145,722 21,200 14,205
Officer
</TABLE>
(1) The total number of restricted shares held by Mr. Terry and the
aggregate market value of such shares at September 30, 1998, was
14,685 shares valued at $528,660.00. Dividends are paid on the
restricted shares at the same time and at the same rate as dividends
paid to all shareholders of common stock. Aggregate market value is
based on a per share price of $36.00, the closing price of Peoples
Energy's stock on the New York Stock Exchange composite transactions
on September 30, 1998.
(2) Restricted stock awards granted to date vest in equal annual
increments over a five year period. If a recipient's employment with the
Company terminates, other than by reason of death, disability or
retirement after attaining age 65, the recipient forfeits all rights to
the unvested portion of the restricted stock award. In addition, the
Compensation-Nominating Committee (and with respect to the CEO, the
Compensation-Nominating Committee, subject to the approval of the non-
employee directors) may, in its sole discretion, accelerate the vesting
of any restricted stock awards granted under the Long-Term Incentive
Compensation Plan. Total restricted stock awarded to Mr. Terry for 1996
constitutes 5,275 shares, of which 1,055 shares vested in 1997; 1,055
shares vested in 1998; 1,055 shares will vest in 1999; 1,055 shares
will vest in 2000; and the remaining 1,055 shares will vest in 2001.
Total restricted stock awarded to Mr. Terry for 1997 constitutes 4,425
shares, of which 885 shares vested in 1998; 885 shares will vest in
1999; 885 shares will vest in 2000; 885 shares will vest in 2001; and the
remaining 885 shares will vest in 2002. Total restricted stock awarded
to Mr. Terry for 1998 constitutes 5,125 shares, of which 1,025 shares
will vest in 1999; 1,025 shares will vest in 2000; 1,025 shares will vest
in 2001; 1,025 shares will vest in 2002; and the remaining 1,025 shares
will vest in 2003.
(3) Company contributions to the Capital Accumulation Plan accounts
of the named executive officers during the above fiscal years.
Employee contributions under the plan are subject to a maximum
limitation under the Internal Revenue Code of 1986. The Company
pays an employee who is subject to this limitation an additional
50 cents for each dollar that the employee is prevented from
contributing solely by reason of such limitation. The amounts
shown in the table above reflect, if applicable, this additional
Company payment.
(4) Not available as of the latest practicable date.
<TABLE>
<CAPTION>
OPTIONS/SAR GRANTS IN FISCAL 1998
Individual Grants
% of Total Options/
Options/SARs SARs Granted to Exercise or Grant Date
Granted Employees in Fiscal Base Price Expiration PresentValue
Name (#) (1) Year (2) ($/Sh) Date ($)(3)
<S> <C> <C> <C> <C> <C>
Richard E. Terry 20,600 12.3% $37.84 01-Oct-07 $131,428
Chairman and Chief
Executive Officer
</TABLE>
(1)The grant of an Option enables the recipient to purchase Peoples
Energy common stock at a purchase price equal to the fair market
value of the shares on the date the Option is granted. The grant
of an SAR enables the recipient to receive, for each SAR granted,
cash in an amount equal to the excess of the fair market value of
one share of Peoples Energy common stock on the date the SAR is
exercised over the fair market value of such common stock on the
date the SAR was granted. Options or SARs that expire
unexercised become available for future grants. Before an Option
or SAR may be exercised, the recipient must complete 12 months of
continuous employment subsequent to the grant of the Option or
SAR. Options and SARs may be exercised within 10 years from the
date of grant, subject to earlier termination in case of death,
retirement, or termination of employment.
(2)Based on 83,800 Options and 83,800 SARs granted to all employees
under Peoples Energy's Long-Term Incentive Compensation Plan during
fiscal 1998.
(3)Present value is determined using a variation of the Black-
Scholes Option-Pricing Model. The model assumes: a) that Options
and SARs are exercised three and one-half years after the date of
grant - the average time Options and SAR's were held by recipients
under Peoples Energy's Long-Term Incentive Compensation Plan over the
past ten years; b) use of an interest rate equal to the interest rate
on a U.S. Treasury security with a maturity date corresponding to the
assumed exercise date; c) a level of volatility calculated using
weekly stock prices for the two years prior to the date of grant; d)
an expected dividend yield; and e) that no adjustments were made for
non-transferability or risk of forfeiture. This is a theoretical
value for the Options and SARs. The amount realized from an Option
or SAR ultimately depends upon the excess of the market value of
Peoples Energy's stock over the exercise price on the date the option
or SAR is exercised.
ITEM 11. EXECUTIVE COMPENSATION (Continued)
<TABLE>
<CAPTION>
AGGREGATED OPTION/SAR EXERCISES IN FISCAL 1998
AND FISCAL YEAR-END OPTION/SAR VALUES
Shares Number of Unexercised Value of Unexercised
Acquired Options/SARs at In-the-Money
on Fiscal Options/SARs
(Option/SAR) Value Year-End (#) at Fiscal Year-End ($)
Name Exercise(#) Realized($) Exercisable Unexercisable Exercisable Unexercisable
<S> <C> <C> <C> <C> <C> <C>
Richard E. Terry N/A (1) N/A (1) 46,800 20,600 $187,998 $0
Chairman and Chief
Executive Officer
(1) Not available as of the latest practicable date.
</TABLE>
PENSION PLAN TABLE
Years of Service
Average Annual
Compensation 20 25 30 35 40
$150,000 $ 54,400 $ 68,000 $ 81,600 $ 90,975 $100,350
200,000 74,400 93,000 111,600 124,100 136,600
250,000 94,400 118,000 141,600 157,225 172,850
300,000 114,400 143,000 171,600 190,350 209,100
350,000 134,400 168,000 201,600 223,475 245,350
400,000 154,400 193,000 231,600 256,600 281,600
450,000 174,400 218,000 261,600 289,725 317,850
500,000 194,400 243,000 291,600 322,850 354,100
550,000 214,400 268,000 321,600 355,975 390,350
600,000 234,400 293,000 351,600 389,100 426,600
650,000 254,400 318,000 381,600 422,225 462,850
700,000 274,400 343,000 411,600 455,350 499,100
750,000 294,400 368,000 441,600 488,475 535,350
800,000 314,400 393,000 471,600 521,600 571,600
850,000 334,400 418,000 501,600 554,725 607,850
900,000 354,400 443,000 531,600 587,850 644,100
The above table illustrates various annual straight-life
benefits at normal retirement (age 65) for the indicated levels of
average annual compensation and various periods of service,
assuming no future changes in Peoples Energy's pension benefits.
The compensation used in the computation of annual retirement
benefits is substantially equivalent to the salary and bonus
reported in the Summary Compensation Table. The benefit amounts
shown reflect reduction for applicable Social Security benefits.
Average annual compensation is the average 12-month compensation
for the highest 60 consecutive months of the last 120 months of
service prior to retirement. Compensation is total salary paid to
an employee by the Company and/or its affiliates, including bonuses
under Peoples Energy's Short-Term Incentive Compensation Plan, pre-
tax contributions under Peoples Energy's Capital Accumulation Plan,
pre-tax contributions under Peoples Energy's Health and Dependent
Care Spending Accounts Plan, and pre-tax contributions for life and
health care insurance, but excluding moving allowances, exercise of
stock options and SARs, and other compensation that has been
deferred.
ITEM 11. EXECUTIVE COMPENSATION (Continued)
At September 30, 1998, the credited years of retirement benefit
service for the individuals listed in the Summary Compensation
Table are as follows: Mr. Terry, 34 years. The benefits shown in
the foregoing table are subject to maximum limitations under the
Employee Retirement Income Security Act of 1974, as amended, and
the Internal Revenue Code of 1986, as amended. Should these
benefits at the time of retirement exceed the then-permissible
limits of the applicable Act, the excess would be paid by the
Company as supplemental pensions pursuant to Peoples Energy's
Supplemental Retirement Benefit Plan. The benefits shown give
effect to these supplemental pension benefits.
SEVERANCE AGREEMENTS
Peoples Energy has entered into separate severance agreements
with certain key executives including each of the executives named
in the Summary Compensation Table. The intent of the severance
agreements is to assure the continuity of the administration and
operations of Peoples Energy and its subsidiaries, including the
Company in the event of a Change in Control of the Company (as
described below). The severance agreements were developed in
accordance with the advice of outside consultants.
The term of each severance agreement is for the longer of 36
months after the date in which a Change in Control of Peoples
Energy occurs or 24 months after the completion of the transaction
approved by shareholders described in (iii) below of the
description of a Change in Control. A Change in Control is
defined as occurring when (i) Peoples Energy receives a report on
Schedule 13D filed with the Securities and Exchange Commission
pursuant to Section 13(d) of the Securities Exchange Act of 1934,
as amended, disclosing that any person, group, corporation, or
other entity is the beneficial owner, directly or indirectly, of
20% or more of the common stock of Peoples Energy; (ii) any person,
group, corporation, or other entity (except Peoples Energy or a
wholly-owned subsidiary), after purchasing common stock of Peoples
Energy in a tender offer or exchange offer, becomes the beneficial
owner, directly or indirectly, of 20% or more of such common stock;
(iii) the shareholders of Peoples Energy approve (a) any
consolidation or merger of Peoples Energy in which Peoples Energy
is not the continuing or surviving corporation, other than a
consolidation or merger in which holders of Peoples Energy's common
stock prior to the consolidation or merger have substantially the
same proportionate ownership of common stock of the surviving
corporation immediately after the consolidation or merger as
immediately before; (b) any consolidation or merger in which
Peoples Energy is the continuing or surviving corporation, but in
which the common shareholders of Peoples Energy immediately prior
to the consolidation or merger do not hold at least 90% of the
outstanding common stock of Peoples Energy; (c) any sale, lease,
exchange or other transfer of all or substantially all of the
assets of Peoples Energy, except where Peoples Energy owns all of
the outstanding stock of the transferee entity or Peoples Energy's
common shareholders immediately prior to such transaction own at
least 90% of the transferee entity or group of transferee entities
immediately after such transaction; or (d) any consolidation or
merger of Peoples Energy where, after the consolidation or merger,
one entity or group of entities owns 100% of the shares of Peoples
Energy, except where Peoples Energy's common shareholders
immediately prior to such merger or consolation own at least 90% of
the outstanding stock of such entity or group of entities
immediately after such consolidation or merger; or (iv) a change in
the majority of the members of Peoples Energy's Board of Directors
within a 24-month period, unless approved by two-thirds of the
directors then still in office who were in office at the beginning
of the 24-month period.
Each severance agreement provides for payment of severance
benefits to the executive in the event that, during the term of the
severance agreement, (i) the executive's employment is terminated
by Peoples Energy or the Company, except for "cause" as defined
therein; or (ii) the executive's employment is terminated due to a
constructive discharge, which includes (a) a material change in the
executive's responsibilities, which change would cause the
executive's position with Peoples Energy or the Company to become
of less dignity, responsibility, prestige or scope; (b) reduction,
which is more than de minimis, in total compensation; (c)
assignment without the executive's consent to a location more than
50 miles from the current place of employment; or (d) liquidation,
dissolution, consolidation, merger, or sale of all or
substantially all of the assets of Peoples Energy or the Company,
unless the successor corporation has a net worth at least equal to
that of Peoples Energy or the Company, as applicable, and expressly
assumes the obligations of Peoples Energy under the executive's
severance agreement.
The principal severance benefits payable under each severance
agreement consist of the following: (i) the executive's base
salary and accrued benefits through the date of termination,
including a pro rata portion of awards under Peoples Energy's
Short-Term Incentive Compensation (STIC) Plan; (ii) three times the
sum of the individual's base salary, the average of the STIC Plan
awards for the prior three years and the value of the Long-Term
Incentive Compensation (LTIC) Plan awards in the prior calendar
year; and (iii) the present value of the executive's accrued
benefits under the Peoples Energy's Supplemental Retirement
Benefits Plan (SRBP) that would be payable upon retirement at
normal retirement age, computed as if the executive had completed
three years of additional service. In addition, the executive will
be entitled to continuation of life insurance and medical benefits
for the longer of (a) a period of three years after termination or
(b) a period commencing after termination and ending when the
executive may receive pension benefits without actuarial reduction,
provided that Peoples Energy's obligation for such benefits under
the severance agreement shall cease upon the executive's employment
with another employer that provides life insurance and medical
benefits. Each severance agreement also provides that the
executive's Options and SARs shall become exercisable upon a Change
in Control and that all Options and SARs shall remain exercisable
for the shorter of (a) three years after termination or (b) the
term of such Options and SARs. Any restricted stock previously
awarded to the executive under the LTIC Plan would vest upon a
Change in Control if such vesting does not occur due to a Change in
Control under the terms of the LTIC Plan. Peoples Energy is also
obligated under each severance agreement to pay an additional
amount to the executive sufficient on an after-tax basis to satisfy
any excise tax liability imposed by Section 4999 of the Internal
Revenue Code of 1986, as amended. The benefits received by the
executive under each agreement are in lieu of benefits under
Peoples Energy's termination allowance plan and the executive's
benefits under the SRBP. Each executive would be required to waive
certain claims prior to receiving any severance
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
At November 1, 1998, voting securities of the Company were
beneficially owned as follows:
Title of Number of Percent of
Class Name and Address Shares Owned Class
Common Stock Peoples Energy Corporation
without 130 East Randolph Drive
par value Chicago, Illinois 60601 3,625,887 100
SECURITY OWNERSHIP OF MANAGEMENT
No equity securities of the Company are beneficially owned
directly or indirectly by any director or officer of the Company.
Shares of common stock, without par value, of Peoples Energy
beneficially owned directly or indirectly by all directors and
certain executive officers of the Company and all directors and
executive officers of the Company as a group at November 1, 1998,
are as follows:
Shares of Peoples Energy
Common Stock Beneficially
Name Owned at November 1, 1998 (1)
Donald M. Field* 19,467 (2)(3)(4)
James Hinchliff* 34,918 (2)(3)
James M. Luebbers* 6,355 (2)(3)
Thomas M. Patrick* 26,763 (2)(3)
Richard E. Terry* 90,724 (2)(3)
All directors and officers of the Company
as a group, including those named above
(13 in number) 292,122 (1)(2)(3)
* Director of the Company.
(1) The total of 292,122 shares held by all directors and
executive officers as a group is less than one percent of
Peoples Energy's outstanding common stock. Unless otherwise
indicated, each individual has sole voting and investment
power with respect to the shares of common stock attributed to
him in the table. Includes shares held in Peoples Energy's
Capital Accumulation Plan as of July 31, 1998, the most recent
practical date available.
(2) Includes shares that the following have a right to acquire
within 60 days following November 1, 1998, through the
exercise of stock options granted under the Long-Term
Incentive Compensation Plan of Peoples Energy: Messrs. Field
, 9,300; Hinchliff, 9,300; Luebbers, 3,600; Patrick,
11,300; Terry, 33,700; and all executive officers of the
Company, as a group, 117,300.
(3) Includes shares of restricted stock awarded under the Long-
Term Incentive Compensation Plan of Peoples Energy, the
restrictions on which had not lapsed at November 1, 1998, as
follows: Messrs. Field, 9,300; Hinchliff, 9,300;
Luebbers, 3,600;Patrick, 11,300; Terry, 33,700; and all
executive officers as a group, 117,300. Owners of shares of
restricted stock have the right to vote such shares and to
receive dividends thereon, but have no investment power with
respect to such shares until the restrictions thereon lapse.
(4) Shared voting and investment power for 480 shares hold in joint
tenancy with spouse.
CHANGES IN CONTROL
None.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
None.
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON
FORM 8-K
(a) 1. Financial
Statements: Page
See Part II, Item 8. 17
2. Financial Statement Schedule:
Schedule
Number
VIII Valuation and Qualifying Accounts 44
3. Exhibits:
See Exhibit Index on page 46.
(b) Reports on Form 8-K filed during the final quarter of fiscal
year 1998:
None
<TABLE>
<CAPTION>
Schedule VIII
North Shore Gas Company and Subsidiary Companies
VALUATION AND QUALIFYING ACCOUNTS
(Thousands)
Column A Column B Column C Column D Column E
Additions Deductions
Charged Charges for the
Balance to costs purpose for which the Balance
at beginning and reserves or deferred at end of
Description of period expenses credits were created period
Fiscal Year Ended September 30, 1998
<S> <C> <C> <C> <C>
RESERVES (deducted from assets in balance sheet):
Uncollectible items $ 898 $717 $ 910 $ 705
Fiscal Year Ended September 30, 1997
RESERVES (deducted from assets in balance sheet):
Uncollectible items $ 932 $839 $ 873 $ 898
Fiscal Year Ended September 30, 1996
RESERVES (deducted from assets in balance sheet):
Uncollectible items $ 698 $801 $ 567 $ 932
</TABLE>
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the
Securities Exchange Act of 1934, as amended, the registrant has
duly caused this report to be signed on its behalf by the
undersigned, thereunto duly authorized.
NORTH SHORE GAS COMPANY
Date: November 25, 1998 By: /s/ RICHARD E. TERRY
Richard E. Terry
Chairman of the Board and Chief
Executive Officer
Pursuant to the requirements of the Securities Exchange Act of
1934, as amended, this report has been signed below by the
following persons on behalf of the registrant and in the capacities
indicated on November 25, 1998.
/s/ RICHARD E. TERRY Chairman of the Board and Chief Executive
Richard E. Terry Officer and Director
(Principal Executive Officer)
/s/ JAMES M. LUEBBERS Vice President and Controller and Director
James M. Luebbers (Principal Financial and Accounting Officer)
/s/ DONALD M. FIELD Director
Donald M. Field
/s/ JAMES HINCHLIFF Director
James Hinchliff
/s/ THOMAS M. PATRICK Director
Thomas M. Patrick
North Shore Gas Company and Subsidiary Companies
EXHIBIT INDEX
(a) The exhibits listed below are filed herewith and made a part
hereof:
Exhibit
Number Description of Document
10(a) U.S. Shippers Service Agreement between North Shore
and Northern Border Pipeline Company, dated August 14, 1997.
10(b) Transportation Rate Schedule FTS Agreement between
North Shore and Natural Gas Pipeline Company of America,
dated January 15, 1998.
10(c) FTS-1 Service Agreement between North Shore and ANR
Pipeline Company, dated May 28, 1998.
12 Statement re: Computation of Ratio of Earnings to
Fixed Charges.
21 Subsidiaries of the Registrant.
23 Arthur Andersen LLP consent to incorporation by
reference in Registration Statement No. 33-60256
27 Financial Data Schedule
(b)Exhibits listed below have been filed heretofore with the
Securities and Exchange Commission pursuant to the Securities
Act of 1933, as amended, and/or the Securities Exchange Act of
1934, as amended, and are incorporated herein by reference.
The file number and exhibit number of each such exhibit are
stated in the description of such exhibits.
3(c) Articles of Incorporation of the Registrant, as
amended on April 24, 1995 (Registrant Form 10-K
for the fiscal year ended September 30, 1995,
Exhibit 3(b)).
4(a) Indenture, dated as of April 1, 1955, from the Company
to Continental Bank, National Association, as Trustee;
Third Supplemental Indenture, dated as of December
20, 1963 (North Shore - File No. 2-35965, Exhibit 4-
1); Fifth Supplemental Indenture, dated as of
February 1, 1970 (File No. 2-35965, Exhibit 4-2);
Ninth Supplemental Indenture, dated as of December 1,
1987 (Form 10-K for the fiscal year ended September
30, 1987, Exhibit 4); and Tenth Supplemental
Indenture, dated as of November 1, 1990 (Form S-3
Registration Statement No. 33-37332, Exhibit 4b);
Eleventh Supplemental Indenture, dated as of October
1, 1992 (Form 10-K for the fiscal year ended
September 30, 1992, Exhibit 4); and Twelfth
Supplemental Indenture dated as of April 1, 1993
(Form 8-K dated April 23, 1993, Exhibit 4).
North Shore Gas Company and Subsidiary Companies
EXHIBIT INDEX (Continued)
Exhibit
Number
Description of Document
10(g) ETS Service Agreement between the Company and ANR Pipeline
Company, dated September 21, 1994. (Registrant Form
10-K for fiscal year ended September 30, 1995,
Exhibit 10(a)); FSS Service Agreement between the
Company and ANR Pipeline Company, dated September 21,
1994. (Registrant Form 10-K for fiscal year ended
September 30, 1995, Exhibit 10(b)); Transportation
Rate Schedule FTS Agreement between the Company and
Natural Gas Pipeline Company of America, dated
September 22, 1995. (Registrant Form 10-K for fiscal
year ended September 30, 1995, Exhibit 10(c));
Storage Rate Schedule NSS Agreement between the
Company and Natural Gas Pipeline Company of America,
dated October 19, 1995. (Registrant Form 10-K for
fiscal year ended September 30, 1995, Exhibit 10(d));
Transportation Rate Schedule FTS Agreement between
the Company and Natural Gas Pipeline Company of
America, dated October 19, 1995. (Registrant Form 10-
K for fiscal year ended September 30, 1995, Exhibit
10(e)); Storage Rate Schedule DSS Agreement between
the Company and Natural Gas Pipeline Company of
America, dated December 1, 1995. (Registrant Form 10-
K for fiscal year ended September 30, 1995, Exhibit
10(f)); Firm Transportation Service Agreement under
Rate Schedule FTS-1 between the Company and ANR
Pipeline Company, dated as of October 25, 1995.
(Registrant form 10-K for fiscal year ended September
30, 1996, Exhibit 10(g)); Firm Transportation Service
Agreement under Rate Schedule FT-A or FT-G between
the Company and Midwestern Gas Transmission Company,
dated May 1, 1997. (Registrant form 10-K for fiscal
year ended September 30, 1997, Exhibit 10(h)); Firm
Transportation Service Agreement under Rate Schedule
FT-A between the Company and Tennessee Gas Pipeline
Company, dated May 1, 1997. (Registrant form 10-K for
fiscal year ended September 30, 1997, Exhibit 10(i));
Firm Transportation Service Agreement under Rate
Schedule FT-A or FT-GS between the Company and
Midwestern Gas Transmission Company, dated November
1, 1997. (Registrant form 10-K for fiscal year ended
September 30, 1997, Exhibit 10(j)); Firm
Transportation Service Agreement under Rate Schedule
FT-A between the Company and Tennessee Gas Pipeline
Company, dated November 1, 1997. (Registrant form 10-
K for fiscal year ended September 30, 1997, Exhibit
10(k)); Firm Transportation Service Agreement under
Rate Schedule FT-A or FT-GS between the Company and
Midwestern Gas Transmission Company, dated April 1,
1998. (Registrant form 10-K for fiscal year ended
September 30, 1997, Exhibit 10(l)); Firm
Transportation Service Agreement under Rate Schedule
FT-A between the Company and Tennessee Gas Pipeline
Company, dated April 1, 1998. (Registrant form 10-K
for fiscal year ended September 30, 1997, Exhibit
10(m)).
Exhibit 10(a)
Contract #: T1066F
NORTHERN BORDER PIPELINE COMPANY
U.S. SHIPPERS SERVICE AGREEMENT
This Agreement (the "Service Agreement") is made and entered into
at Omaha, Nebraska as of August 14, 1997, by and between
NORTHERN BORDER PIPELINE COMPANY, hereinafter referred to as
"Company" and NORTH SHORE GAS COMPANY, a(n) Illinois
corporation, hereinafter referred to as "Shipper".
WHEREAS, Company's investors and lenders rely on Certificates of
Public Convenience and Necessity granted by the Federal Energy
Regulatory Commission and on the Tariff for the return of and the
return on all funds invested in or loaned to the Company; and
WHEREAS, the transportation of natural gas shall be effectuated
pursuant to Part 157 or Part 284 of the Federal Energy Regulatory
Commission's Regulations; and
WHEREAS, Company recognizes that it will be a condition to the
initial effectiveness of this Service Agreement that,
notwithstanding any other provision of the Tariff or this Service
Agreement, the FERC and all other appropriate federal
governmental authorities and/or agencies in the United States
shall have issued, under terms and conditions acceptable to
Shipper, all final nonappealable authorizations and certificates;
NOW THEREFORE, in consideration of their respective covenants and
agreements hereinafter set out, the parties hereto covenant and
agree as follows:
Article 1 - Basic Receipts
Shipper shall on each day beginning with Shipper's Billing
Commencement Date, as defined in Section 1 of the General Terms
and Conditions of Company's FERC Gas Tariff, be entitled to
tender and, following tender, deliver to Company, at each of
Shipper's Points of Receipt, a quantity of gas not in excess of
the Daily Receipt Quantity for such Point of Receipt for such
day, as defined in such Section 1, and Company shall, on such
day, take receipt of the quantity of gas so tendered and
delivered by Shipper at such Point of Receipt.
Article 2 - Excess Receipts
If Shipper shall desire to tender to Company on any day beginning
with Shipper's Billing Commencement Date, at any of Shipper's
Points of Receipt, a quantity of gas in excess of Shipper's Daily
Receipt Quantity for such Point of Receipt for such day, it shall
notify Company of such desire. If Company in its sole judgment,
determines that it has available the necessary capacity to
receive and transport all or any part of such excess quantity and
make deliveries in respect thereof, and that the performance of
Company's obligations to other Shippers under their Agreements
will not be adversely affected thereby, Company may elect to
receive from Shipper said excess quantity or part thereof, and
shall so notify Shipper. Scheduling of Excess Receipts will be in
accordance with Section 10 of the General Terms and Conditions.
-1-
Contract #: T1066F
NORTHERN BORDER PIPELINE COMPANY
U.S. SHIPPERS SERVICE AGREEMENT
Article 3 - Deliveries
Company shall deliver gas to Shipper at the Point(s) of Delivery
and under the conditions specified in Exhibit A hereto and in
accordance with Section 13 of the General Terms and Conditions.
Article 4 - Payments
Shipper shall make payments to Company in accordance with Rate
Schedules T-1 and OT-1 and the other applicable terms and
provisions of this Service Agreement.
Article 5 - Change in Tariff Provisions
Upon notice to Shipper, Company shall have the right to file with
the Federal Energy Regulatory Commission any changes in the terms
of any of its Rate Schedules, General Terms and Conditions or
Form of Service Agreement as Company may deem necessary, and to
make such changes effective at such times as Company desires and
is possible under applicable law. Shipper may protest any filed
changes before the Federal Energy Regulatory Commission and
exercise any other rights it may have with respect thereto.
Article 6 - Cancellation of Prior Agreements
When this Service Agreement becomes effective, it shall
supersede, cancel and terminate the following Agreements:
- -none-
Article 7 - Term
This Service Agreement shall become effective upon its execution
and shall under all circumstances continue in effect in
accordance with the Tariff for ten (10) years after the Billing
Commencement Date, defined herein as the later of November 1,
1998, or the in-service date of the facilities certificated for
the construction and operation in a Federal Energy Regulatory
Commission proceeding prosecuted by Company in reliance upon this
Agreement, and shall continue in effect thereafter until extended
or terminated in accordance with Section 5 of the Rate Schedule T-
1. Shipper shall give Company not less than six (6) months prior
written notice of Shipper's intent to terminate this Service
Agreement. Service rendered pursuant to this Service Agreement
shall be abandoned upon termination of this Service Agreement.
This Service Agreement shall automatically terminate and be of no
further force and effect unless Shipper shall furnish a proper
security arrangement, in accordance with Subsection 9.1 of Rate
Schedule T-1, to the Company within thirty (30) days after notice
from the Company subsequent to the occurrence of any of the
following events:
-2-
Contract #: T1066F
NORTHERN BORDER PIPELINE COMPANY
U.S. SHIPPERS SERVICE AGREEMENT
The filing by Shipper or its parent of a voluntary petition
in bankruptcy or the entry of a decree or order by a court
having jurisdiction in the premises adjudging the Shipper as
bankrupt or insolvent, or approving as properly filed a
petition seeking reorganization, arrangement, adjustment or
composition of or in respect of the Shipper under the
Federal Bankruptcy Act or any other applicable federal or
state law, or appointing a receiver, liquidator, assignee,
trustee, sequestrator (or other similar official) of the
Shipper or any substantial part of its property, or the
ordering of the winding-up or liquidation of its affairs,
with said order or decree continuing unstayed and in effect
for a period of sixty (60) consecutive days.
A failure by Shipper to pay in full the undisputed amount of
any invoice rendered by Company shall continue for ten (10)
days from the date payment is due.
Termination of this Service Agreement shall not relieve Company
and Shipper of the obligation to correct any Receipt or Delivery
Imbalances hereunder, or Shipper to pay money due hereunder to
Company and shall be in addition to any other remedies that
Company may have.
Article 8 - Applicable Law and Submission to Jurisdiction
This Service Agreement and Company's Tariff, and the rights and
obligations of Company and Shipper thereunder are subject to all
relevant United States lawful statutes, rules, regulations and
orders of duly constituted authorities having jurisdiction.
Subject to the foregoing, this Service Agreement shall be
governed by and interpreted in accordance with the laws of the
State of Nebraska. For purposes of legal proceedings, this
Service Agreement shall be deemed to have been made in the State
of Nebraska and to be performed there, and the Courts of that
State shall have jurisdiction over all disputes which may arise
under this Service Agreement, provided always that nothing herein
contained shall prevent the Company from proceeding at its
election against the Shipper in the Courts of any other state,
Province or country.
At the Company's request, the Shipper shall irrevocably appoint
an agent in Nebraska to receive, for it and on its behalf,
service of process in connection with any judicial proceeding in
Nebraska relating to this Service Agreement. Such service shall
be deemed completed on delivery to such process agent (even if
not forwarded to and received by the Shipper). If said agent
ceases to act as a process agent within Nebraska on behalf of
Shipper, the Shipper shall appoint a substitute process agent
within Nebraska and deliver to the Company a copy of the new
agent's acceptance of that appointment within 30 days.
-3-
Contract #: T1066F
NORTHERN BORDER PIPELINE COMPANY
U.S. SHIPPERS SERVICE AGREEMENT
Article 9 - Successors and Assigns
Any person which shall succeed by purchase, amalgamation, merger
or consolidation to the properties, substantially as an entirety,
of Shipper or of Company, as the case may be, and which shall
assume all obligations under Shipper's Service Agreement of
Shipper or Company, as the case may be, shall be entitled to the
rights, and shall be subject to the obligations, of its
predecessor under Shipper's Service Agreement. Either party to a
Shipper's Service Agreement may pledge or charge the same under
the provisions of any mortgage, deed of trust, indenture,
security agreement or similar instrument which it has executed,
or assign such Service Agreement to any affiliated Person (which
for such purpose shall mean any person which controls, is under
common control with or is controlled by such party). Nothing
contained in this Article 9 shall, however, operate to release
predecessor Shipper from its obligation under its Service
Agreement unless Company shall, in its sole discretion, consent
in writing to such release, which it shall not do unless it
concludes that, on the basis of the facts available to it, such
release is not likely to have a substantial adverse effect upon
other Shippers or other Persons who may become liable to provide
funds to Company to enable it to meet any of its obligations.
Company shall not release any Shipper from its obligations under
its Service Agreement without the written consent of the other
Shippers unless: (a) such release is effected pursuant to an
assignment of obligations by such Shipper, and the assumption
thereof by the assignee, and the terms of such assignment and
assumption render the obligations being assigned and assumed no
more conditional and no less absolute than those at the time
provided therein; and (b) such release is not likely to have a
substantial adverse effect upon Company or the other Shippers.
For the purposes hereof, and without limiting the generality of
the foregoing, any release of any Shipper from its obligations
under its Service Agreement shall be deemed likely to have a
substantial adverse effect upon Company or the other Shippers if
the assignee of such obligations has a credit standing which is
not at least equal to the credit standing of the assignor of such
obligations (credit standings in each case as reflected by the
ratings on outstanding debt securities by Moody's Investors
Service, Standard and Poor's Corporation or another rating
service acceptable to all Shippers to the extent available or by
other appropriate objective measures). Shipper shall, at
Company's request, execute such instruments and take such other
action as may be desirable to give effect to any such assignment
of Company's rights under such Shipper's Service Agreement or to
give effect to the right of a Person whom the Company has
specified pursuant to Section 6 of the General Terms and
Conditions of Company's FERC Gas Tariff as the Person to whom
payment of amounts invoiced by Company shall be made; provided,
however, that: (a) Shipper shall not be required to execute any
such instruments or take any such other action the effect of
which is to modify the respective rights and obligations of
either Shipper or Company under this Service Agreement; and (b)
Shipper shall be under no obligation at any time to determine the
status or amount of any payments which may be due from Company to
any Person whom the Company has specified pursuant to said
Section 6 as the Person to whom payment of amounts invoiced by
Company shall be made.
-4-
Contract #: T1066F
NORTHERN BORDER PIPELINE COMPANY
U.S. SHIPPERS SERVICE AGREEMENT
Article 10 - Loss of Governmental Authority, Gas Supply,
Transportation or Market
Without limiting its other responsibilities and obligations under
this Service Agreement, the Shipper acknowledges that it is
responsible for obtaining and assumes the risk of loss of the
following: (1) gas removal permits, (2) export and import
licenses, (3) gas supply, (4) markets and (5) transportation
upstream and downstream of the Company's pipeline system.
Notwithstanding the loss of one of the items enumerated above,
Shipper shall continue to be liable for payment to the Company of
the transportation charges as provided for in this Service
Agreement.
Article 11 - Other Operating Provisions
(This Article to be utilized when necessary to specify other
operating provisions.)
Article 12 - Exhibit A of Service Agreement, Rate Schedules and
General Terms and Conditions
Company's Rate Schedules and General Terms and Conditions, which
are on file with the Federal Energy Regulatory Commission and in
effect, and Exhibit A hereto are all applicable to this Service
Agreement and are hereby incorporated in, and made a part of,
this Service Agreement. In the event that the terms and
conditions herein are in conflict with the General Terms and
Conditions in Company's FERC Gas Tariff, the terms and conditions
of this Service Agreement are controlling.
IN WITNESS WHEREOF, The parties hereto have caused this Service
Agreement to be duly executed as of the day and year first set
forth above.
ATTEST: NORTHERN BORDER PIPELINE COMPANY
By: Northern Plains Natural Gas Company,
Operator
/s/ Eva Neufeld By: /s/ Robert A. Hill
Assistant Secretary
Title: Vice President
ATTEST: NORTH SHORE GAS COMPANY
_________________________ By: /s/ William E. Morrow
Title: Vice President
-5-
Contract #: T1066F
NORTHERN BORDER PIPELINE COMPANY
U.S. SHIPPERS SERVICE AGREEMENT
EXHIBIT A TO U.S. SHIPPERS SERVICE AGREEMENT
Company: NORTHERN BORDER PIPELINE COMPANY
Company's Address: 1111 South 103rd Street
Omaha, Nebraska 68124-1000
Shipper: NORTH SHORE GAS COMPANY
Attn: Mr. Roulando DeLara
Shipper's Address: 130 E. Randolph Dr., 22nd Floor
Chicago, IL 60601
Maximum Minimum Maximum
Role Maximum Receipt Delivery Receipt Minimum
(Notes Quantity Pressure Pressure Temperature Temperature
Points 1 and 3) (MCF/Day) (PSIG) (PSIG) (F) (F)
Harper, IA RD 40,000 -- -- -- --
TP 40,000 -- -- -- --
PD 40,000 -- 712 -- 32
DD 40,000 -- -- -- --
Iowa City, IA RD 40,000 -- -- -- --
(Secondary- TP 40,000 -- -- -- --
Note 2)
PD 40,000 -- 600 -- 32
DD 40,000 -- -- -- --
Davenport, IA RD 40,000 -- -- -- --
(Secondary- TP 40,000 -- -- -- --
Note 2)
PD 40,000 -- 650 -- 32
DD 40,000 -- -- -- --
Prophetstown,IL RD 40,000 -- -- -- --
(Secondary- TP 40,000 -- -- -- --
Note 2)
PD 40,000 -- 600 -- 32
DD 40,000 -- -- -- --
Troy Grove,IL RD 40,000 -- -- -- --
(Secondary- TP 40,000 -- -- -- --
Note 2)
PD 40,000 -- 750 -- 32
DD 40,000 -- -- -- --
-6-
Contract #: T1066F
NORTHERN BORDER PIPELINE COMPANY
U.S. SHIPPERS SERVICE AGREEMENT
EXHIBIT A TO U.S. SHIPPERS SERVICE AGREEMENT (continued)
Maximum Minimum Maximum
Role Maximum Receipt Delivery Receipt Minimum
(Notes Quantity Pressure Pressure Temperature Temperature
Points 1 and 3) (MCF/Day) (PSIG) (PSIG) (F) (F)
Minooka, IL RD 40,000 -- -- -- --
(Secondary- TP 40,000 -- -- -- --
Note2)
PD 40,000 -- 550 -- 32
DD 40,000 -- -- -- --
Channahon, IL RD 40,000 -- -- -- --
(Secondary- TP 40,000 -- -- -- --
Note 2)
PD 40,000 -- 850 -- 32
DD 40,000 -- -- -- --
Joliet, IL RD 40,000 -- -- -- --
(Secondary- TP 40,000 -- -- -- --
Note 2)
PD 40,000 -- 850 -- 32
DD 40,000 -- -- -- --
Manhattan, IL RD 40,000 -- -- -- --
TP 40,000 -- -- -- --
PD 40,000 -- 858 -- 32
DD 40,000 -- -- -- --
Total Maximum
Receipt Quantity 40,000 MCF
Note 1: The point role will be either PR for physical receipts,
RD for receipt by displacement, TP for transfer points,
PD for physical deliveries, and DD for delivery by
displacement.
Note 2: Should nominations at secondary receipt and delivery
points be received which exceed available capacity,
volumes will be scheduled in accordance with Northern
Border's nomination and scheduling procedures.
-7-
Contract #: T1066F
NORTHERN BORDER PIPELINE COMPANY
U.S. SHIPPERS SERVICE AGREEMENT
EXHIBIT A TO U.S. SHIPPERS SERVICE AGREEMENT (continued)
Note 3:For receipt or delivery of gas by displacement, Company
cannot and does not have an obligation to physically
deliver or receive gas at these points. Volumes will be
delivered or received at these point(s) only to the
extent that corresponding equal or greater volumes are
received or delivered by other parties at these points on
the same day. These corresponding volumes will be used to
displace volumes nominated for delivery or receipt by
Shipper.
Note 4:Gas volumes which are nominated/scheduled at a sub
primary receipt or delivery point(s) have priority over
gas volumes of shipper utilizing such point on a
corresponding basis as a secondary receipt or delivery
point. Shipper's rights and obligations regarding the use
of sub primary points are governed by Subsection 17.1 of
the General Terms and Conditions of the Tariff.
This Exhibit A. is made and entered into as of August 14,
1997. On the effective date designated by the Federal Energy
Regulatory Commission, it shall supersede the Exhibit A dated as
of N/A .
The effective date of this Exhibit A is August 14, 1997 .
ATTEST: NORTHERN BORDER PIPELINE COMPANY
By: Northern Plains Natural Gas Company,
Operator
/s/ Eva Neufeld By: /s/ Robert A. Hill
Assistant Secretary
Title: Vice President
ATTEST: NORTH SHORE GAS COMPANY
__________________________ By: /s/ William E. Morrow
Title: Vice President
-8-
Amendment #2
#2295
AMENDMENT TO PRECEDENT AGREEMENT
BETWEEN
NORTHERN BORDER PIPELINE COMPANY
AND
NORTH SHORE GAS COMPANY
DATED AUGUST 10, 1995
This Amendment is entered into as of this 15th day of July,
1997, by and between NORTHERN BORDER PIPELINE COMPANY, and NORTH
SHORE GAS COMPANY,
The parties hereby agree as follows:
Article 5(iii) of the Precedent Agreement concerning
termination rights and required notice, shall be amended to
read as follows:
STRIKE "July 1, 1997" and substitute
"August 1, 1997"; and
STRIKE "July 15, 1997" and substitute
"August 15, 1997"
IN WITNESS WHEREOF, the parties hereto have caused this Amendment
to be duly executed as of the day and year set forth above.
NORTHERN BORDER PIPELINE COMPANY
By: Northern Plains Natural Gas Company,
Operator
By: /s/ Robert A. Hill
Title: Vice President
ATTEST: NORTH SHORE GAS COMPANY
/s/ Thomas M. Patrick
/s/ Thomas W. Harwig By: Thomas M. Patrick
Assistant Secretary
Title: Executive Vice President
ATTEST:
___________________________ By: ___________________________
Title:_________________________
Exhibit 10(b)
Contract .No. 113421
NATURAL GAS PIPELINE COMPANY OF AMERICA (Natural)
TRANSPORTATION RATE SCHEDULE FTS AGREEMENT DATED January 15, 1998
UNDER SUBPART G OF PART 284 OF THE FERC'S REGULATIONS
1. SHIPPER is: NORTH SHORE GAS COMPANY, a LOCAL DISTRIBUTION COMPANY.
2. (a) MDQ totals: 8,929 MMBTU per day.
(b) Service option selected (check any or all):
[ ] LN [ ] SW [ ] NB
3. TERM: Service under FTS Agreement No. 113421 shall commence on the
next calendar day following the termination of North Shore's FTS
Agreement No. 110522 dated September 22, 1995, and shall continue
through the last day of the month in which twelve complete calendar
months of service have been provided under the FTS Agreement.
4. Service will be ON BEHALF OF: [X ] Shipper or [ ] Other:.
5. The ULTIMATE END USERS are customers within any state in the
continental U.S.; or (specify state)
_______________________________________________________________
6. [ ] This Agreement supersedes and cancels a __________ Agreement
dated __________
[ ] Capacity rights for this Agreement were released from Natural's
Transportation Rate Schedule Agreement (KT #) dated and are subject to
any recall/return provisions in Natural's Capacity Release Package ID
#.
[X] Service and reservation charges commence the latter of:
(a) December 01, 1998, and
(b) the date capacity to provide the service hereunder is
available on Natural's System.
[ ] Other: _______________________________________________________
7. SHIPPER'S ADDRESSES NATURAL'S ADDRESSES
General Correspondence:
NORTH SHORE GAS COMPANY NATURAL GAS PIPELINE COMPANY OF AMERICA
WILLIAM MORROW ATTENTION: GAS TRANSPORTATION SERVICES
130 E. RANDOLPH DR., 23RD FLOOR 3200 SOUTHWEST FREEWAY 77027-7523
CHICAGO, IL 60601-6207 P.O. BOX 283 77001-0283
HOUSTON, TEXAS
Statements/Invoices/Accountinq Related Materials:
NORTH SHORE GAS COMPANY NATURAL GAS PIPELINE COMPANY OF AMERICA
WILLIAM MORROW ATTENTION: ACCOUNT SERVICES
130 E. RANDOLPH DR., 23RD FLOOR 701 EAST 22ND STREET
CHICAGO, IL 60601-6207 LOMBARD, ILLINOIS 60148
Payments:
NATURAL GAS PIPELINE COMPANY OF AMERICA
P. O. BOX 2910
CAROL STREAM, ILLINOIS 60132-2910
FOR WIRE TRANSFER OR ACH:
DEPOSITORY INSTITUTION: CITIBANK N.A.
ABA ROUTING #: 021000089
ACCOUNT #: 4067-6195
8. The above stated Rate Schedule, as revised from time to time, controls this
Agreement and is incorporated herein. The attached Exhibits A, B, and
C (for firm service only) are a part of this Agreement. NATURAL AND
SHIPPER ACKNOWLEDGE THAT THIS AGREEMENT IS SUBJECT TO THE PROVISIONS
OF NATURAL'S FERC GAS TARIFF AND APPLICABLE FEDERAL LAW. TO THE EXTENT
THAT STATE LAW IS APPLICABLE, NATURAL AND SHIPPER EXPRESSLY AGREE THAT
THE LAWS OF THE STATE OF ILLINOIS SHALL GOVERN THE VALIDITY,
CONSTRUCTION, INTERPRETATION AND EFFECT OF THIS CONTRACT, EXCLUDING,
HOWEVER, ANY CONFLICT OF LAWS RULE WHICH WOULD APPLY THE LAW OF
ANOTHER STATE. This Agreement states the entire agreement between the
parties and no waiver, representation, or agreement shall affect this
Agreement unless it is in writing. Shipper shall provide the actual
end user purchaser name(s) to Natural if Natural must provide them to
FERC.
AGREED TO BY:
NATURAL GAS PIPELINE COMPANY OF AMERICA NORTH SHORE GAS COMPANY
"Natural" "Shipper"
By: /s/ Stephen G. Weiman By: /s/ William E. Morrow
Name: Stephen G. Weiman Name: William E. Morrow
Title: Senior Vice President Title: Vice President
113421
EXHIBIT A
DATED: January 15, 1998
EFFECTIVE DATE: December 01, 1998
COMPANY: NORTH SHORE GAS COMPANY
CONTRACT: 113421
RECEIPT POINT/S
County/Parish PIN MDQ
Name/Location Area State No. Zone (MMBtu/d)
PRIMARY RECEIPT POINT/S
1. NGPL/TPC GAGE GAGE NE 2900 07 8,929
INTERCONNECT WITH TRAILBLAZER PIPELINE
IN SEC. 15-T4N-R6E, GAGE COUNTY,
NEBRASKA.
SECONDARY RECEIPT POINT/S
All secondary receipt point, and the related priorities and volumes, as
provided under the Tariff provisions governing this Agreement.
RECEIPT PRESSURE, ASSUMED ATMOSPHERIC PRESSURE
Natural gas to be delivered to Natural at the Receipt Point/s shall be
at a delivery pressure sufficient to enter Natural's pipeline facilities at
the pressure maintained from time to time, but Shipper shall not deliver
gas at a pressure in excess of the Maximum Allowable Operating Pressure
(MAOP) stated for each Receipt Point. The measuring party shall use or
cause to be used an assumed atmospheric pressure corresponding to the
elevation at such Receipt Point/s.
RATES
Except as provided to the contrary in any written agreement(s) between
the parties in effect during the term hereof, Shipper shall pay Natural the
maximum rate and all other lawful charges as specified in Natural's
applicable rate schedule.
FUEL GAS AND GAS LOST AND UNACCOUNTED FOR PERCENTAGE (%)
Shipper will be assessed the applicable percentage for Fuel Gas and Gas
Lost and Unaccounted For.
TRANSPORTATION OF LIQUIDS
Transportation of liquids may occur at permitted points identified in
Natural's current Catalog of Receipt and Delivery Points, but only if the
parties execute a separate liquids agreement.
A-1
EXHIBIT B
DATED January 15, 1998
EFFECTIVE DATE: December 01, !998
COMPANY: NORTH SHORE GAS COMPANY
CONTRACT: 113421
RECEIPT POINT/S
County/Parish PIN MDQ
Name/Location Area State No. Zone (MMBtu/d)
PRIMARY DELIVERY POINT/S
1. NO SHORE/NGPL GRAYSLAKE LAKE LAKE IL 1 06 8,929
INTERCONNECT WITH NORTH SHORE GAS
COMPANY LOCATED IN SEC. 12-T44N-R10E,
LAKE COUNTY, ILLINOIS.
SECONDARY DELIVERY POINT/S
All secondary delivery points, and the related priorities and volumes,
as provided under the Tariff provisions governing this Agreement.
DELIVERY PRESSURE, ASSUMED ATMOSPHERIC PRESSURE
Natural gas to be delivered by Natural to Shipper, or for Shipper's
account, at the Delivery Point/s shall be at the pressure available in
Natural's pipeline facilities from time to time. The measuring party shall
use or cause to be used an assumed atmospheric pressure corresponding to
the elevation at such Delivery Point/s.
B-1
EXHIBIT C
DATED January 15, 1998
EFFECTIVE DATE: December 01, 1998
COMPANY: NORTH SHORE GAS COMPANY
CONTRACT: 113421
Pursuant to Natural's tariff, an MDQ exists for each primary
transportation path segment and direction under the Agreement. Such MDQ is
the maximum daily quantity of gas which Natural is obligated to transport
on a firm basis along a primary transportation path segment.
A primary transportation path segment is the path between a primary
receipt, delivery, or node point and the next primary receipt, delivery, or
node point. A node point is the point of interconnection between two or
more of Natural's pipeline facilities.
A segment is a section of Natural's pipeline system designated by a
segment number whereby the Shipper under the terms of their agreement based
on the points within the segment identified on Exhibit C has throughput
capacity rights.
The segment numbers listed on Exhibit C reflect this Agreement's path
corresponding to Natural's most recent Pipeline System Map which identifies
segments and their corresponding numbers. All information provided in this
Exhibit C is subject to the actual terms and conditions of Natural's
Tariff.
C-1
EXHIBIT C
DATED January 15, 1998
EFFECTIVE DATE: December 01, 1998
COMPANY: NORTH SHORE GAS COMPANY
CONTRACT: 113421
Segment Upstream Forward/Backward Flow Through
Number Segment Haul (Contractual) Capacity
12 0 F 0
13 12 F 8,929
14 13 F 8,929
29 14 F 8,929
37 29 F 8,929
39 37 F 8,929
C-2
Exhibit 10(c)
Date: May 28, 1998 Contract No.: 101471
FTS - 1 SERVICE AGREEMENT
This AGREEMENT is entered into by ANR PIPELINE COMPANY
(Transporter) and
NORTH SHORE GAS COMPANY (Shipper).
WHEREAS, Shipper has requested Transporter to transport Gas on
its behalf and Transporter represents that it is willing to
transport Gas under the terms and conditions of this Agreement.
NOW, THEREFORE, Transporter and Shipper agree that the terms
below, together with the terms and conditions of Transporter's
applicable Rate Schedule and General Terms and Conditions of
Transporter's FERC Gas Tariff constitute the transportation
service to be provided and the rights and obligations of Shipper
and Transporter.
1. AUTHORITY FOR TRANSPORTATION SERVICE:
(284B = Section 311; 284G = Blanket)
284G
2. RATE SCHEDULE: Firm Transportation Service (FTS - 1)
3. CONTRACT QUANTITIES:
Primary Route- See Exhibit attached hereto
Such contract quantities shall be reduced for scheduling
purposes, but not for billing purposes, by the Contract
Quantities that Shipper has released through Transporter's
capacity release program for the period of any release.
4. TERM OF AGREEMENT:
Nov 01, 1998 to
Oct 31, 2003
5. RATES:
Maximum rates, charges, and fees shall be applicable for the
entitlements and quantities delivered pursuant to this
Agreement unless Transporter has advised Shipper in writing
or by GEMStm that it has agreed otherwise.
1
Date: May 28, 1998 Contract No.: 101471
It is further agreed that Transporter may seek authorization
from the Commission and/or other appropriate body at any
time and from time to time to change any rates, charges or
other provisions in the applicable Rate Schedule and General
Terms and Conditions of Transporter's FERC Gas Tariff, and
Transporter shall have the right to place such changes in
effect in accordance with the Natural Gas Act. This
Agreement shall be deemed to include such changes and any
changes which become effective by operation of law and
Commission order. Nothing contained herein shall be
construed to deny Shipper any rights it may have under the
Natural Gas Act, including the right to participate fully in
rate or other proceedings by intervention or otherwise to
contest changes in rates in whole or in part.
6. INCORPORATION BY REFERENCE:
The provisions of Transporter's applicable Rate Schedule and
the General Terms and Conditions of Transporter's FERC Gas
Tariff are specifically incorporated herein by reference and
made a part hereof.
7. NOTICES:
All notices can be given by telephone or other electronic
means, however, such notices shall be confirmed in writing
at the addresses below or through GEMStm. Shipper and
Transporter may change the addresses below by written notice
to the other without the necessity of amending this
Agreement:
TRANSPORTER:
ANR PIPELINE COMPANY
500 Renaissance Center
Detroit, Michigan 48243
Attentions: Gas Control (Nominations)
Volume Management (Statements)
Cash Control (Payments)
Customer Administration (All Other Matters)
2
Date: May 28, 1998 Contract No.: 101471
SHIPPER:
NORTH SHORE GAS COMPANY
C/O PEOPLES GAS LIGHT & COKE
130 E RANDOLPH 22ND FLR.
CHICAGO, IL 60601-6207
Attention: JEROME SLECHTA
Telephone: 312-240-4362
Fax: 312-240-4211
INVOICES AND STATEMENTS:
NORTH SHORE GAS COMPANY
C/O PEOPLES GAS LIGHT & COKE
130 E RANDOLPH 23RD FLR.
CHICAGO, IL 60601-6207
Attention: PATTY GARCIA
Telephone: 312-240-4275
Fax: 312-240-3865
NOMINATIONS:
NORTH SHORE GAS COMPANY
C/O PEOPLES GAS LIGHT & COKE
130 E RANDOLPH 22ND FLR.
CHICAGO, IL 60601-6207
Attention: JEROME SLECHTA
Telephone: 312-240-4362
Fax: 312-240-4211
3
Date: May 28, 1998 Contract No.: 101471
ALL OTHER MATTERS:
NORTH SHORE GAS COMPANY
C/O PEOPLES GAS LIGHT & COKE
130 E RANDOLPH 22ND FLR.
CHICAGO, IL 60601-6207
Attention: JEROME SLECHTA
Telephone: 312-240-4362
Fax: 312-240-4211
8 FURTHER AGREEMENT:
A. For all quantities of gas transported on the Primary
Route up to the Primary Route MDQ under this Agreement,
Shipper will be charged a Reservation Charge of $0.10
per dth on a 100% load factor basis inclusive of
Volumetric Buyout/Buydown, Dakota and Transition Costs.
In addition, for all quantities of gas transported,
Shipper will be charged the Minimum Commodity Charge,
ACA and fuel. Shipper shall not be responsible for GRI
surcharges, unless and to the extent that Transporter
is required to collect and/or remit such charges to
GRI.
B. All quantities associated with Secondary Receipt
Points, Secondary Delivery Points and Secondary Routes
under this Agreement will be Maximum Tariff Rates plus
all other related fees, surcharges and fuel unless
mutually agreed to otherwise.
C. The term of service under this Agreement shall begin on
the later of November 1, 1998 or the date on which the
Racine Lateral, as defined in the Letter Agreements
dated September 25, 1997 and November 4, 1997, is
placed into service.
D. Consistent with provisions of its Tariff, Transporter
is willing to contract on Shipper's behalf for capacity
required on third party transporters, or for other
services to effectuate Shipper's receipt of gas on
third party facilities and delivery of gas to
Transporter's facilities.
Shipper has advised Transporter of its desire to have
Transporter act in such a capacity.
4
Date: May 28, 1998 Contract No.: 101471
Shipper agrees to pay all charges related to such
third party transportation arrangements pursuant to
Transporter's Tariff.
E. To the extent Shipper desires to utilize
receipt/delivery points pursuant to Part 284B (Section
311 of the NGPA and Section 284.102 of the Commission's
regulations), Shipper must execute a separate agreement
with Transporter and Shipper must also certify that the
transportation of gas will be on behalf of either an
"intrastate pipeline" or a "local distribution
company".
9. OPERATIONAL FLOW ORDERS:
Shipper hereby guarantees to Transporter that each contract
it has entered into in connection with the Gas to be
transported under this Agreement contains a provision that
permits Transporter to issue an effective Operational Flow
Order pursuant to Section 8 of the General Terms and
Conditions, of Transporter's FERC Gas Tariff.
IN WITNESS WHEREOF, the parties hereto have caused this Agreement
to be signed by their respective Officers or Representatives
there unto duly authorized to be effective as of the date stated
above.
SHIPPER: NORTH SHORE GAS COMPANY
By: /s/ William E. Morrow
Title: Vice President
Date: June 29, 1998
TRANSPORTER: ANR PIPELINE COMPANY
By: /s/ Richard H. Leehr
Title: Vice President
Date: 7-16-98
5
PRIMARY ROUTE EXHIBIT Contract No: 101471
To Agreement Between Rate Schedule FTS-1
ANR PIPELINE COMPANY (Transporter) Contract Date: May 28, 1998
AND NORTH SHORE GAS COMPANY (Shipper) Amendment Date:
Receipt Delivery Annual Winter Summer
Number Number MDQ MDQ MDQ
Name Name (DTH) (DTH) (DTH)
246067 40000 0 0
WILL COUNTY INT RACINE LATERAL
DELIVERY POINT
FROM: Nov 01, 1998 TO: Oct 31, 2003
1
<TABLE>
<CAPTION>
Exhibit 12
North Shore Gas Company and Subsidiary Companies
Statement Re: Computation of Ratio of Earnings to Fixed Charges
(Dollars in Thousands)
Fiscal years ended September 30,
1998 1997 1996 1995 1994
<S> <C> <C> <C> <C> <C>
Net Income Before Preferred
Stock Dividends $ 12,986 $ 14,814 $ 16,347 $ 9,048 $ 10,378
Add - Income Taxes 8,124 9,229 10,154 4,859 5,087
Fixed Charges (see below) 5,190 5,068 5,741 7,196 6,648
Earnings $ 26,300 $ 29,111 $ 32,242 $ 21,103 $ 22,113
Fixed Charges:
Interest on Long-Term Debt $ 4,625 $ 4,627 $ 4,937 $ 5,905 $ 6,326
Other Interest 565 441 804 1,291 322
Total Fixed Charges $ 5,190 $ 5,068 $ 5,741 $ 7,196 $ 6,648
Ratio of Earnings to Fixed Charges 5.07 5.74 5.62 2.93 3.33
</TABLE>
Exhibit 21
North Shore Gas Company
Subsidiaries of the Registrant
Date of State of
Company Incorporation Incorporation
North Shore Exploration Company 04/25/73 Illinois
Exhibit 23
ARTHUR ANDERSEN LLP
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the
incorporation by reference of our report, dated November 2,
1994, included in this Form 10-K, into North Shore Gas
Company's previously filed Registration Statement File No.
33-60256.
/s/ Arthur Andersen LLP
ARTHUR ANDESEN LLP
Chicago, Illinois,
November 25, 1998
<TABLE> <S> <C>
<ARTICLE> UT
<LEGEND>
THE SCHEDULE CONTAINS SUMMARY INFORMATION EXTRACTED FROM CONSOLIDATED
STATEMENTS OF INCOME, CONSOLIDATED BALANCE SHEETS, AND CONSOLIDATED
STATEMENTS OF CASH FLOWS, AND QUALIFIED IN ITS ENTIRETY BY REFERENCE TO
SUCH FINANCIAL STATEMENTS.
</LEGEND>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> SEP-30-1998
<PERIOD-START> OCT-01-1997
<PERIOD-END> SEP-30-1998
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 196,897
<OTHER-PROPERTY-AND-INVEST> 22
<TOTAL-CURRENT-ASSETS> 26,719
<TOTAL-DEFERRED-CHARGES> 3,730
<OTHER-ASSETS> 23,895
<TOTAL-ASSETS> 251,263
<COMMON> 24,757
<CAPITAL-SURPLUS-PAID-IN> 0
<RETAINED-EARNINGS> 70,020
<TOTAL-COMMON-STOCKHOLDERS-EQ> 94,777
0
0
<LONG-TERM-DEBT-NET> 64,604
<SHORT-TERM-NOTES> 0
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 0
<LONG-TERM-DEBT-CURRENT-PORT> 0
0
<CAPITAL-LEASE-OBLIGATIONS> 0
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 91,882
<TOT-CAPITALIZATION-AND-LIAB> 251,263
<GROSS-OPERATING-REVENUE> 144,206
<INCOME-TAX-EXPENSE> 7,967
<OTHER-OPERATING-EXPENSES> 118,320
<TOTAL-OPERATING-EXPENSES> 126,287
<OPERATING-INCOME-LOSS> 17,919
<OTHER-INCOME-NET> 257
<INCOME-BEFORE-INTEREST-EXPEN> 18,176
<TOTAL-INTEREST-EXPENSE> 5,190
<NET-INCOME> 12,986
0
<EARNINGS-AVAILABLE-FOR-COMM> 12,986
<COMMON-STOCK-DIVIDENDS> 13,960
<TOTAL-INTEREST-ON-BONDS> 4,625
<CASH-FLOW-OPERATIONS> 30,668
<EPS-PRIMARY> 0
<EPS-DILUTED> 0
</TABLE>
