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UNITED
STATES
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SECURITIES
AND EXCHANGE COMMISSION
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Washington,
D.C. 20549
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FORM
10-K
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(Mark
One)
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R
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ANNUAL
REPORT PURSUANT TO SECTION 13 OR 15(d) OF
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THE
SECURITIES EXCHANGE ACT OF 1934
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For
the fiscal year ended SEPTEMBER 30, 2006
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OR
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£
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TRANSITION
REPORT PURSUANT TO SECTION 13 OR 15(d)
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OF
THE SECURITIES EXCHANGE ACT OF 1934
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Commission
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Exact
Name of Registrant as Specified in Charter, State of
Incorporation,
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IRS
Employer
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File
Number
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Address
of Principal Executive Office and Telephone Number
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Identification
Number
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1-5540
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PEOPLES
ENERGY CORPORATION
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36-2642766
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2-26983
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THE
PEOPLES GAS LIGHT AND COKE COMPANY
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36-1613900
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2-35965
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NORTH
SHORE GAS COMPANY
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36-1558720
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(an
Illinois Corporation)
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130
East Randolph Drive, 24
th
Floor
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Chicago,
Illinois 60601-6207
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Telephone
(312) 240-4000
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Securities
registered pursuant to Section 12(b) of the Act:
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Name
of each exchange
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Title
of Each Class
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on
which registered
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Peoples
Energy Corporation
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New
York Stock Exchange,
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Common
Stock, without par value
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Chicago
Stock Exchange,
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and
Pacific Exchange
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Indicate
by check mark whether the registrants (1) have 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 shorter period that the registrant
was required to file such reports), and (2) have been subject to
such
filing requirements for the past 90 days. Yes
R
No
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Indicate
by check mark if disclosure of delinquent filers pursuant to Item
405 of
Regulation S-K (§229.405 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.
R
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This
combined Form 10-K is separately filed by Peoples Energy Corporation,
The
Peoples Gas Light and Coke Company, and North Shore Gas Company.
Information contained herein relating to any individual company is
filed
by such company on its own behalf. Each company makes no representation
as
to information relating to the other companies.
The
Peoples Gas Light and Coke Company and North Shore Gas Company meet
the
conditions set forth in General Instruction I(1)(a) and (b) of Form
10-K
and are therefore filing this Form 10-K with the reduced disclosure
format
permitted by General Instruction
I(2).
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Documents
Incorporated by Reference
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Document
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Part
of Form 10-K
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Peoples
Energy Corporation
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Company's
Notice of Annual Meeting and Proxy Statement or an amendment to this
Form
10-K filed within 120 days of the end of the Company's fiscal
year
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Part
III
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The
Peoples Gas Light and Coke Company
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None
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North
Shore Gas Company
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None
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WHERE
TO FIND MORE INFORMATION
Peoples
Energy Corporation makes available through its Web site, free of charge, its
annual report on Form 10-K, quarterly reports on Form 10-Q, current reports
on
Form 8-K, and amendments to those reports filed or furnished pursuant to Section
13(a) of the Exchange Act as soon as reasonably practicable after it
electronically files such material with, or furnishes it to, the Securities
and
Exchange Commission. The Company's Web site address is http://
www.PeoplesEnergy.com
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Peoples
Energy Corporation - Glossary of Terms
Throughout
this document, Peoples Energy Corporation, together with its consolidated
subsidiaries, may be referred to as "Peoples Energy," "the Company,"
"management," "we," "us" or "our." References to Peoples Gas and to North Shore
Gas refer to The Peoples Gas Light and Coke Company and North Shore Gas Company,
respectively. References to the Registrants mean Peoples Energy, Peoples Gas
and
North Shore Gas, unless the context clearly indicates otherwise. Additional
abbreviations or acronyms used in this filing are defined below:
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Definitions
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Basin
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A
geological feature in the earth’s subsurface that is composed of
sedimentary rock and geological structures where oil and natural
gas
prospect and fields are potentially found.
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Development
well
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Well
drilled within the proved area of an oil or natural gas field to
the depth
of a stratigraphic horizon known to be productive.
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Dry
hole
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Exploratory
or development well that does not produce oil or gas in commercial
quantities.
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Exploratory
well
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Well
drilled to find and produce oil or gas in an unproved area, to find
a new
reservoir in a field previously found to be productive or in another
reservoir, or to extend a known reservoir.
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Field
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Area
consisting of a single reservoir or multiple reservoirs all grouped
on or
related to the same geological structural feature or stratigraphic
condition.
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Gross
acres or gross wells
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The
total acres or wells in which a working interest is
owned.
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Heating
degree days
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A
unit of measure used to represent each degree that the mean temperature
for a 24-hour period is less than 65 degrees
Fahrenheit.
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Lease
operating expenses
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Expenses
incurred to operate the wells and equipment on a producing
lease.
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Mark-to-market
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A
re-valuation of an asset or liability to its current fair
value.
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Multiple
completion
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The
completion of a well in more than one producing formation at multiple
depths.
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Net
acreage and net wells
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Obtained
by multiplying gross acreage and gross wells by the Company’s working
interest percentage in the properties.
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Proved
developed reserves
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Portion
of proved reserves that can be expected to be recovered through existing
wells with existing equipment and operating methods.
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Proved
reserves
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Estimated
quantities of natural gas, natural gas liquids and crude oil which
geological and engineering data demonstrate, with reasonable certainty,
can be recovered in future years from known reservoirs under existing
economic and operating conditions. Reservoirs are considered proved
if
shown to be economically producible by either actual production or
conclusive formation tests.
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Proved
undeveloped reserves
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Portion
of proved reserves that can be expected to be recovered from new
wells on
undrilled proved acreage, or from existing wells where a relatively
major
expenditure is required for completion.
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Regulatory
asset/liability
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An
asset or liability recorded by the Company as a result of certain
costs or
revenues qualifying for regulatory treatment and deferred until recovered
or refunded through rates.
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Reservoir
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A
porous, permeable sedimentary rock formation containing quantities
of oil
and/or gas enclosed or surrounded by layers of less permeable or
impervious rock.
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Weather
normalized
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Usage,
revenue or operating income excluding the estimated effects of deviations
from normal weather.
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Working
Interest
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The
ownership interest under an oil and gas lease after accounting for
the
interests reserved for the lessor or landowner.
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Referenced
Accounting Standards
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APB
Opinion No. 25
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Accounting
for Stock Issued to Employees
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EITF
99-02
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Accounting
for Weather Derivatives
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FIN
47
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Accounting
for Conditional Asset Retirement Obligations
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FIN
48
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Accounting
for Uncertainty in Income Taxes - an Interpretation of FASB Statement
No.
109
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FSP
No. 106-2
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Accounting
and Disclosure Requirements Related to the Medicare Prescription
Drug
Improvement and Modernization Act of 2003
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SAB
No. 108
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Considering
the Effects of Prior Year Misstatements When Quantifying Misstatements
in
Current Year Financial Statements
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SFAS
No. 5
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Accounting
for Contingencies
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SFAS
No. 71
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Accounting
for the Effects of Certain Types of Regulation
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SFAS
No. 88
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Employer’s
Accounting for Settlements and Curtailments of Defined Benefit Pension
Plans and for Termination Benefits
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SFAS
No. 123
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Accounting
for Stock-Based Compensation
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SFAS
No. 123 (R)
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Share-based
Payment
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SFAS
No. 133
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Accounting
for Derivatives and Hedging Activities (as amended and
interpreted)
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SFAS
No. 141
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Business
Combinations
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SFAS
No. 143
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Accounting
for Asset Retirement Obligations
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SFAS
No. 144
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Accounting
for the Impairment or Disposal of Long-Lived Assets
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SFAS
No. 158
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Employers’
Accounting for Defined Benefit Pension and Other Postretirement Plans—an
amendment of FASB Statements No. 87, 88, 106, and
132(R)
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FORWARD-LOOKING
INFORMATION
This
document contains statements that may be considered forward-looking, such as:
management's expectations and outlook for earnings, the statements of the
Company's business and financial goals regarding its business segments, the
effect of weather on net income, cash position, source of funds and financing
activities, market risk, the effect on income arising from changes in Gas
Distribution revenue from customers' gas purchases from third parties, the
adequacy of the Gas Distribution segment's reserves for uncollectible accounts,
capital expenditures of the Company's subsidiaries, and environmental matters.
These statements speak of the Company's plans, goals, beliefs, or expectations,
refer to estimates or use similar terms. Generally, the words "may," "could,"
"project," "believe," "anticipate," "estimate," "plan," "forecast," "will be"
and similar words identify forward-looking statements. Actual results could
differ materially, because the realization of those results is subject to many
uncertainties including:
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The
outcome of the pending merger between the Company and WPS Resources
Corporation;
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the
outcome of rate increase proceedings if filed with the Commission
by the
utility subsidiaries;
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adverse
decisions in proceedings before the Commission, including, but not
limited
to, proceedings concerning the prudence review of the utility
subsidiaries' gas purchases;
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adverse
changes in the Commission's approved rate mechanisms for recovery
of
environmental remediation costs at former manufactured gas sites
of the
Company's subsidiaries, or adverse decisions by the Commission with
respect to the prudence of costs actually
incurred;
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the
future health of the United States and Illinois
economies;
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the
timing and extent of changes in interest rates and energy commodity
prices, including but not limited to the effect of gas prices on
cost of
gas supplies, accounts receivable and the provision for uncollectible
accounts, interest expense and earnings from the Oil and Gas Production
segment;
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the
effectiveness of the Company's derivative instruments and hedging
activities and their impact on our future results of
operations;
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adverse
resolution of material litigation;
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effectiveness
of the Company's risk management policies and the creditworthiness
of
customers and counterparties;
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changes
in the credit ratings of the Company, Peoples Gas and North Shore
Gas;
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regulatory
developments in the United States, Illinois and other states where
the
Company does business;
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changes
in the nature of the Company's competition resulting from industry
consolidation, legislative change, regulatory change and other factors,
as
well as action taken by particular
competitors;
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the
Company's success in identifying diversified business segment projects
on
financially acceptable terms and generating earnings from projects
in a
reasonable time;
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operational
factors affecting the Company's Gas Distribution, Energy Assets and
Oil
and Gas Production segments;
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the
Company's ability to complete its divestment of its power generation
assets on advantageous terms;
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drilling
and production risks and the inherent uncertainty of oil and gas
reserve
estimates;
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weather-related
energy demand;
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terrorist
activities; and
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the
application of, or changes in, accounting rules or interpretations,
including, but not limited to the impact of mark-to market accounting
treatment for some of the Company's derivative contracts used by
the
Company to manage commodity price basis, and other
risks.
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Also,
projections to future periods of the effectiveness of internal control over
financial reporting are subject to the risk that controls may become inadequate
because of changes in conditions, or that the degree of compliance with the
policies or procedures may deteriorate. Some of these uncertainties that may
affect future results are discussed in more detail in Item 1—Business, Item
1A—Risk Factors and Item 7—MD&A. All forward-looking statements included in
this document are based upon information presently available, and the
C
ompany,
Peoples Gas and North Shore Gas
assume
no obligation to update any forward-looking statements.
PART
I
GENERAL
Peoples
Energy is a holding company and does not engage directly in any business of
its
own, but does provide administrative services that support the business
activities of its subsidiaries. Income is derived principally from the Company’s
regulated utility subsidiaries, Peoples Gas and North Shore Gas. The Company
also derives income from its other subsidiaries, Peoples Energy Resources
Company, LLC (Peoples Energy Resources), Peoples Energy Services Corporation
(Peoples Energy Services) and Peoples Energy Production Company (Peoples Energy
Production). The Company and its subsidiaries had 2,223 employees at September
30, 2006.
The
Company was incorporated in 1967 under the Illinois Business Corporation Act
and
has its principal executive offices at 130 East Randolph Drive, Chicago,
Illinois 60601-6207 (Telephone (312) 240-4000).
The
Company has five reportable business segments: Gas Distribution, Oil and Gas
Production, Energy Marketing, Energy Assets, and Corporate and Other. (See
Note
3 of the Notes to Consolidated Financial Statements for financial information
about the Company’s business segments for the last three fiscal years.) Also see
Note 2B of the Notes to Consolidated Financial Statements for financial
information about discontinued operations.
MERGER
On
July 8,
2006, WPS Resources Corporation (WPS Resources), Wedge Acquisition Corporation
(Sub), a wholly owned subsidiary of WPS Resources, and Peoples Energy
Corporation (the Company or Peoples Energy) entered into an Agreement and Plan
of Merger (the Agreement).
The
Agreement provides for the merger of Sub with and into Peoples Energy (the
Merger) on the terms and subject to the conditions set forth in the Agreement,
with Peoples Energy continuing as the surviving corporation. As a result of
the
Merger, Peoples Energy will become a wholly owned subsidiary of WPS Resources,
and Peoples Energy shareholders will receive shares of WPS Resources common
stock in exchange for their shares of common stock of Peoples Energy. At the
effective time of the Merger, each share of common stock of Peoples Energy
issued and outstanding immediately prior to the effective time will be cancelled
and converted into the right to receive 0.825 shares of common stock of WPS
Resources. The companies expect that upon consummation of the Merger Peoples
Energy shareholders will own approximately 42.4% of the common stock of WPS
Resources and WPS Resources shareholders will own approximately 57.6% of the
common stock of WPS Resources.
WPS
Resources and Peoples Energy have each made customary representations,
warranties and covenants in the Agreement, including, among others, covenants
to
conduct their businesses in the ordinary course between the execution of the
Agreement and the consummation of the Merger and covenants not to engage in
certain kinds of transactions during that period. During such period, Peoples
Energy will not declare cash dividends in excess of $0.545 per share per quarter
without the prior consent of WPS Resources. Immediately after the effective
time
of the Merger, WPS Resources will adopt a dividend policy providing for a
quarterly dividend of $0.66 per share of WPS Resources common stock, subject
to
evaluation over time as future business needs dictate. WPS Resources and Peoples
Energy have made certain additional customary covenants, including, among
others, covenants, subject to certain exceptions, (A) to cause a shareholders
meeting to be held to consider approval of the Merger and the other transactions
contemplated by the Agreement, (B) not to solicit proposals relating to
alternative business combination transactions, and (C) not to enter into
discussions concerning, or provide confidential information in connection with,
alternative business combination transactions.
Consummation
of the Merger is subject to customary conditions, including, among others,
(i)
approval of the shareholders of each of WPS Resources and Peoples Energy, (ii)
absence of any material adverse effect, (iii) expiration or termination of
the
applicable Hart-Scott-Rodino Act waiting period, (iv) absence of any order
or
injunction prohibiting the consummation of the Merger, (v) the registration
statement on Form S-4 shall have become effective, (vi) the shares of WPS
Resources common stock issuable to Peoples Energy’s shareholders pursuant to the
Agreement and under the employee benefit plans of Peoples Energy shall have
been
approved for listing on the New York Stock Exchange, (vii) subject to certain
exceptions, the accuracy of representations and warranties with respect to
WPS
Resources’ and Peoples Energy’s business, as applicable, (vii) receipt of
customary tax opinions and (viii) receipt of all required statutory approvals
from, among others, the FERC, the Federal Communications Commission, and state
public service and utility commissions.
The
Agreement contains certain termination rights for both WPS Resources and Peoples
Energy, and further provides that, upon termination of the Agreement under
specified circumstances, a party would be required to pay the other party a
termination fee of $45 million. In addition, under specified circumstances
each
party may be obligated to reimburse the other party for up to $15 million of
expenses, which would reduce the amount of any required termination fee payable
by that party.
The
consummation of the Merger is subject to the satisfaction or waiver of closing
conditions applicable to both WPS
Resources
and Peoples Energy, including the receipt of required regulatory approvals
and
the approval of the transaction by the shareholders of both WPS Resources and
Peoples Energy. On August 2, 2006, WPS Resources, Peoples Energy, Peoples Gas
and North Shore Gas jointly filed an application for approval of the Merger
with
the Commission. The companies seek the expedited consideration of the
application by the Commission, with requested approval by December 28, 2006
so
that the Merger could close on or shortly after January 1, 2007. The application
indicates that The Peoples Gas Light and Coke Company (Peoples Gas) and North
Shore Gas Company (North Shore Gas) will further postpone filing rate cases
until early 2007, with new rates to take effect in 2008 due to the normal
11-month rate case process in Illinois. On October 31, 2006, Commission Staff
and Interveners filed Direct Testimony and opinion on the Merger proposal.
On
November 13, 2006, the Companies filed rebuttal testimony.
WPS
Resources and Peoples Energy filed their joint application for FERC approval
on
August 15, 2006. The comment period on the FERC filing passed with no comments
received. On November 2, 2006, the FERC issued a deficiency letter identifying
an item about which additional information was required, and WPS Resources
and
Peoples Energy responded on November 6, 2006. The comment period for this
response was concluded on November 13, 2006. No comments were
received.
On
August
15, 2006, WPS Resources filed with the Public Service Commission of Wisconsin
(PSCW) for approval of amendments to its “affiliated interest” agreements so
that they include and apply to Peoples Energy and its subsidiaries, as
appropriate, upon closing of the merger. These agreements govern the provision
by and among WPS Resources and its regulated and non-regulated subsidiaries
of
services, property, and other things of value. Modification of these agreements
requires the approval of the PSCW. WPS Resources had concluded that no other
PSCW approvals were required prior to the closing of the merger. However, on
August 9, 2006, the PSCW issued a notice of investigation of the merger to
consider, among other things, whether the PSCW has jurisdiction and pre-approval
authority over the merger. Subsequently, the PSCW asserted jurisdiction and
pre-approval authority over the merger, and, on September 27, 2006, the PSCW
re-noticed the investigatory matter as a contested case proceeding in which
it
would consider whether the merger is in the public interest and whether certain
conditions should be placed upon WPS Resources (and affiliate arrangements
within its holding company system) as a result of the merger. WPS Resources
acknowledges the PSCW’s continuing jurisdiction from time to time to consider
and, if appropriate, impose additional conditions upon Wisconsin public utility
holding companies. However, WPS Resources does not believe that the PSCW has
jurisdiction and pre-approval authority over the merger, even though the PSCW
has asserted such jurisdiction and authority. The PSCW has established a
schedule for completion of the proceeding that would accommodate a closing
of
the merger in the first quarter of 2007. WPS Resources’ participation in the
proceeding will be subject to its right to challenge the PSCW’s asserted
jurisdiction before the PSCW and on appeal of an adverse PSCW
order.
Pursuant
to the Agreement, management from both companies jointly selected Integrys
Energy Group, Inc. (Integrys) as the new name for the combined company. Upon
consummation of the Merger, WPS Resources’ Board of Directors will be comprised
of sixteen directors, nine of whom will have been designated by WPS Resources
and seven of whom will have been designated by Peoples Energy. Mr. Larry Weyers,
currently Chairman, President and Chief Executive Officer of WPS Resources,
will
remain President and Chief Executive Officer of Integrys following the Merger.
Mr. James Boris, currently the Lead Director of Peoples Energy will become
the
non-executive Chairman of Integrys as of the effective time of the Merger.
Upon
the consummation of the Merger, WPS Resources will amend bylaws consistent
with
the foregoing.
On
October 9, 2006, the Company identified many of Integrys’ senior leaders, who
will manage Integrys after the transaction closes through a holding company,
operating companies and a services group. Following the Merger, Integrys will
establish its headquarters in Chicago, Illinois. The headquarters of the
Integrys’ unregulated energy marketing business will be located in Green Bay,
Wisconsin and the headquarters of the utilities’ businesses will be located in
the same place as immediately prior to the effective time of the Merger. The
headquarters of the oil and gas production business will remain in Houston,
Texas.
On
October 18, 2006, the WPS Resources registration statement on Form S-4 was
made
effective by the SEC.
On
October 25, 2006, the Federal Trade Commission granted termination of the
waiting period for the Hart-Scott-Rodino filing for the Merger.
On
December 6, 2006, at special meetings of shareholders held by WPS Resources
and Peoples Energy, shareholders of both companies approved the proposed
merger transaction. WPS Resources’ shareholders also approved an amendment to
WPS Resources Corporation’s restated articles of incorporation to change the
name of WPS Resources Corporation to Integrys Energy Group, Inc., when the
closing of the merger has been completed.
1.
GAS DISTRIBUTION SEGMENT
Principal
Products and Markets
The
Gas
Distribution segment is the Company’s core business. Its two regulated utilities
(Peoples Gas and North Shore Gas, whose operations are limited to this segment
and the Corporate and Other segment) purchase, store, distribute, sell and
transport natural gas to approximately one million customers through an
approximately 6,000-mile distribution-mains system serving Chicago and 54
communities in northeastern Illinois. The customer base includes residential,
commercial and industrial sales and transportation accounts that provide a
broad
and diversified foundation for the utilities’ business.
As
part
of this segment, Peoples Gas utilizes its storage and pipeline supply assets
as
a natural gas hub. This activity is regulated by the FERC and consists of
providing wholesale transportation and storage services in interstate
commerce.
For
fiscal 2006 and on September 30, 2006, the Gas Distribution segment accounted
for
64%
of
revenues and 75% of capital assets.
Peoples
Gas was formed in 1855 and had 1,520 employees at September 30, 2006, of which
883 are union employees. It has approximately 815,000 residential, commercial
and industrial retail sales and transportation customers in
Chicago.
North
Shore Gas was formed in 1900 and had 205 employees at September 30, 2006, of
which 138 are union employees. It has approximately 156,000 residential,
commercial and industrial retail sales and transportation customers within
its
service area of approximately 275 square miles, located in northeastern
Illinois.
The
basic
marketing plans of Peoples Gas and North Shore Gas are to maintain their
existing shares in traditional market segments, which include space heating,
water heating, clothes drying and cooking. North Shore Gas’ service territory
has potential for expansion through increasing population density.
Competition
Competition
in varying degrees exists between natural gas and other fuels or forms of energy
available to consumers in the Midwest and the utilities’ respective service
territories, such as electricity and diesel fuel.
Absent
extraordinary circumstances, potential competitors are barred from constructing
competing gas distribution systems in the utility subsidiaries’ service
territories 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.
An
interstate 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. No Peoples Gas
customers have been lost to bypass service; only one end user in North Shore
Gas’ service territory is served directly by a pipeline supplier. Both utility
subsidiaries have a bypass rate approved by the Commission, which allows the
utilities to negotiate rates with customers that are potential bypass
candidates.
Since
2002, all customers have had the opportunity to choose a gas supplier. A
substantial portion of the gas that Peoples Gas and North Shore Gas deliver
to
their customers consists of gas that the subsidiaries’ customers purchase
directly from producers and marketers rather than from the utilities. These
direct customer purchases have little effect on net income because the utilities
provide transportation service for such gas volumes and recover margins similar
to those applicable to conventional gas sales.
Current
Sources and Availability of Natural Gas
Peoples
Gas and North Shore Gas have each entered into long-term and short-term firm
gas
supply contracts with various suppliers, including BP Canada Energy Marketing
Corp., Occidental Energy Marketing, Inc., Oneok Energy Services Company, L.P.,
and Tenaska Marketing Ventures, with remaining gas supply contract terms up
to
two years. When used in conjunction with contract storage, company-owned storage
and peak-shaving facilities, such supply is deemed sufficient to meet current
and foreseeable peak and annual market requirements. Although the Company
believes North American gas supply to be sufficient to meet current and
prospective United States market demands, it is unable to quantify or otherwise
make specific representations regarding national supply availability and the
cost of the supply.
Peoples
Gas and North Shore Gas purchase firm transportation and storage services from
interstate pipelines in the ordinary course of business. Seven interstate
pipelines interconnect with Peoples Gas’ utility system and two interstate
pipelines and one local distribution company interconnect with North Shore
Gas’
utility system. Having multiple pipelines that serve the utilities’ service
territories improves reliability, provides access to diverse supply and fosters
competition among these service providers that can lead to favorable conditions
for the utilities when negotiating new agreements.
The
following table shows the expected design peak-day availability of gas in MDth
during the 2006-2007 heating season for Peoples Gas and North Shore
Gas:
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Peoples
Gas
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North
Shore Gas
|
||||||
|
Design
Peak-Day
|
Year
of
|
Design
Peak-Day
|
Year
of
|
||||||
|
Availability
|
Contract
|
Availability
|
Contract
|
||||||
|
Source
|
(MDth)
|
Expiration
|
(MDth)
|
Expiration
|
|||||
|
Firm
pipeline capacity
|
320
|
2008-2011
|
58
|
2008-2017
|
|||||
|
Firm
city-gate supply
|
168
|
2007
|
47
|
2007
|
|||||
|
Liquefied
petroleum gas
|
-
|
40
|
|||||||
|
Storage
gas:
|
|
||||||||
|
Contract
|
583
|
2009-2017
|
233
|
2009-2017
|
|||||
|
Peoples—Manlove
|
993
|
-
|
|||||||
|
Customer-owned
|
253
|
60
|
|||||||
|
Total
expected design
|
|
||||||||
|
peak-day
availability
|
2,317
|
438
|
|||||||
Peoples
Gas and North Shore Gas forecast maximum peak day demands of 2,257 MDth and
427
MDth, respectively.
The
sources of gas supply (including gas transported for customers) in MDth for
Peoples Gas and North Shore Gas were as follows:
|
|
|
Peoples
Gas
|
North
Shore Gas
|
||||||||||
|
For
Fiscal Years Ended September 30,
|
For
Fiscal Years Ended September 30,
|
||||||||||||
|
2006
|
2005
|
2004
|
2006
|
2005
|
2004
|
||||||||
|
Gas
purchases
|
109,685
|
115,530
|
118,532
|
23,523
|
24,052
|
25,479
|
|||||||
|
Liquefied
petroleum gas produced
|
-
|
-
|
-
|
10
|
6
|
10
|
|||||||
|
Customer-owned
gas received
|
71,782
|
73,240
|
78,007
|
12,793
|
12,516
|
13,106
|
|||||||
|
Underground
storage—net
|
(3,655
|
)
|
(2,710
|
)
|
214
|
(883
|
)
|
116
|
(964
|
)
|
|||
|
Purchased
storage compressor fuel,
|
|||||||||||||
|
franchise
requirements,
|
|||||||||||||
|
and
unaccounted-for gas
|
(4,456
|
)
|
(4,200
|
)
|
(4,436
|
)
|
(517
|
)
|
(868
|
)
|
(646
|
)
|
|
|
Total
|
173,356
|
181,860
|
192,317
|
34,926
|
35,822
|
36,985
|
|||||||
Importance
of Regulatory Environment
Legislation
and Regulation at State Level.
Peoples
Gas and North Shore Gas are 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. These include rates
and
charges, issuance of securities, services and facilities, systems of accounts,
investments, safety standards, transactions with affiliated interests and other
matters.
Peoples
Gas and North Shore Gas are authorized, by statute and/or certificates of public
convenience and necessity, to conduct operations in the territories they serve.
In addition, these subsidiaries operate under franchises and license agreements
granted to them by the municipalities they serve. Peoples Gas holds a perpetual,
nonexclusive franchise to serve Chicago. North Shore Gas’ franchises with
municipalities within its service territory are of various terms and expiration
dates.
Impact
on Sales and Rates.
Peoples
Gas and North Shore Gas sell and distribute natural gas having an average
heating value of approximately 1,000 Btu per cubic foot. Sales are made and
service rendered by Peoples Gas and North Shore Gas pursuant to rate schedules
on file with the Commission containing various service
classifications
largely reflecting customers’ different uses and levels of consumption. In
addition to the rate for distribution of gas, Peoples Gas and North Shore Gas
each bills a gas charge representing the cost of gas and transportation and
storage services purchased. This gas charge is determined in accordance with
a
rider to the rate schedules (Rider 2, Gas Charge) to recover the costs incurred
by Peoples Gas and North Shore Gas to purchase, transport and store gas
supplies. The level of the Gas Charge under both subsidiaries’ rate schedules is
adjusted monthly to reflect increases or decreases in natural gas supplier
charges, gains, losses and costs incurred under its hedging program, purchased
storage service costs, transportation charges and liquefied petroleum gas costs.
In addition, under the tariffs of Peoples Gas and North Shore Gas, the
difference for any month between costs recoverable through the Gas Charge and
revenues billed to customers under the Gas Charge is refundable to or
recoverable from customers. (See Notes 2K and 8 of the Notes to Consolidated
Financial Statements.)
Commission
rules place restrictions on when the utility subsidiaries may terminate or
deny
service to customers who do not pay their bills for utility service. Though
each
utility’s current rates were established to recover an estimated bad debt
expense, bad debt expense can exceed these estimates by significant amounts,
particularly for Peoples Gas. Both the federal and state governments have
legislation that provides for additional funding for assistance to low-income
energy users, including customers of the Company’s utility subsidiaries. The
state legislation creates a fund, financed by charges to electric and gas
customers of public utilities, participating municipal utilities and electric
co-ops, which supplements currently available federal energy
assistance.
Legislation
and Regulation at Federal Level.
The
Company is a holding company as defined in the Public Utility Holding Company
Act of 1935 (1935 Act). By Order entered on December 6, 1968 (Holding Company
Act Release No. 16233), the SEC, pursuant to Section 3(a)(1) of the 1935 Act,
exempted the Company and its subsidiary companies as such from the provisions
of
the 1935 Act, other than Section 9(a)(2) thereof.
The
Energy Policy Act of 2005 (Energy Policy Act), signed into law on August 8,
2005, repeals the 1935 Act and makes clear the authority of the FERC over
mergers or acquisitions of public utility holding companies. In addition, the
Energy Policy Act reduces the depreciable life of certain gas distribution
lines
for Federal income tax purposes from twenty years to 15 years, and authorizes
funding of coal gasification projects, which could provide additional gas
supply.
Most
of
the gas distributed by Peoples Gas and North Shore Gas is transported to the
utilities’ distribution systems by interstate pipelines. The pipelines’ services
(transportation and storage service) are regulated by the FERC under the Natural
Gas Act and the Natural Gas Policy Act of 1978. (See Impact on Sales and Rates
and Current Sources and Availability of Natural Gas.)
Under
United States Department of Transportation regulations, the Commission is
responsible for monitoring Peoples Gas’ and North Shore Gas’ safety compliance
program for its pipelines under 49 CFR Part 192 (Transportation of Natural
and
Other Gas by Pipeline: Minimum Federal Safety Standards) and 49 CFR Part 195
(Transportation of Hazardous Liquids by Pipeline).
The
Pipeline Safety Improvement Act of 2002 makes numerous changes to pipeline
safety law, the most significant of which is the requirement that operators
of
pipeline facilities implement written integrity management programs. Such
programs must include a baseline integrity assessment of an operator’s
transmission facilities that must be completed within 10 years after enactment
of the legislation. Peoples Gas owns and operates 158 miles of pipelines subject
to this requirement, and North Shore Gas owns and operates 96 miles of pipelines
subject to this requirement. Implementation of this legislation is not expected
to have a material adverse effect on the financial condition or operations
of
the Company.
Seasonality
The
business of the Company’s utility subsidiaries is influenced by seasonal weather
conditions because a large element of the subsidiaries’ customer load consists
of space heating. Therefore, weather-related deliveries can have a significant
positive or negative impact on net income. (For discussion of the Company’s
prior weather
insurance
arrangements mitigating the effect of the seasonal nature of gas revenues on
cash flow, see Item 7A—Quantitative and Qualitative Disclosures About Market
Risk—Risk Management Activities—Weather Risk.)
During
fiscal 2006, the Gas Distribution segment recorded 74% of its revenues from
November through March.
Practices
Relating to Working Capital
The
seasonality of revenues causes the timing of cash collections to be concentrated
from January through June. A portion of the winter gas supply needs is typically
purchased and stored from April through November. Also, planned capital spending
on the Gas Distribution facilities is concentrated in April through November.
Because of these timing differences, the cash flow from customers is likely
to
be supplemented with temporary increases of short-term commercial paper and
bank
loans during the late summer and fall. Short-term debt is typically reduced
over
the January through June period.
Effects
of Environmental Legislation
The
Company and its subsidiaries are subject to federal and state environmental
laws. Peoples Gas and North Shore Gas are conducting environmental
investigations and remedial work at the sites of former manufactured gas plant
operations. (See Note 7A of the Notes to Consolidated Financial Statements.)
In
1994, North Shore Gas received a demand for payment of environmental response
costs at a former mineral processing site in Denver, Colorado (Denver Site).
North Shore Gas does not believe that it has liability for the response costs
but cannot determine the matter with certainty. (See Note 7B of the Notes to
Consolidated Financial Statements.)
Peoples
Gas and North Shore Gas did not incur and do not anticipate any material
expenditures to construct environmental control facilities due to normal
operations.
2.
OIL AND GAS PRODUCTION SEGMENT
The
Oil
and Gas Production segment, through Peoples Energy Production, is active in
the
acquisition, development and production of oil and gas reserves in selected
onshore basins in the United States through direct ownership in oil, gas and
mineral leases.
Peoples
Energy Production’s primary focus is on natural gas, with growth coming from low
to moderate risk drilling opportunities and acquisition of proved reserves
with
upside potential that can be realized through drilling, production enhancements
and reservoir optimization programs. Peoples Energy Production also has a 23%
equity interest in EnerVest Energy, L.P. (EnerVest), which developed and managed
a portfolio of oil and gas producing properties. This partnership closed a
transaction on October 31, 2005 that resulted in the remaining properties owned
by the partnership being sold to a third party. A substantial portion of the
proceeds from the sale of assets have been distributed to the partners. The
partnership is in the process of winding up the affairs of the partnership.
Peoples Energy Production has no remaining capital investment commitments
associated with the EnerVest partnership.
Competition
in acquiring oil and gas leases and producing properties in the Company’s
targeted onshore basins is substantial. Competitors include the major oil
companies, as well as many independents, some of which have significantly
greater resources. In order to grow the current asset base, replace and expand
reserves, and increase operating income, the Company must select and acquire
from third parties quality producing properties and prospects for future
drilling. The Company has no control over the timing of when these opportunities
may become available.
Extensive
federal, state and local laws govern oil and natural gas operations, regulate
the discharge of materials into the environment or otherwise relate to the
protection of the environment. Numerous governmental agencies issue rules and
regulations to implement and enforce such laws that are often difficult and
costly to comply with and which may carry substantial administrative, civil
and
even criminal penalties for failure to comply. The regulatory burden on the
oil
and natural gas extractive industry increases its cost of doing business and
consequently affects its profitability. These laws, rules and regulations affect
the Company’s operations, as well as the oil and gas exploration and production
industry in general. The costs of such compliance have not been material to
Peoples Energy Production to date. The Company believes that it is in
substantial compliance with current applicable environmental laws, rules and
regulations and that continued compliance with existing
requirements
will not have a material adverse impact on the Oil and Gas Production segment.
The Company currently has no material estimated capital expenditures for
environmental control facilities.
The
Energy Policy Act contains several provisions intended to encourage domestic
production of oil and gas, such as greater access to Federal lands for onshore
oil and gas leasing and permitting, and tax incentives to encourage oil refinery
investment. The Energy Policy Act is not expected to have a significant effect
on the Company’s Oil and Gas Production segment.
3.
ENERGY MARKETING SEGMENT
Peoples
Energy Services, one of the major contributors to the Energy Marketing segment,
primarily provides gas, electricity and energy management services to
industrial, commercial and residential customers regionally within
Illinois
.
Peoples
Energy Services also provides gas in Michigan, Ohio and New York.
Peoples
Energy Services’ operating income can be influenced by seasonal weather
conditions and total margin can be impacted by usage. In addition, revenue
sensitive items such as customer accounts receivable balances are typically
impacted when natural gas or electric prices increase as certain products of
the
segment are tied to an index. However, some risk to accounts receivables and
reserves for uncollectible accounts is mitigated by fixed price products offered
to customers.
Peoples
Energy Services is one of the largest nonutility energy marketers in the
northern Illinois retail energy marketplace. It has customers from a wide
variety of commercial and industrial segments, as well as residential customers.
This minimizes the impacts of business cycle risks in any one segment. Peoples
Energy Services is certified by the Commission as an Alternative Retail Electric
Supplier (ARES), authorizing it to be a nonutility marketer of electricity,
and
as an Alternative Gas Supplier (AGS), authorizing it to be a nonutility marketer
of natural gas for residential and small commercial customers; AGS certification
is not required to serve other customers. As of September 30, 2006, there were
a
total of 20 ARESs in addition to three electric utilities offering supply
service outside their service territories and 12 AGSs in Illinois, as well
as
several other national gas marketers focused on the commercial and industrial
segment. Peoples Energy Services is also currently licensed as an AGS in
Michigan, a Competitive Retail Natural Gas Supplier (CRNGS) in Ohio, and a
gas
Energy Service Company (ESCO) in New York.
Peoples
Energy Resources, another major contributor to the Energy Marketing segment,
provides wholesale services to marketers, utilities, pipelines and gas-fired
power generation facilities. Peoples Energy Resources is authorized by the
FERC
to sell gas for resale at negotiated rates. The FERC conferred this authority
in
a rulemaking (Order 547), and Peoples Energy Resources did not need to seek
specific approval to make sales for resale at negotiated rates. The FERC does
not regulate the sales rates, nor are there any reporting requirements
associated with these sales. The FERC, in November 2003, issued Order 644 in
which it established a code of conduct applicable to entities making sales
pursuant to Order 547 and required such sellers to report to the FERC whether
they report prices to publications that publish natural gas price
indices.
4.
ENERGY ASSETS SEGMENT
The
Energy Assets segment, through Peoples Energy Resources, is engaged in the
development, operation and ownership of electric generation facilities for
sales
to electric utilities and marketers. Currently, the Company has an ownership
interest in one electric generation facility. Peoples Energy Resources and
Dominion Energy, Inc. (Dominion) are equal investors in Elwood Energy LLC
(Elwood), which owns and operates a 1,400-megawatt peaking facility near
Chicago. The plant capacity has been sold through long-term contracts with
Exelon Generation Company, LLC (Exelon) and Constellation Energy Commodities
Group, Inc. Due to the structure of these contracts and the fact that Elwood
is
a peaking facility, the majority of Elwood’s revenues and the Company’s equity
earnings in this investment are recognized in the Company’s third and fourth
fiscal quarters.
The
Company announced in February 2006 its intention to exit the power generation
business.
On
January 31, 2006, the Company sold its 100% interest in the Valencia Energy
power development site in New Mexico. On May 31, 2006, the Company completed
the
sale of its 27% interest in the SCEP facility to Exelon Generation
Company,
LLC. On September 20, 2006, the Company announced that it signed an agreement
with J-POWER USA Development Co., Ltd. (J-Power) to sell its 50% interest in
the
Elwood power generation facility and its 100% interest in a fully-permitted
power development site, the COB Energy Facility (COB), for $110 million, subject
to certain closing adjustments. These sales will complete the divestiture of
substantially all power assets owned by Peoples Energy. The Board of Directors
of J-Power's parent company approved the transactions on November 30, 2006.
Financial results for power generation are now being reported by Peoples Energy
as discontinued operations. Through Elwood and COB, the Company owned
approximately 700 net Megawatts of power generation assets.
Peoples
Energy Resources owns a propane-based peaking plant and other contractual assets
of pipeline transportation and storage in the Midwest region, which enables
it
to perform in other asset-based wholesale activities. Peoples Energy Resources
owns approximately 40 miles of small diameter pipes, which are used to provide
services to local refineries in the Chicago area. Peoples Energy Resources
also
owns 250 acres of land and related facilities in Will County,
Illinois.
The
Energy Policy Act removes certain regulatory obstacles that could have delayed
or impeded government approvals of and private investment in liquefied natural
gas facilities, authorizes funding for coal gasification projects, and contains
standards banning energy market manipulation and permitting substantially higher
penalties for violations of such standards.
5
.
CORPORATE AND OTHER SEGMENT
Certain
business development activities that do not fall under the four major business
segments are reported in the Corporate and Other segment. Corporate
administrative activities that support the business segments are also included
in Corporate and Other.
Investors
should consider carefully the following factors that could cause the Company’s
operating results and financial condition to be materially adversely affected.
New risks may emerge at any time, and management cannot predict those risks
or
estimate the extent to which they may affect the Company’s financial
performance.
Peoples
Energy is a holding company and its assets consist primarily of investments
in
its subsidiaries; covenants in certain of the Company’s financial instruments
may limit its ability to pay dividends, thereby adversely impacting the
valuation of the Company’s common stock and access to
capital.
The
Company’s assets consist primarily of investments in subsidiaries. Dividends on
its common stock depend on the earnings, financial condition and capital
requirements of the Company’s subsidiaries, principally Peoples Gas and North
Shore Gas and the distribution or other payment of earnings from the
subsidiaries to the Company in the form of dividends from the utilities, and
in
the case of its non-regulated subsidiaries dividends, loans, advances or
repayment of loans and advances. The subsidiaries are distinct legal entities
and have no obligation to pay any dividends or make advances or loans to the
Company. Peoples Energy’s ability to pay dividends on its common stock may also
be limited by existing or future regulatory restrictions or agreement covenants
limiting the right of its subsidiaries to pay dividends on their common
stock.
Commodity
price changes may affect the operating costs and competitive positions of the
Company’s businesses, thereby adversely impacting its liquidity and results of
operations.
The
Company’s energy businesses are sensitive to changes in natural gas, oil,
electricity and other commodity prices. Any changes could affect the prices
these businesses charge, their operating costs and the competitive position
of
their products and services. In the case of the Gas Distribution operations,
costs for purchased gas and pipeline transportation and storage services are
fully recovered through the Gas Charge, but increases in gas costs affect total
retail prices and, therefore, the competitive position of the Company’s Gas
Distribution businesses relative to electricity and other forms of energy.
In
addition, the timing and extent of high natural gas
prices
can materially adversely affect the Gas Distribution segment’s accounts
receivable, provision for uncollectible accounts, fuel cost and interest
expense. The Company is also subject to margin requirements in connection with
use of derivative financial instruments and these requirements could escalate
if
prices move adversely relative to hedge positions.
The
Company’s earnings growth and the carrying value of the Company’s oil and gas
producing properties depends in part upon the prices received for its natural
gas and oil production. Natural gas and oil prices historically have been
volatile and are likely to continue to be volatile in the future. The prices
for
natural gas and oil are subject to a variety of factors that are beyond the
Company’s control. These factors include, but are not limited to, the level of
consumer demand for, and the supply of, natural gas and oil, commodity
processing, gathering and transportation availability, the level of imports
of,
and the price of, foreign natural gas and oil, the price and availability of
alternative fuel sources, weather conditions, political conditions or
hostilities in natural gas and oil producing regions. Further, because over
90%
of the Company’s proved reserves at September 30, 2006 were natural gas
reserves, the Company is substantially more sensitive to changes in natural
gas
prices than to changes in oil prices. Declines in natural gas and oil prices
would not only reduce revenue, but could reduce the amount of natural gas and
oil that can be produced economically and, as a result, could adversely affect
the financial results of the Oil and Gas Production segment.
A
significant decline in natural gas and oil prices could result in a downward
revision of the Company’s reserves and a write-down of the carrying value of
natural gas and oil properties that would negatively impact the Company’s net
income and stockholders’ equity.
The
Company has approximately 50% of anticipated production hedged for fiscal 2007,
which is substantially lower than in recent years. This lower hedge percentage
may potentially result in the Company having increased earnings
volatility. The Company will have the potential to realize
higher prices if gas prices hold at or near current levels or lower prices
if gas prices decline.
The
Company’s use of derivative financial instruments could result in earnings
volatility and financial losses.
Some
of
the Company's subsidiaries use derivative financial instruments, including
futures, swaps, collars and option contracts either traded on exchanges or
executed over-the-counter with natural gas and power merchants as well as
financial institutions, to hedge commodity price and interest rate risk.
Fluctuating commodity prices could cause revenues, net income and cash
requirements of the Company to be volatile due to the use of financial
instruments that are not perfectly matched to the exposure (which may result
from the nature of the derivative instrument used or as a result of a
discontinued physical transaction), or if the Company's derivative instruments
and hedging transactions fail to qualify for hedge accounting under SFAS No.
133. The Company may also incur financial losses if counterparties fail to
perform under these instruments. Fluctuating commodity prices and related MTM
accounting also could cause revenues and net income of the Company to be
volatile due to the use of derivative instruments. For additional information
concerning the use of derivatives, see Note 2L of the Notes to Consolidated
Financial Statements.
The
Company’s operating results may be adversely affected by mild
weather.
The
Company’s Gas Distribution businesses and retail business have historically
delivered less natural gas, and consequently earned less income, when weather
conditions are warmer than normal. Mild weather in the future could diminish
the
Company’s revenues and results of operations and harm its financial condition.
Although the Company may from time to time utilize weather insurance or
financial weather derivatives to manage this risk, such measures result in
the
Company incurring costs and expose the Company to the credit risk of the
counterparties in such transactions and, moreover, there can be no assurance
that such measures will fully protect the Company from the effects of mild
weather. (See Item 7A—Quantitative and Qualitative Disclosures about Market
Risk—Weather Risk.)
The
Company’s Gas Distribution subsidiaries depend on storage and transportation
services purchased from interstate pipelines and on a storage field owned by
Peoples Gas to meet their customers’ gas requirements.
Peoples
Gas and North Shore Gas meet a significant percentage of their customers’ peak
day, seasonal and annual gas requirements through withdrawals, pursuant to
contracts, from storage facilities owned and operated by interstate pipelines
and through deliveries of gas transported on interstate pipelines with which
they or their gas suppliers have contracts. Peoples Gas and North Shore Gas
each
contracts with multiple pipelines for these services, and it has gas supply
contracts with multiple suppliers. If a pipeline were to fail to perform storage
or transportation service, including for reasons of force majeure, on a peak
day
or other day with high volume gas requirements, Peoples Gas’ and North Shore
Gas’ ability to meet all their customers’ gas requirements may be impaired
unless or until alternative supply arrangements were put in place. Likewise,
Peoples Gas plans to meet approximately 40% of its peak day requirements from
its own storage field. If that storage field, or the Peoples Gas-owned
transmission pipeline used to transport storage gas to the market, were to
be
out of service for any reason, this could impair Peoples Gas’ ability to meet
its customers’ full requirements on a peak day. Also, North Shore Gas purchases
a storage service from Peoples Gas, and its ability to serve its customers
could
be adversely affected by failures at Peoples Gas’ storage field.
The
Company’s operations are subject to operational hazards and uninsured
risks.
The
Company’s Gas Distribution, Oil and Gas Production, and Energy Assets operations
are subject to the inherent risks normally associated with those operations,
including pipeline ruptures, damage caused by excavators, explosions, release
of
toxic substances, fires, adverse weather conditions, and other hazards, each
of
which could result in damage to or destruction of the Company’s facilities or
damages to persons and property. In addition, the Company’s operations face
possible risks associated with acts of intentional harm on these assets. The
nature of the risks is such that some liabilities could exceed the Company’s
insurance policy limits, or, as in the case of environmental fines and
penalties, cannot be insured. As a result, the Company could incur substantial
costs that could adversely affect its future results of operations, cash flows
or financial condition. A substantial portion of the Company’s oil and gas
production is transported on or processed by third party pipelines and
processing plants. Those pipelines and processing plants are subject to the
same
risks.
The
Company’s oil and gas producing operations involve many risks associated with
estimates and assumptions used in making capital expenditure
decisions.
In
addition to the operational risks described above, the Company’s oil and gas
drilling operations are also subject to the risk of not encountering
commercially productive reservoirs and the Company may not recover all or any
portion of its investment in those wells. Drilling for natural gas and oil
can
be unprofitable, not only because of dry holes but also due to wells that are
productive but do not produce sufficient net reserves to return a profit at
then
realized prices after deducting drilling, operating, production taxes and other
costs.
In
addition, estimating quantities of proved natural gas and oil reserves is a
complex process that involves significant interpretations of technical data
and
assumptions that result in reserve estimates being inherently imprecise. The
Company utilizes a 10% discount factor when estimating the value of its
reserves, as prescribed by the SEC, and this may not necessarily represent
the
most appropriate discount factor, given actual interest rates and risks to
which
the Company’s production business or the natural gas and oil industry, in
general, are subject. Any significant variations from the interpretations or
assumptions used in the estimates or changes of conditions could cause the
estimated quantities and net present value of the Company’s reserves to differ
materially from amounts disclosed in this document.
The
natural gas and oil reserve data included in this document represent the
Company’s best estimates. The Company uses outside reservoir engineers to
provide an analysis of reserves and future production. These analyses are the
basis for the Company’s reserve estimates. Investors should not assume that the
present values referred to in this document represent the current market value
of the Company’s estimated natural gas and oil
reserves.
The timing of the production and the expenses from development and production
of
natural gas and oil properties will affect both the timing of actual future
net
cash flows from proved reserves and their present value.
The
agencies that regulate the Company’s businesses and their customers affect
profitability and potential regulatory changes may adversely affect the
Company’s businesses due to reductions in revenues or increased capital
expenditures.
The
Company’s utility subsidiaries are 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
and other matters. Recently, credit rating agencies have issued negative alerts
on some Illinois utilities, citing as a concern a heightened level of
politicizing of the regulatory process in Illinois, particularly with regard
to
electric utilities. If Peoples Gas’ and North Shore Gas’ tariff rates were
reduced in a future proceeding, or if the Commission denied recovery of certain
costs presently allowed to be recovered through rates, the profitability of
the
utilities’ businesses could be reduced.
The
utility subsidiaries and Peoples Energy Resources are also subject to U.S.
Department of Transportation rules applicable to owners and operators of certain
pipeline facilities. Regulatory requirements relating to the integrity of these
pipelines require capital spending in order to maintain compliance with these
requirements. Any additional laws or regulations that are enacted could
significantly increase the amount of these expenditures.
Peoples
Gas’ and Peoples Energy Wholesale Marketing’s midstream gas services that are
reflected in the Gas Distribution and Energy Marketing segments, respectively,
are regulated by the FERC. Additional or different regulations imposed by the
FERC could affect the profitability of these segments.
The
Company’s Gas Distribution and Energy Assets businesses are also subject to
costly and increasingly stringent environmental regulations. The cost of future
environmental compliance could be significant.
The
Illinois state legislature is reviewing potential legislation to modify the
regulatory process applicable to electric transmission and distribution
companies. This has increased regulatory uncertainty surrounding retail electric
unbundling in Illinois and could adversely impact retail electric sales by
Peoples Energy Services within the Energy Marketing segment.
An
adverse decision in proceedings before the Commission concerning the prudence
review of the Company’s gas purchases could require a significant refund
obligation.
For
each
utility subsidiary, the Commission conducts annual proceedings regarding the
reconciliation of revenues from the Gas Charge and related gas costs. In these
proceedings, the accuracy of the reconciliation of revenues and costs is
reviewed and the prudence of gas costs recovered through the Gas Charge is
examined by interested parties. If the Commission were to find that the
reconciliation was inaccurate or any gas costs were imprudently incurred, the
Commission would order the utility to refund the affected amount to customers
through subsequent Gas Charge filings. The Commission has ordered refunds to
the
Company's utility customers in connection with prior years' gas charge
reconciliation proceedings (see Notes 2C and 8A of the Notes to Consolidated
Financial Statements). Proceedings regarding Peoples Gas and North Shore Gas
for
fiscal year 2005 costs are currently pending before the Commission. The outcome
of these proceedings cannot be predicted. (See Note 8A of the Notes to
Consolidated Financial Statements.)
A
change in the Commission’s approved rate mechanisms for recovery of
environmental remediation costs at former manufactured gas sites of the
Company’s subsidiaries, or adverse decisions with respect to the prudence of
costs actually incurred, could result in the Company reversing significant
amounts currently reflected as regulatory assets, resulting in a decrease to
net
income.
As
described more fully in Note 7A of the Notes to Consolidated Financial
Statements, the Company’s subsidiaries are accruing liabilities and deferring
costs (recorded as regulatory assets) incurred in connection with the
subsidiaries' former manufactured gas sites, including related legal expenses,
pending recovery through rates or from other entities. At September 30, 2006,
regulatory assets of $313 million have been recorded. This amount reflects
the
net amount of (1) costs incurred to date, (2) carrying costs, (3) amounts
recovered from insurance companies, other entities and from customers, and
(4)
management's best estimates of the costs the utilities will spend in the future
for investigating and remediating the manufactured gas sites ($269 million
for
the Company on a consolidated basis). Management has recorded liabilities for
the amounts described in clause (4) of the preceding sentence. Management
believes that any such costs that are not recoverable from other entities or
from insurance carriers are recoverable through rates for utility services
under
Commission-approved mechanisms for the recovery of prudently incurred costs.
A
change in these rate recovery mechanisms, however, or a decision by the
Commission that some or all of these costs were not prudently incurred, could
result in the present recognition as expense of some or all of these
costs.
An
inability to access financial markets could affect the execution of the
Company’s business plan.
The
Company relies on access to both short-term money markets and longer-term
capital markets as a significant source of liquidity for capital requirements
not satisfied by the cash flows from its operations. Management believes that
the Company and its subsidiaries will maintain sufficient access to these
financial markets based upon current credit ratings. However, certain
disruptions outside of the Company’s control may increase its cost of borrowing
or restrict its ability to access one or more financial markets. Such
disruptions could include an economic downturn, the bankruptcy of an unrelated
energy company or downgrades to the Company’s credit ratings.
Restrictions
on the Company’s ability to access financial markets may affect its ability to
execute its business plan as scheduled.
Adverse
changes in our credit ratings may negatively affect the
Company.
The
Company's long-term senior unsecured debt is rated Baa2 by Moody’s Investors
Services and BBB+ by Standard and Poor’s Rating Group. Peoples Gas' and North
Shore Gas' long-term senior secured debt is rated A1 by Moody's Investor
Services and A- by Standard and Poor's. Downgrades in the credit ratings of
the
Company or the utility subsidiaries could impair our ability to access capital
markets at attractive rates and increase our borrowing costs. In addition,
reductions in credit ratings could require the affected company to post
additional collateral related to various trading contracts which could reduce
its liquidity.
Risks
Relating to the Merger
The
merger may not be completed, which could adversely affect Peoples Energy’s
business operations and stock prices.
WPS
Resources and Peoples Energy have not yet obtained all federal and state
regulatory clearances, consents and approvals required to complete the merger.
Governmental or regulatory agencies could still seek to block or challenge
the
merger or could impose restrictions they deem necessary or desirable in the
public interest as a condition to approving the merger. If these approvals
are
not received, or they are not received on terms that satisfy the conditions
set
forth in the merger agreement, then neither WPS Resources nor Peoples Energy
will be obligated to complete the merger.
WPS
Resources and Peoples Energy are each subject to termination fees of $45 million
or the reimbursement of $15 million of merger-related out-of-pocket expenses
if
it terminates the merger under certain circumstances specified in the merger
agreement.
In
addition, the merger agreement contains customary other closing conditions,
which may not be satisfied or waived. If WPS Resources and Peoples Energy are
unable to complete the merger, Peoples Energy would be subject to a number
of
risks, including the following:
| · |
Peoples
Energy would not realize the benefits of the proposed merger, including
any synergies from combining the two
companies;
|
| · |
the
trading price of Peoples Energy common stock may decline to the extent
that the current market prices reflect a market assumption that the
merger
will be completed; and
|
| · |
Peoples
Energy would continue to be exposed to the general competitive pressures
and risks discussed in this Annual Report on Form 10-K for the year
ended
September 30, 2006, which pressures and risks may be increased if
the
merger is not completed.
|
The
occurrence of any of these events individually or in combination could have
a
material adverse effect on the results of operations or the trading price of
Peoples Energy common stock.
Peoples
Energy will be subject to business uncertainties and contractual restrictions
while the merger is pending that could adversely affect its
business.
Uncertainty
about the effect of the merger on employees and customers may have an adverse
effect on Peoples Energy, regardless of whether the merger is eventually
completed, and, consequently, on the combined company. Although Peoples Energy
has taken steps designed to reduce any adverse effects, these uncertainties
may
impair Peoples Energy’s ability to attract, retain and motivate key personnel
until the merger is completed, or the merger agreement is terminated, and for
a
period of time thereafter, and could cause customers, suppliers and others
that
deal with Peoples Energy to seek to change existing business relationships
with
WPS Resources or Peoples Energy.
Employee
retention and recruitment may be particularly challenging during the pendency
of
the merger, as employees and prospective employees may experience uncertainty
about their future roles with the combined company. The departure of existing
key employees or the failure of potential key employees to accept employment
with the Company, despite Peoples Energy’s retention and recruiting efforts,
could have a material adverse impact on Peoples Energy’s business, financial
condition and operating results, regardless of whether the merger is eventually
completed.
The
pursuit of the merger and the preparation for the integration of WPS Resources
and Peoples Energy may place a significant burden on management and internal
resources. The diversion of management attention away from day-to-day business
concerns and any difficulties encountered in the transition and integration
process could have a material adverse impact on Peoples Energy’s business,
financial condition and operating results, regardless of whether the merger
is
eventually completed.
In
addition, the merger agreement restricts each of WPS Resources and Peoples
Energy, without the other party’s consent, from making certain acquisitions and
taking other specified actions until the merger occurs or the merger agreement
terminates. These restrictions may prevent Peoples Energy from pursuing
otherwise attractive business opportunities and making other changes to their
businesses prior to completion of the merger or termination of the merger
agreement.
The
value of shares of WPS Resources common stock to be received by Peoples Energy
shareholders in the merger will fluctuate.
In
the
merger, each share of Peoples Energy common stock outstanding immediately prior
to completion of the merger will be converted into the right to receive 0.825
shares of WPS Resources common stock (with cash paid in lieu of fractional
shares). The exchange ratio is fixed and will not be adjusted to reflect stock
price changes prior to the completion of the merger.
The
market prices of WPS Resources common stock and Peoples Energy common stock
immediately prior to the effective time of the completion of the merger may
vary
significantly from their market prices at the date of the joint proxy
statement/prospectus and at the date of the special meetings of the shareholders
of WPS Resources and the shareholders of Peoples Energy. These variations may
be
the result of various factors, including:
| · |
changes
in the business, operations or prospects of WPS Resources and/or
Peoples
Energy;
|
| · |
speculation
regarding the likelihood that the merger will be completed and the
timing
of the completion;
|
| · |
general
market and economic conditions; and
|
| · |
litigation
and/or regulatory developments.
|
The
merger is subject to receipt of consent or approval from governmental entities
that could delay or prevent the completion of the merger or impose conditions
that could have a material adverse effect on the combined company or that could
cause abandonment of the merger.
To
complete the merger, WPS Resources and Peoples Energy need to obtain approvals
or consents from, or make filings with, a number of United States federal and
state public utility, antitrust and other regulatory authorities.
While
WPS
Resources and Peoples Energy each believe that they will receive the required
statutory approvals and other clearances for the merger, there can be no
assurance as to the timing of these approvals and clearances or their ability
to
obtain these approvals and clearances on satisfactory terms or otherwise. There
can be no assurance that any of these approvals will be obtained or, if
obtained, that these approvals will not contain terms or conditions that could
reasonably be expected to have a material adverse effect on the combined company
following completion of the merger.
On December
6, 2006, at special meetings of shareholders held by WPS
Resources and Peoples Energy, shareholders of both companies approved the
proposed merger transaction. Additional approvals will have to be obtained
to complete the merger. Accordingly, the companies' shareholder approvals
have been obtained before the terms of any conditions that may be imposed
to obtain additional approvals are known. As a result, WPS Resources and Peoples
Energy may make prospective decisions to waive a condition or approve certain
actions required to obtain necessary approvals without seeking further
shareholder approval.
The
anticipated benefits of combining WPS Resources and Peoples Energy may not
be
realized.
WPS
Resources and Peoples Energy entered into the merger agreement with the
expectation that the merger would result in various benefits, including, among
other things, synergies, cost savings and operating efficiencies.
Although
Peoples Energy and WPS Resources expect to achieve the anticipated benefits
of
the merger, including the synergies, achieving them is subject to a number
of
uncertainties, including:
| · |
whether
United States federal and state public utility, antitrust and other
regulatory authorities whose approval is required to complete the
merger
impose conditions on the merger or require the combined company to
share a
disproportionate amount of the expected or achieved synergies of
the
merger with customers, any of which may have an adverse effect on
the
combined company;
|
| · |
resolution
of pending and future rate cases and negotiations (including the
recovery
of deferred costs) and other regulatory decisions impacting WPS Resources’
and Peoples Energy’s regulated businesses, including the rate treatment of
synergies and the cost to achieve those
synergies;
|
| · |
the
ability of the two companies to combine certain of their operations
or
take advantage of expected growth opportunities;
|
| · |
general
market and economic conditions;
|
| · |
general
competitive factors in the market place;
and
|
| · |
higher
than expected costs required to achieve the expected
synergies.
|
No
assurance can be given that these benefits will be achieved or, if achieved,
the
timing of their achievement. Failure to achieve these anticipated benefits
could
result in increased costs and decreases in the amount of expected revenues
of
the combined company.
The
integration of WPS Resources and Peoples Energy following the merger will
present significant challenges that may result in a decline in the anticipated
potential benefits of the merger.
The
merger involves the integration of two companies that previously operated
independently. The difficulties of combining the companies’ operations
include:
| · |
combining
the best practices of two companies, including utility operations,
non-regulated marketing operations and staff
functions;
|
| · |
the
necessity of coordinating geographically separated organizations,
systems
and facilities;
|
| · |
integrating
personnel with diverse business backgrounds and organizational
cultures;
|
| · |
reducing
the costs associated with each company’s operations;
and
|
| · |
preserving
important relationships of both WPS Resources and Peoples Energy
and
resolving potential conflicts that may
arise.
|
The
process of integrating operations could cause an interruption of, or loss of
momentum in, the activities of one or more of the combined company’s businesses
and the possible loss of key personnel. The diversion of management’s attention
and any delays or difficulties encountered in connection with the merger and
the
integration of the two companies’ operations could have an adverse effect on the
business, results of operations, financial condition or prospects of the
combined company after the merger.
WPS
Resources and Peoples Energy expect the merger to generate potential pre-tax
cost synergies of $94 million for the combined company on an annualized basis
by
the end of the fifth full year of operations following completion of the merger
(excluding costs of integration). These savings may not be realized within
the
time periods contemplated, or at all.
Peoples
Energy will incur significant transaction, merger-related and restructuring
costs in connection with the merger.
Peoples
Energy expects to incur costs associated with combining the operations of the
two companies, as well as transaction fees and other costs related to the
merger. The combined company also will incur restructuring and integration
costs
in connection with the merger. The estimated total cost to WPS Resources (and
ultimately the combined company) of accomplishing the merger and achieving
the
synergies and cost savings is approximately $186 million in transaction and
integration costs, most of which will be incurred through 2010. The costs
related to restructuring will be treated as a liability and will be included
in
the total purchase price or expensed, depending on the nature of the
restructuring activity. Although WPS Resources and Peoples Energy expect that
the
elimination of duplicative costs, as well as the realization of other
efficiencies related to the integration of the businesses, may offset
incremental transaction, merger-related and restructuring costs over time,
any
net benefit may not be achieved in the near term, or at all.
The
combined company will record goodwill that could become impaired and adversely
affect the combined company’s operating results.
The
merger will be accounted for as a purchase by WPS Resources in accordance with
generally accepted accounting principles. Under the purchase method of
accounting, the assets and liabilities of Peoples Energy will be recorded,
as of
completion, at their respective fair values and added to those of WPS Resources.
The reported financial condition and results of operations of WPS Resources
issued after completion of the merger will reflect Peoples Energy balances
and
results after completion of the merger, but will not be restated retroactively
to reflect the historical financial position or results of operations of Peoples
Energy. Following completion of the merger, the earnings of the combined company
will reflect purchase accounting adjustments, including increased amortization
and depreciation expense for acquired assets.
Under
the
purchase method of accounting, the total purchase price will be allocated to
Peoples Energy’s tangible assets and liabilities and identifiable intangible
assets, based on their fair values as of the date of completion of the merger.
The excess of the purchase price over those fair values will be recorded as
goodwill. We expect that the merger will result in the creation of goodwill
based upon the application of purchase accounting. To the extent the value
of
goodwill or intangibles becomes impaired, the combined company may be required
to incur material charges relating to such impairment. Such a potential
impairment charge could have a material impact on the combined company’s
operating results.
None.
The
Company’s assets consist primarily of its investments in its subsidiaries. The
principal properties of those subsidiaries are described below.
GAS
DISTRIBUTION
The
properties of Peoples Gas and North Shore Gas consist primarily of its gas
distribution system, which includes approximately 6,000 miles of gas mains,
approximately
611,000
service pipes, and odorization and regulation facilities. Peoples Gas owns
and
operates an underground gas storage reservoir and a liquefied natural gas plant
at Manlove Field located in central Illinois. Peoples Gas also owns a natural
gas pipeline system that runs from Manlove Field to Chicago with seven major
interstate pipeline interconnects at various points. The underground storage
reservoir also serves North Shore Gas under a contractual arrangement. Peoples
Gas utilizes its storage and pipeline supply assets as a natural gas hub in
the
Chicago area. General properties include 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 Peoples Gas and North Shore Gas, 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
under 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. Certain storage wells and other
facilities of the Manlove Field storage reservoir and certain portions of the
transmission system are located on land held pursuant to leases, easements
or
permits. Peoples Gas leases its headquarters office in Chicago.
Substantially
all of the physical properties now owned or hereafter acquired by Peoples Gas
or
North Shore Gas are subject to (a) the first-mortgage lien of each utility’s
respective mortgage indenture to U.S. Bank National Association, as Trustee,
to
secure each utility’s respective outstanding first mortgage bonds and (b) in
certain cases, other exceptions and defects that do not interfere with the
use
of the property.
OIL
AND GAS PRODUCTION
The
Oil
and Gas Production segment, through Peoples Energy Production, owns working
interests in substantial oil and gas leasehold positions located in various
areas of Texas, Louisiana, New Mexico, Arkansas, Oklahoma
,
Mississippi and North Dakota. The Company operates a number of Texas, New
Mexico, Louisiana and Mississippi properties, with its principal operating
areas
being located in South Texas, eastern Texas, northern Louisiana and along the
Gulf Coast of Texas. As of September 30, 2006, total proved reserves were
approximately 233 Bcfe, of which approximately 88% are operated by the Company.
The Company owns a 23% equity investment interest in EnerVest, which managed
and
developed a portfolio of oil and gas producing properties. On October 31, 2005,
EnerVest sold all the properties owned by the partnership and has distributed
a
substantial portion of the proceeds to the partners. The partnership is in
the
process of winding up the affairs of the partnership. Peoples Energy Production
has no remaining capital investment commitments associated with the EnerVest
partnership.
Information
detailing the Company's gas and oil operations is presented below:
Location
of Oil and Gas Properties—Distribution of Production and
Reserves
The
following tables summarize certain property and drilling statistics for Peoples
Energy Production's oil and gas production activities.
|
|
|
At
September 30, 2006
|
|
|
Proved
reserves (Bcfe)
|
232.8
|
||
|
Productive
wells
|
|||
|
Gross
oil wells
|
43
|
||
|
Net
oil wells
|
22
|
||
|
Gross
gas wells (1)
|
710
|
||
|
Net
gas wells (1)
|
333
|
||
|
Acreage
|
|||
|
Gross
developed acres
|
162,334
|
||
|
Net
developed acres
|
86,985
|
||
|
Gross
undeveloped acres
|
32,843
|
||
|
Net
undeveloped acres
|
18,256
|
(1)
27
gross
(14 net) wells have multiple completions.
|
|
|
For
Fiscal Years Ended
|
||||||||
|
September
30,
|
||||||||||
|
Net
Wells Drilled
|
|
2006
|
|
2005
|
|
2004
|
|
|||
|
Productive
|
|
|
|
|
|
|
|
|||
|
Exploratory
|
|
-
|
|
-
|
|
2.2
|
|
|||
|
Developmental
|
|
32.4
|
|
32.8
|
|
22.2
|
|
|||
|
Dry
|
|
|
|
|
|
|
|
|||
|
Exploratory
|
|
0.2
|
|
-
|
|
1.5
|
|
|||
|
Developmental
|
|
2.8
|
|
1.6
|
0.2
|
|||||
As
of
September 30, 2006, 3 gross (2.2 net) wells were in progress.
Peoples
Energy Production leases office space in Houston, Texas. Total capital outlays
in fiscal 2006 for drilling and exploration projects were approximately $95
million.
See
Notes
7, 8 and 9 of the Notes to Consolidated Financial Statements for a discussion
of
material legal proceedings. The Company, Peoples Gas and North Shore Gas are
involved in various other claims and legal actions which management does not
believe will have a material adverse effect on the Company's, Peoples Gas'
and
North Shore Gas' financial position or results of operations.
None.
EXECUTIVE
OFFICERS OF THE COMPANY
The
following is a list of the names, ages and positions of the executive officers
of the Company. Executive officers were elected to serve for a term of one
year
or until their successors are duly elected and qualified.
|
Age
at
|
|||||
|
Name
|
11/30/2006
|
Position
with the Company
|
|||
|
Katherine
A. Donofrio
|
49
|
Senior
Vice President (Business Services) of the Company (2001). Ms. Donofrio
is
also Senior Vice President of Peoples Gas and North Shore Gas (2002).
|
|||
|
Linda
M. Kallas
|
47
|
Vice
President and Controller (2004) of the Company. Ms. Kallas is also
Vice
President and Controller (2004) of Peoples Gas and North Shore Gas.
Prior
to becoming Vice President, Ms. Kallas was Assistant Vice President
and
Controller (2002). Prior to becoming Controller Ms. Kallas was Director
of
Corporate Accounting (1999).
|
|||
|
Peter
H. Kauffman
|
60
|
Assistant
General Counsel and Secretary (1998) of the Company. Mr. Kauffman
is also
Assistant General Counsel and Secretary of Peoples Gas and North
Shore Gas
(1998).
|
|||
|
William
E. Morrow
|
50
|
Executive
Vice President of Operations (2004) of the Company and Vice Chairman
(2004) and a Director (2000) of Peoples Gas and North Shore Gas.
Mr.
Morrow is also President of Peoples Energy Resources (2000). Prior
to
becoming Executive Vice President of Operations, Mr. Morrow was Executive
Vice President of the Company (2000). Mr. Morrow was also Executive
Vice
President (2001) of Peoples Gas and North Shore Gas.
|
|||
|
Thomas
A. Nardi
|
52
|
Executive
Vice President and Chief Financial Officer (2005) of the Company,
Peoples
Gas and North Shore Gas and Director (2002) of Peoples Gas and North
Shore
Gas. Prior to becoming Executive Vice President, Mr. Nardi was Senior
Vice
President and Chief Financial Officer (2001) of the Company, Peoples
Gas
and North Shore Gas. Prior to becoming Senior Vice President, Mr.
Nardi
was President of Peoples Energy Services (2000). Mr. Nardi has been
an
employee of the Company and/or its subsidiaries since 2000.
|
|||
|
Steven
W. Nance
|
50
|
President
of Peoples Energy Production Company, the Oil and Gas Production
business
segment of the Company (2000).
|
|||
|
Thomas
M. Patrick
|
60
|
Chairman,
President and Chief Executive Officer (2002) and a Director (1998)
of the
Company. Mr. Patrick is also Chairman of the Board and Chief Executive
Officer of Peoples Gas and North Shore Gas (2002). Prior to becoming
Chairman, Mr. Patrick was President and Chief Operating Officer (1998)
of
the Company and its subsidiaries and Vice Chairman (2001) of both
utility
subsidiaries.
|
|||
|
Desiree
G. Rogers
|
47
|
President
(2004) and a Director (2004) of Peoples Gas and North Shore Gas.
Ms.
Rogers is also Senior Vice President (Marketing and Communications)
of the
Company (2001). Prior to becoming President, Ms. Rogers was Senior
Vice
President of Peoples Gas and North Shore Gas (2001).
|
|||
|
Age
at
|
||||
|
Name
|
11/30/2005
|
Position
with the Company
|
||
|
Douglas
M. Ruschau
|
48
|
Vice
President (Finance) (2002) and Treasurer of the Company (2003). Mr.
Ruschau is also Vice President (2002) and Treasurer (2003) of Peoples
Gas
and North Shore Gas. Mr. Ruschau became an employee of the Company
in
2002. Prior to working for the Company, Mr. Ruschau was employed
by Nicor
Inc. (1980-2002) as Assistant Vice President Finance (1998).
|
PART
II
The
common stock of the Company is listed on the New York Stock, Chicago Stock
and
Pacific Exchanges (trading symbol: PGL). At November 30, 2006, there were 18,091
registered shareholders. There were no issuances of unregistered stock in the
current fiscal quarter. See Notes 17 and 18 of the Notes to Consolidated
Financial Statements for information regarding dividends declared on common
equity and securities authorized for issuance under equity compensation
plans.
All
of
the outstanding shares of common stock of Peoples Gas and North Shore Gas are
owned by the Company.
|
Stock
Price
|
|||||||
|
Fiscal
Quarters
|
High
|
Low
|
|||||
|
2006
|
|||||||
|
Fourth
|
$
|
43.87
|
$
|
35.71
|
|||
|
Third
|
38.66
|
35.10
|
|||||
|
Second
|
37.97
|
35.11
|
|||||
|
First
|
39.90
|
34.34
|
|||||
|
2005
|
|||||||
|
Fourth
|
$
|
45.52
|
$
|
38.71
|
|||
|
Third
|
44.97
|
38.72
|
|||||
|
Second
|
45.10
|
41.11
|
|||||
|
First
|
45.38
|
41.05
|
|||||
The
following table provides information about the Company's purchases of its equity
securities in fiscal 2006:
|
(A)
|
(B)
|
(C)
|
(D)
|
||||||
|
Period
|
Total
Number of Shares (or Units) Purchased
|
Average
Price Paid Per Share (or Unit)
|
Total
Number of Shares (or Units) Purchased as Part of Publicly Announced
Plans
or Programs
|
Maximum
Number (or Approximate Dollar Value) of Shares (or Units) that
May Yet Be
Purchased Under the Plans or Programs
|
|||||
|
October
2005
|
10,027
(1)
|
$
38.98
|
10,027
(1)
|
Not
applicable
(2)
|
|||||
|
December
2005
|
834
(1)
|
$
36.30
|
834
(1)
|
Not
applicable
(2)
|
|||||
|
March
2006
|
65
(1)
|
$
36.09
|
65
(1)
|
Not
applicable
(2)
|
|||||
|
May
2006
|
69
(1)
|
$
36.46
|
69
(1)
|
Not
applicable
(2)
|
|||||
|
(1)
|
Represents
shares of restricted stock cancelled to pay for taxes related to
the
vesting of restricted stock
|
||||||||
|
under
the 1990 LTIC Plan. The 2004 Incentive Compensation Plan replaced
the 1990
LTIC Plan.
|
|||||||||
|
(2)
|
Maximum
number of shares cannot be determined as amounts to be purchased
vary with
individual tax
|
||||||||
|
status
and market price of Company common
stock.
|
|||||||||
|
Peoples
Energy Corporation
|
||||||||||||||||||||||||
|
(In
Thousands, Except Per-Share Amounts)
|
||||||||||||||||||||||||
|
For
Fiscal Years Ended September 30,
|
2006
|
2005
|
2004
|
2003
|
2002
|
|||||||||||||||||||
|
Operating
revenues
|
$
|
3,017,970
|
$
|
2,599,585
|
$
|
2,260,199
|
$
|
2,138,394
|
$
|
1,482,534
|
||||||||||||||
|
Income
(loss) from continuing operations
|
(27,941
|
)
|
66,848
|
74,742
|
97,162
|
83,027
|
||||||||||||||||||
|
Income
from discontinued operations, net of taxes
|
10,305
|
11,285
|
6,822
|
6,772
|
6,044
|
|||||||||||||||||||
|
Net
income (loss) (GAAP)
|
$
|
(17,636
|
)
|
$
|
78,133
|
$
|
81,564
|
$
|
103,934
|
$
|
89,071
|
|||||||||||||
|
Ongoing
income from continuing operations
|
||||||||||||||||||||||||
|
(non-GAAP)
(1)
|
$
|
44,206
|
$
|
74,766
|
$
|
84,985
|
$
|
97,162
|
$
|
83,027
|
||||||||||||||
|
Diluted
(loss) earnings per share:
|
||||||||||||||||||||||||
|
From
continuing operations
|
(0.73
|
)
|
1.75
|
2.00
|
2.68
|
2.34
|
||||||||||||||||||
|
From
discontinued operations, net of taxes
|
0.27
|
0.30
|
0.18
|
0.19
|
0.17
|
|||||||||||||||||||
|
Total
|
(0.46
|
)
|
2.05
|
2.18
|
2.87
|
2.51
|
||||||||||||||||||
|
Total
assets
|
3,822,414
|
3,537,791
|
3,094,790
|
2,928,538
|
2,723,647
|
|||||||||||||||||||
|
Capitalization:
|
||||||||||||||||||||||||
|
Long-term
debt
|
894,702
|
895,583
|
897,377
|
744,345
|
554,014
|
|||||||||||||||||||
|
Common
equity
|
841,454
|
800,154
|
870,083
|
847,999
|
806,324
|
|||||||||||||||||||
|
Short-term
debt
|
309,744
|
(2
|
)
|
8,148
|
55,625
|
207,949
|
(3
|
)
|
377,871
|
(4
|
)
|
|||||||||||||
|
Cash
dividends declared per share
|
$
|
2.18
|
$
|
2.175
|
$
|
2.15
|
$
|
2.11
|
$
|
2.07
|
||||||||||||||
|
(1)
|
Ongoing
income from continuing operations (non-GAAP) is defined as GAAP income
from continuing operations adjusted to exclude the effects of
the
amended gas charge settlement agreement and merger-related costs
of $64.7
million and $7.5 million after tax, respectively, in fiscal 2006,
and
restructuring costs for fiscal 2005 and 2004 of $7.9 million and
$10.2
million after tax, respectively. See Item 7-MD&A-Executive Summary-for
a discussion of management's use of non-GAAP financial measures and
a
reconciliation of GAAP and non-GAAP
earnings.
|
|
(2)
|
Represents
commercial paper at Peoples Energy as discussed in Item
7-MD&A-Financial Sources.
|
|
(3)
|
Includes
$152.0 million of long-term debt of Peoples Gas classified as short-term
debt due to bondholder tender
rights.
|
|
(4)
|
Includes
$90.0 million of long-term debt ($75.0 million for Peoples Gas and
$15.0
million for North Shore Gas) retired in fiscal 2003 and $202.0 million
of
long-term debt of Peoples Gas classified as short-term debt due to
bondholder tender rights.
|
ITEM
7. Management's Discussion and Analysis of Financial Condition and Results
of
Operations
INTRODUCTION
In
this
section, management discusses the financial condition, results of operations,
cash flows, and expected future performance of the Company and its four primary
business segments. The discussion applies to Peoples Energy and its business
segments on a consolidated basis with the exception of the section titled
“Peoples Gas and North Shore Gas Discussions,” which provides information
specific to the Company’s two regulated utility subsidiaries. Certain other
results of operations and information specific to Peoples Gas and North Shore
Gas are also found in Item 1—Business—Gas Distribution Segment and in this Item
7 under Liquidity and Capital Resources.
Management’s
discussion should be read in conjunction with the Company’s Consolidated
Financial Statements and related notes. Unless otherwise noted, earnings per
share are presented on a diluted basis.
EXECUTIVE
SUMMARY
Peoples
Energy is a diversified energy company that conducts operations in four main
business segments:
| · |
Gas
Distribution
|
| · |
Oil
and Gas Production
|
| · |
Energy
Marketing
|
| · |
Energy
Assets
|
The
Gas
Distribution segment has the most significant impact on the Company’s
consolidated financial results. The remaining segments represent a portfolio
of
complementary energy businesses that the Company has developed to diversify
the
sources of consolidated operating income.
The
regulated gas distribution utilities, with service territories in Chicago and
its northern suburbs, form the core of Peoples Energy. Until recently they
have
generated reliable earnings near the rate of return on equity allowed by the
Commission, approximately 11%, since 1994. Fiscal 2006 operating results reflect
continued erosion in Gas Distribution segment results, including a $107.3
million pre-tax gas charge settlement, pursuant to Commission orders issued
on
March 28, 2006 that settled gas charge reconciliation proceedings for fiscal
years 2001 through 2004. Our two natural gas utilities, Peoples Gas and North
Shore Gas, have not increased their delivery rates in eleven years, during
which
time operating costs have increased and throughput has declined.
The
business environment in which Peoples Gas and North Shore Gas operate benefits
from a fundamentally strong economic base. The service territories are mature,
and natural gas has a high penetration in its markets. However, gas usage per
customer has declined steadily in recent years due to lower weather-normalized
demand primarily reflecting customer conservation. It is unclear how much of
the
load loss is permanent, but customers are reacting to higher bills by lowering
their consumption.
The
diversified energy businesses use a low to moderate risk approach to develop
assets and services that can provide long-term growth and supplement the base
of
utility earnings. Since 1998, the contribution of operating income from the
Company’s diversified businesses has grown from an insignificant amount to $59.0
million (including $17.1 million in operating income from the discontinued
operations of the power generation business) in fiscal 2006.
The
Company announced in February 2006 its intention to exit the power generation
business. On January 31, 2006, the Company sold its 100% interest in the
Valencia Energy power development site in New Mexico. On May 31, 2006, the
Company completed the sale of its 27% interest in the SCEP facility to Exelon
Generation Company, LLC. On September 20, 2006, the Company announced that
it
signed an agreement with J-POWER USA Development Co., Ltd. (J-Power) to sell
its
50% interest in the Elwood power generation facility and its 100% interest
in a
fully-permitted power development site, the COB Energy Facility (COB), for
$110
million, subject to certain closing adjustments. These sales will complete
the
divestiture of substantially all power assets owned by Peoples Energy. The
Board
of Directors of J-Power's parent company approved the transactions on
November
30, 2006. Financial results for power generation are now being reported by
Peoples Energy as discontinued operations. Through Elwood and COB, the Company
owned approximately 700 net Megawatts of power generation assets.
Merger.
Pursuant
to the definitive merger agreement entered into between Peoples Energy and
WPS
Resources on July 10, 2006, in August the companies jointly filed an application
for approval of the merger with the Commission. Required regulatory approvals
at
the federal level, including those with the SEC, FERC, and Department of
Justice, either have been or are expected to be received by December 31, 2006.
Special shareholder meetings were held by both companies on December 6, 2006,
to
seek shareholder approval of the transaction.
Shareholders of both WPS Resources and Peoples Energy approved the merger.
The
companies are targeting a closing date for the merger during the first calendar
quarter of 2007. (See Note 1 of the Notes to Consolidated Financial Statements
for further discussion of the merger.)
Rate
Case.
The
Company announced in September 2005 that Peoples Gas and North Shore Gas planned
to file delivery rate increases with the Commission. However, those plans have
been postponed to allow Peoples Energy and WPS Resources to focus on gaining
approvals for the merger. The companies are seeking expedited consideration
of
the application for approval of the merger by the Commission. The application
indicates that Peoples Gas and North Shore Gas will further postpone filing
rate
cases until early 2007, with new rates to take effect in 2008 due to the normal
11-month rate case process in Illinois.
Strategic
Restructuring.
In
fiscal 2004 the Company took actions to improve the financial performance of
its
utilities by restructuring its utility and corporate support areas. The
organizational restructuring targeted elimination of over 100 salaried
positions, or about 10% of the Company’s nonunion workforce. Overall, about 300
employees accepted the voluntary severance offer that accompanied the
restructuring. (See Note 4 of the Notes to Consolidated Financial
Statements.)
Earnings
Outlook.
Due to
the pending merger with WPS Resources, Peoples Energy is not providing a
specific earnings outlook for fiscal 2007 at this time. However, the Company
expects some improvement in earnings, excluding the impact of merger-related
expenses, driven primarily by higher earnings from the Energy Marketing and
Oil
and Gas Production segments. Excluding the effects in fiscal 2006 of the gas
charge settlement, Gas Distribution results are not likely to improve materially
over fiscal 2006 absent increases in delivery rates, which are not expected
before the second quarter of fiscal 2008.
Key
planning assumptions utilized by the Company for fiscal 2007 include normal
weather based on a 10-year average of 6,175 degree days (representing a change
from the Company’s previous degree day planning assumption, which in fiscal 2006
utilized a 30-year average of 6,408 degree days), an average NYMEX gas price
of
$7.50 per MMbtu, a 2.25% utility bad debt rate, and higher expenses in the
Gas
Distribution and Corporate and Other segments. Capital expenditures are
estimated at $250 million, with nearly half in the Gas Distribution segment
and
the remainder primarily in the Oil and Gas Production segment. No acquisitions
have been budgeted in the Oil and Gas Production segment. Other assumptions
include higher interest expense, a 35% effective tax rate, and slightly higher
common shares outstanding.
Financial
Results
Financial
results for fiscal years 2006 and 2005 are summarized in the following table.
Operating income for fiscal 2006 includes a $107.3 million pre-tax charge ($1.68
per share after tax) for settlement of utility gas charge proceedings for fiscal
years 2001 through 2004, as well as related civil litigation, and $8.9 million
of expenses (pre-tax) related to the Company’s recently announced proposed
merger with WPS Resources. Results for fiscal 2005 include $13.1 million in
pension charges (pre-tax) related to the Company’s 2004 organizational
restructuring. Income from discontinued operations relates to the Company’s
power generation business. Ongoing operating income (non-GAAP) and ongoing
income from continuing operations (non-GAAP) are defined as GAAP operating
income and GAAP income from continuing operations, respectively, adjusted to
exclude the effects of the fiscal 2006 settlement charge, merger expenses,
and
last year’s restructuring charge. Management believes that such measures of
ongoing results are useful for year-over-year comparisons since charges of
this
magnitude
are infrequent and affect the comparability of operating results. Ongoing
operating income and ongoing income from continuing operations are used
internally to measure performance and in reports for management and the
Company’s Board of Directors.
|
Merger,
Restructuring
|
|||||||||||||||||||
|
Ongoing
|
and
Settlement
|
As
Reported
|
|||||||||||||||||
|
(In
Thousands, except per share amounts)
|
(non-GAAP
)
|
Charges
|
(GAAP
)
|
||||||||||||||||
|
For
Fiscal Years Ended September 30,
|
2006
|
2005
|
2006
|
2005
|
2006
|
2005
|
|||||||||||||
|
Operating
Income (Loss):
|
|||||||||||||||||||
|
Gas
Distribution
|
$
|
94,606
|
$
|
137,335
|
$
|
(107,330
|
)
|
$
|
-
|
$
|
(12,724
|
)
|
$
|
137,335
|
|||||
|
Oil
and Gas Production
|
31,097
|
16,853
|
-
|
-
|
31,097
|
16,853
|
|||||||||||||
|
Energy
Marketing
|
8,959
|
13,471
|
-
|
-
|
8,959
|
13,471
|
|||||||||||||
|
Energy
Assets
|
1,766
|
1,727
|
-
|
-
|
1,766
|
1,727
|
|||||||||||||
|
Corporate
and Other
|
(18,368
|
)
|
(6,828
|
)
|
(8,944
|
)
|
(13,141
|
)
|
(27,312
|
)
|
(19,969
|
)
|
|||||||
|
Total
Operating Income (Loss)
|
$
|
118,060
|
$
|
162,558
|
$
|
(116,274
|
)
|
$
|
(13,141
|
)
|
$
|
1,786
|
$
|
149,417
|
|||||
|
Income
(loss) from continuing operations
|
$
|
44,206
|
$
|
74,766
|
$
|
(72,147
|
)
|
$
|
(7,918
|
)
|
$
|
(27,941
|
)
|
$
|
66,848
|
||||
|
Income
from discontinued operations,
|
|||||||||||||||||||
|
net
of income taxes
|
10,305
|
11,285
|
|||||||||||||||||
|
Net
Income (Loss)
|
$
|
(17,636
|
)
|
$
|
78,133
|
||||||||||||||
|
Per
Diluted Share:
|
|||||||||||||||||||
|
Income
(loss) from continuing operations
|
$
|
1.14
|
$
|
1.96
|
$
|
(1.87
|
)
|
$
|
(0.21
|
)
|
$
|
(0.73
|
)
|
$
|
1.75
|
||||
|
Income
from discontinued operations
|
0.27
|
0.30
|
|||||||||||||||||
|
Net
Income (Loss)
|
$
|
(0.46
|
)
|
$
|
2.05
|
||||||||||||||
Ongoing operating income for fiscal 2006 decreased $44.5 million, primarily driven by the following items:
| · |
Gas
Distribution deliveries for the year declined an estimated 4% from
the
prior year due to customer conservation. In addition, fiscal 2006
utility
deliveries were negatively impacted by 10% warmer than normal weather.
Gas
Distribution results were also negatively impacted by sharply higher
operating expenses.
|
| · |
Pursuant
to the amended gas charge settlement, Hub revenues for the Gas
Distribution segment in fiscal 2006 are being recorded as a credit
to
customers’ gas charges, negatively impacting year-over-year comparisons by
$10.7 million.
|
| · |
Oil
and Gas Production volumes were up 2% for fiscal 2006 compared to
a year
ago. This improvement reflects strong performance of both existing
and new
wells and the impact of the Company’s fiscal 2006 Will-Drill acquisition,
offset by the normal decline rate of existing production. Net realized
prices increased sharply in fiscal 2006, partially offset by higher
operating costs.
|
| · |
Energy
Marketing results were negatively impacted by an unrealized loss
of $17.6
million for the year due to LOCOM inventory adjustments and MTM accounting
of energy contracts, the impact of which was magnified by a significant
decline in the market price of natural gas during the latter half
of
September 2006. Approximately $15 million of the year-end impact
from
these adjustments is timing related and is expected to reverse over
fiscal
2007.
|
| · |
Year-over-year
comparisons were negatively impacted by a $6.8 million gain in last
year’s
fourth quarter associated with the sale by Trigen-Peoples District
Energy
(of which Peoples Energy owned a 50% interest) of its district heating
and
cooling plant in Chicago, which was reported in the Corporate and
Other
segment.
|
RESULTS
OF OPERATIONS
Statement
of Operations Variations
Fiscal
2006
.
The
Company’s revenues and cost of energy sold increased $418.4 million and $398.9
million, respectively. The increases are due to the impact of higher commodity
prices at the Gas Distribution and Energy
Marketing
segments as well as a 2% year-over-year increase in average daily production
volumes and higher net realized prices at the Oil and Gas Production segment.
These increases were partially offset by the impacts on the Gas Distribution
segment of warmer weather and an estimated 4% decrease in deliveries resulting
from customer conservation. Revenue comparisons were also adversely impacted
by
the change in the regulatory treatment of Hub revenue in the Gas Distribution
segment.
In
fiscal
2006, the Company recorded a $107.3 million pretax charge related to a
settlement of the Company's gas charge proceedings for fiscal years 2001 through
2004 approved by the Commission, as discussed in Notes 2C and 8A of the Notes
to
Consolidated Financial Statements. Also, the Company recorded $8.9 million
of
costs incurred in connection with the Merger. See Note 1 of the Notes to
Consolidated Financial Statements for further discussion of the
Merger.
In
fiscal
2005, the Company recorded $13.1 million in pension-related charges
resulting from its organizational restructuring commenced in the fall of fiscal
2004 (as described in Note 4 of the Notes to the Consolidated Financial
Statements).
Utility
environmental costs increased $3.2 million for fiscal 2006 and relate to
investigation and remediation activities at multiple sites that formerly had
operations for gas manufacturing and the storage of manufactured gas (see Note
7
of the Notes to Consolidated Financial Statement for further discussion). These
costs are recovered through the utilities' rate mechanism and a similar amount
is included in revenues, therefore these costs do not affect operating
income.
Operation
and maintenance expense, excluding the above-mentioned merger costs,
environmental costs and restructuring-related pension charges, increased $31.0
million. Significant items to note in fiscal 2006 were:
| · |
Increased
bad debt expense at the Gas Distribution segment of $6.5 million
for
fiscal 2006 due to high natural gas prices and their corresponding
impact
on revenues.
|
| · |
Increased
pension expense at Corporate and the Gas Distribution segment totaling
$9.9 million due to lower discount
rates.
|
| · |
Increased
direct labor costs at Corporate and the Gas Distribution segment
totaling
$4.6 million for fiscal 2006, primarily due to increases in wages
and
headcount.
|
| · |
Increased
lease operating, exploration and general and administrative costs
at the
Oil and Gas Production segment totaling $7.5
million.
|
| · |
Rate
case costs of $2.0 million expensed during fiscal 2006.
|
Other
Variances for 2006.
| · |
DD&A
increased $7.5 million in total and at the Oil and Gas Production
segment
increased $6.7 million, primarily due to the impacts of higher production
and higher DD&A rates.
|
| · |
Taxes,
other than income taxes, increased $16.7 million primarily due to
higher
revenue taxes ($13.9 million) in the Gas Distribution segment due
to
higher revenues. Revenue taxes are recovered through the utilities’ rate
mechanism and a similar amount included in revenues; therefore, these
costs do not affect operating
income.
|
| · |
Equity
investment income was $7.8 million in fiscal 2006 compared to $10.3
million in fiscal 2005. Fiscal 2006 results include the $7.8 million
pretax gain associated with the first quarter sale of certain assets
at
the Company’s EnerVest Energy, L.P. (EnerVest) partnership. Fiscal 2005
results include a $6.8 million gain related to the fourth quarter
sale of
assets by the Company's equity investment, Trigen-Peoples District
Energy
(recorded in the Corporate and Other segment). Fiscal 2005 results
also
reflect a full year of equity investment income from both these
investments.
|
| · |
Interest
expense increased $11.0 million due primarily to higher interest
rates,
higher short-term borrowing balances, and an increase in gas costs
refundable to customers through rate
adjustments.
|
| · |
Income
tax expense decreased $60.8 million primarily due to the charge for
the
amended settlement agreement related to the Company's gas charge
proceedings and related tax benefit of $42.7 million. The effective
tax
rate on fiscal 2006 ongoing income (non-GAAP), excluding the impact
of the
gas charge settlement and merger costs) was about 32%, down from
36% last
year, due to the impact of lower income before taxes and federal
Medicare
subsidies excludable from taxable
income.
|
| · |
Pre-tax
income from discontinued operations totaled $17.1 million for fiscal
2006
compared to $18.7 million in fiscal 2005. Fiscal 2006 results included
a
$4.1 million pre-tax gain from the sale of SCEP, a $1.8 million pre-tax
loss from the sale of the Valencia development site, and lower
depreciation expense at Elwood. Fiscal 2005 results reflect a full
year of
SCEP equity investment income.
|
Fiscal
2005
.
The
Company’s revenues and cost of energy sold increased $339.4 million and $337.6
million, respectively, in fiscal 2005 compared to fiscal 2004. The increases
are
due to higher commodity prices in the Gas Distribution segment and increased
sales volumes in the Energy Marketing segment, partially offset by a 5.1%
decrease in Gas Distribution deliveries resulting from warmer weather and
ongoing conservation measures by utility customers. In addition, average daily
production volumes at the Oil and Gas Production segment were down 12% compared
to the prior year due to well performance, rig availability, and other timing
delays.
The
Company recorded $13.1 million in pension-related charges in fiscal 2005
resulting from its organizational restructuring commenced in 2004, compared
to
$17.0 million in restructuring costs recorded in fiscal 2004 (as described
in
Note 4 of the Notes to Consolidated Financial Statements).
Utility
environmental costs increased $13.1 million and relate to investigation and
remediation activities at multiple sites that formerly had operations for gas
manufacturing and the storage of manufactured gas.
Operation
and maintenance expense, excluding the above-mentioned environmental costs
and
restructuring-related pension charges, decreased $3.3 million. Significant
items
to note in fiscal 2005 were:
| · |
Decreased
direct labor costs primarily at Corporate and the Gas Distribution
segment
of $16.4 million as a result of the organizational
restructuring.
|
| · |
Exploration
costs in the Oil and Gas Production segment decreased $5.1 million,
reflecting a significant dry hole expense recognized in fiscal
2004.
|
| · |
Lease
operating expense and general and administrative expenses in the
Oil and
Gas Production segment increased $5.1 million in aggregate primarily
as a
result of a general increase in the cost of goods and
services.
|
| · |
Increased
outside service expense of $3.7 million, much of which related to
Sarbanes-Oxley compliance work.
|
| · |
Increased
insurance, employee group insurance and other benefit expenses totaling
$6.6 million.
|
Other
Variances for 2005.
| · |
DD&A
decreased $8.1 million mainly due to the $6.6 million impact of the
approval by the Commission in April 2005 of new depreciation rates
that
reflect longer useful lives on utility plant (Commission Depreciation
Order). The Oil and Gas Production segment also had lower DD&A expense
($1.6 million) in fiscal 2005.
|
| · |
Taxes,
other than income taxes, increased $14.3 million primarily due to
higher
revenue taxes in the Gas Distribution segment.
|
| · |
Equity
investment income increased $5.9 million primarily due to the $6.8
million
gain related to the sale of assets by the Company's equity investment,
Trigen-Peoples District Energy.
|
| · |
Interest
expense increased $2.2 million due primarily to higher interest
rates.
|
| · |
Income
tax expense increased $3.9 million as tax expense in fiscal 2004
was
positively impacted by several items, including adjustments to accrued
income taxes based on updated estimates of income tax liabilities
and tax
legislation which resulted in the Company realizing tax benefits
from
dividends reinvested in Peoples Energy stock under the Company's
Employee
Stock Ownership Plan.
|
| · |
Income
from discontinued operations, net of taxes, increased $4.5 million
primarily due to the results of the Energy Assets segment’s Elwood
facility, which included the Company’s portion ($4.1 million) of a
reduction in prior and current period expenses, primarily depreciation
on
generating equipment.
|
Segment
Discussion
A
summary
of the Company’s operating income by segment, income from discontinued
operations, and variations between periods, is presented below.
|
For
Fiscal Years Ended
|
||||||||||||||||
|
September
30,
|
Increase/(Decrease
)
|
|||||||||||||||
|
(In
Thousands)
|
2006
|
2005
|
2004
|
2006
vs. 2005
|
|
|
2005
vs. 2004
|
|
||||||||
|
Operating
income:
|
||||||||||||||||
|
Gas
Distribution
|
$
|
(12,724
|
)
|
$
|
137,335
|
$
|
141,158
|
$
|
(150,059
|
)
|
$
|
(3,823
|
)
|
|||
|
Oil
and Gas Production
|
31,097
|
16,853
|
41,537
|
14,244
|
(24,684
|
)
|
||||||||||
|
Energy
Marketing
|
8,959
|
13,471
|
9,879
|
(4,512
|
)
|
3,592
|
||||||||||
|
Energy
Assets
|
1,766
|
1,727
|
1,575
|
39
|
152
|
|||||||||||
|
Corporate
and Other
|
(27,312
|
)
|
(19,969
|
)
|
(41,120
|
)
|
(7,343
|
)
|
21,151
|
|||||||
|
Total
operating income
|
$
|
1,786
|
$
|
149,417
|
$
|
153,029
|
$
|
(147,631
|
)
|
$
|
(3,612
|
)
|
||||
|
Income
from discontinued operations:
|
||||||||||||||||
|
Energy
Assets- Power generation
|
$
|
17,133
|
$
|
18,760
|
$
|
11,353
|
$
|
(1,627
|
)
|
$
|
7,407
|
|||||
|
Corporate
and Other
|
(31
|
)
|
(31
|
)
|
(31
|
)
|
-
|
-
|
||||||||
|
Less:
income tax expense
|
6,797
|
7,444
|
4,500
|
(647
|
)
|
2,944
|
||||||||||
|
Income
from discontinued operations
|
$
|
10,305
|
$
|
11,285
|
$
|
6,822
|
$
|
(980
|
)
|
$
|
4,463
|
|||||
Gas
Distribution Segment.
Revenues
of Peoples Gas and North Shore Gas are directly impacted by fluctuations in
weather because both companies have a large number of heating customers.
Fluctuations in weather have the potential to significantly impact year-to-year
comparisons of operating income and cash flow.
Revenues
of Peoples Gas and North Shore Gas are also affected by changes in the unit
cost
of the utilities’ gas purchases and do not include the cost of gas supplies for
customers who purchase gas directly from producers and marketers. In a steady
gas price environment, the unit cost of gas does not have a significant direct
effect on operating income because the utilities’ tariffs provide for
dollar-for-dollar recovery of gas costs. (See Note 2K of the Notes to
Consolidated Financial Statements.) However, significant changes in gas costs
can materially affect the reserve for uncollectible accounts, customer demand
and working capital needs.
Fiscal
2006 revenues
for
the
Gas Distribution segment increased $233.2 million over 2005, primarily due
to
the impact of changes in commodity prices (an increase of $317 million) that
are
recovered on a dollar-for-dollar basis. This impact was partially offset by
decreases in deliveries due to warmer weather ($21 million), lower
weather-normalized demand ($98 million) and by the impact of the change in
the
regulatory treatment of Hub revenues ($10.7 million) due to the amended
settlement agreement. Operating income for fiscal 2006 decreased $150.1 million
reflecting the impact of the amended settlement agreement. The $107.3 million
in
settlement charges recorded in fiscal 2006 and the $13.3 million liability
recognized in prior periods reflect the following settlement amounts: $100
million in refunds to customers; $5 million related to the payment to the City
and the AG pursuant to the settlement agreement; $10.7 million to reflect a
change in regulatory treatment for fiscal 2005 Hub revenues; and an estimated
$5
million net increase in bad debt expense primarily related to the termination
of
collection activities on approximately $207 million of bad debt written off
during fiscal years 2000-2005.
For
fiscal
2006,
ongoing (non-GAAP) operating income was $94.6 million compared to $137.3 million
last year. The decrease was due primarily to the impact of lower gas deliveries
($10.7 million), including an estimated 4% decline in weather normalized demand
due to the impact of customer conservation, a weather insurance recovery
recorded in fiscal 2005 ($3.5 million), the change in treatment of 2006 Hub
revenues ($10.7 million), and higher operating expenses ($18.3 million). Weather
for fiscal 2006 was 89 degree days or 2% warmer than last year. The increase
in
operating costs primarily reflected higher pension expenses ($7.7 million),
labor-related expenses
($2.1
million), rate case costs ($2.0 million) and higher bad debt expense. Bad debt
increased $6.5 million due to high natural gas prices and their corresponding
impact on revenues. The bad debt accrual rate remained unchanged at
approximately 2.25% of revenue.
Fiscal
2005 revenues increased $186.6 million compared to fiscal 2004, primarily due
to
the impact on revenues of higher commodity prices ($221 million) that are
recovered on a dollar-for-dollar basis. Partially offsetting this effect were
decreases in deliveries due primarily to warmer weather ($31 million). Weather
was 4% warmer compared to fiscal 2004. Operating income decreased $3.8 million
compared with the previous year due to the effects of warmer weather ($5
million), lower weather-normalized deliveries ($8 million), higher outside
services expense ($3.0 million), the 2004 insurance recovery ($2.5 million)
related to mercury cleanup costs incurred in prior years and increases in
numerous other nonlabor expenses aggregating $11.3 million. Partially offsetting
these negative variations are the effect of the fiscal 2004 accounts receivable
adjustment ($6.9 million), decreased direct labor costs related to the
organizational restructuring ($9.6 million), reduced depreciation expense ($6.6
million) as a result of the Commission Depreciation Order, and increased hub
operating income ($2.2 million).
The
following table summarizes revenue, deliveries and other statistics for the
Gas
Distribution segment.
|
Gas
Distribution Statistics
|
||||||||||||||||
|
For
Fiscal Years Ended
|
Increase/(Decrease
)
|
|||||||||||||||
|
Margin
Data
|
September
30,
|
Fiscal
2006 vs.
|
Fiscal
2005 vs.
|
|||||||||||||
|
(In
Thousands)
|
2006
|
2005
|
2004
|
Fiscal
2005
|
Fiscal
2004
|
|||||||||||
|
Gas
Distribution revenues:
|
||||||||||||||||
|
Sales
|
||||||||||||||||
|
Residential
|
$
|
1,485,753
|
$
|
1,290,716
|
$
|
1,148,499
|
$
|
195,037
|
$
|
142,217
|
||||||
|
Commercial
|
242,196
|
209,712
|
184,756
|
32,484
|
24,956
|
|||||||||||
|
Industrial
|
41,575
|
36,368
|
30,324
|
5,207
|
6,044
|
|||||||||||
|
Total
sales
|
1,769,524
|
1,536,796
|
1,363,579
|
232,728
|
173,217
|
|||||||||||
|
Transportation
|
||||||||||||||||
|
Residential
|
35,156
|
32,360
|
32,354
|
2,796
|
6
|
|||||||||||
|
Commercial
|
50,544
|
48,719
|
47,285
|
1,825
|
1,434
|
|||||||||||
|
Industrial
|
18,828
|
19,880
|
19,437
|
(1,052
|
)
|
443
|
||||||||||
|
Contract
pooling
|
29,448
|
20,694
|
15,372
|
8,754
|
5,322
|
|||||||||||
|
Total
transportation
|
133,976
|
121,653
|
114,448
|
12,323
|
7,205
|
|||||||||||
|
Total
Hub revenues
|
-
|
10,662
|
7,620
|
(10,662
|
)
|
3,042
|
||||||||||
|
Other
Gas Distribution revenues
|
18,380
|
19,563
|
16,436
|
(1,183
|
)
|
3,127
|
||||||||||
|
Total
Gas Distribution revenues
|
1,921,880
|
1,688,674
|
1,502,083
|
233,206
|
186,591
|
|||||||||||
|
Less:
Gas costs
|
1,272,633
|
1,034,376
|
868,518
|
238,257
|
165,858
|
|||||||||||
|
Gross
margin
|
649,247
|
654,298
|
633,565
|
(5,051
|
)
|
20,733
|
||||||||||
|
Less:
Revenue taxes and surcharges
|
164,273
|
150,325
|
138,841
|
13,948
|
11,484
|
|||||||||||
|
Environmental costs recovered
|
33,654
|
30,437
|
17,384
|
3,217
|
13,053
|
|||||||||||
|
Net
margin (1)
|
$
|
451,320
|
$
|
473,536
|
$
|
477,340
|
$
|
(22,216
|
)
|
$
|
(3,804
|
)
|
||||
|
Gas
Distribution deliveries (MDth):
|
||||||||||||||||
|
Gas
sales
|
||||||||||||||||
|
Residential
|
103,656
|
110,429
|
116,939
|
(6,773
|
)
|
(6,510
|
)
|
|||||||||
|
Commercial
|
18,210
|
19,349
|
20,303
|
(1,139
|
)
|
(954
|
)
|
|||||||||
|
Industrial
|
3,293
|
3,607
|
3,597
|
(314
|
)
|
10
|
||||||||||
|
Total
gas sales
|
125,159
|
133,385
|
140,839
|
(8,226
|
)
|
(7,454
|
)
|
|||||||||
|
Transportation
|
||||||||||||||||
|
Residential
|
19,504
|
19,927
|
21,061
|
(423
|
)
|
(1,134
|
)
|
|||||||||
|
Commercial
|
42,474
|
41,239
|
43,646
|
1,235
|
(2,407
|
)
|
||||||||||
|
Industrial
|
21,146
|
23,131
|
23,756
|
(1,985
|
)
|
(625
|
)
|
|||||||||
|
Total
transportation
|
83,124
|
84,297
|
88,463
|
(1,173
|
)
|
(4,166
|
)
|
|||||||||
|
Total
Gas Distribution deliveries
|
208,283
|
217,682
|
229,302
|
(9,399
|
)
|
(11,620
|
)
|
|||||||||
|
Total
Hub volumes
|
-
|
22,784
|
19,381
|
(22,784
|
)
|
3,403
|
||||||||||
|
Gross
margin per Dth delivered (3)
|
$
|
3.12
|
$
|
2.96
|
$
|
2.73
|
$
|
0.16
|
$
|
0.23
|
||||||
|
Net
margin per Dth delivered (3)
|
$
|
2.17
|
$
|
2.13
|
$
|
2.05
|
$
|
0.04
|
$
|
0.08
|
||||||
|
Average
cost per Dth of gas sold
|
$
|
10.17
|
$
|
7.75
|
$
|
6.17
|
$
|
2.42
|
$
|
1.58
|
||||||
|
Actual
heating degree days
|
5,775
|
5,864
|
6,091
|
(89
|
)
|
(227
|
)
|
|||||||||
|
Normal
heating degree days (2)
|
6,408
|
6,427
|
6,427
|
|||||||||||||
|
Actual
heating degree days as a percent
|
||||||||||||||||
|
of
normal (actual/normal)
|
90
|
91
|
95
|
|||||||||||||
|
(1)
|
As
used above, net margin is not a financial measure computed under
GAAP but
represents an operating performance measure. Gross margin is the
GAAP
measure most closely related to net margin. Management believes net
margin
to be useful in understanding the Gas Distribution segment's operations
because the utility subsidiaries are allowed, under their tariffs,
to
recover gas costs, revenue taxes and environmental costs from their
customers on a dollar-for-dollar
basis.
|
|
(2)
|
Normal
heating degree days for fiscal 2004 and 2005 are based on a 30-year
average of monthly temperatures at Chicago's O'Hare Airport for the
years
1970-1999. Normal heating degree days for fiscal 2006 are based on
a
30-year average of monthly temperatures at Chicago's O'Hare Airport
for
the years 1975-2004.
|
|
(3)
|
Margin
per Dth is based upon gas distribution and transportation activity
and
excludes the impact of hub revenues and hub
volumes.
|
Oil
and Gas Production Segment.
Revenues
and operating income for fiscal 2006 increased $26.1 million and $14.2 million,
respectively, compared with the same period last year. The increase in revenue
is due primarily to higher net realized commodity prices as older hedge
positions continued to roll off and a 2% increase in equivalent average daily
production. The improvement in production from a year ago reflects the results
of the Company’s 2006 drilling program and the impact of the February 2006
acquisition of properties from Will-Drill Resources, Inc. (Will-Drill),
partially offset by the normal decline of existing production. Fiscal 2006
operating income results benefited from significantly higher net realized prices
due to a lower percentage of gas volumes hedged (71% compared to nearly 100%
a
year ago), a small increase in production, and higher results from the Company’s
EnerVest partnership, which benefited from a $7.8 million pretax gain associated
with the sale of assets. Last year’s net realized price was negatively impacted
by an $8.4 million hedge ineffectiveness charge resulting from wider than normal
differentials between NYMEX and wellhead prices primarily due to the impact
of
hurricanes Katrina and Rita. The improvements in production and realized
commodity prices were partially offset by higher operating costs ($17.3
million), most notably higher general and administrative expense ($6.0 million)
and depletion expenses ($6.7 million). In fiscal 2006, the Company drilled
58
wells (11 related to the Will-Drill acquisition) with a success rate of
93%.
Fiscal
2005 revenues
and
operating income decreased $23.2 million and $24.7 million, respectively,
compared with fiscal 2004 due mainly to lower production volumes and oil and
gas
hedge ineffectiveness ($8.4 million). Hedge ineffectiveness was primarily due
to
the impact of hurricanes Katrina and Rita on the price differentials between
NYMEX and field prices. On an equivalent basis, average daily production volumes
declined 12% compared to the prior year due to well performance, rig
availability, and other timing delays. Increases in lease operating expense
($3.7 million) and lower equity investment income from the Company’s investment
in EnerVest ($1.3 million), higher production taxes (associated with higher
wellhead gas prices) and administrative costs ($1.5 million) also reduced
operating income comparisons to fiscal 2004. These negative impacts on operating
income were partially offset by lower DD&A expense ($1.6 million) and lower
exploration expense ($5.1 million) compared to the previous year.
The
following table summarizes hedges in place as of October 1, 2007 for the Oil
and
Gas Production segment.
|
Fiscal
2007
|
||||
|
Gas
hedges in place (MMbtus)
|
12,705,000
|
|||
|
Gas
hedges as a percent of estimated fiscal production
|
50
|
%
|
||
|
Percent
of gas hedges that are swaps
|
63
|
%
|
||
|
Average
swap price ($/MMbtu)
|
$
|
5.37
|
||
|
Percent
of gas hedges that are no-cost collars
|
37
|
%
|
||
|
Weighted-average
floor price ($/MMbtu)
|
$
|
5.62
|
||
|
Weighted-average
ceiling price ($/MMbtu)
|
$
|
6.72
|
||
|
Oil
hedges in place (MBbls)
|
182
|
|||
|
Oil
hedges as a percent of estimated fiscal production
|
63
|
%
|
||
|
Average
hedge price ($/Bbl)
|
$
|
37.50
|
||
The
following table summarizes operating statistics from the Oil and Gas Production
segment.
|
For
Fiscal Years Ended September 30,
|
||||||||||
|
2006
|
2005
|
2004
|
||||||||
|
Total
production—gas equivalent (MMcfe)
|
24,712
|
24,319
|
27,853
|
|||||||
|
Daily
average gas production (MMcfd)
|
61.9
|
59.6
|
67.0
|
|||||||
|
Daily
average oil production (MBd)
|
1.0
|
1.2
|
1.5
|
|||||||
|
Daily
average production—gas equivalent (MMcfed)
|
67.7
|
66.6
|
76.1
|
|||||||
|
Gas
production as a percentage of total production
|
91
|
%
|
90
|
%
|
88
|
%
|
||||
|
Percent
of production hedged during the period—gas
|
71
|
%
|
98
|
%
|
94
|
%
|
||||
|
Percent
of production hedged during the period—oil
|
85
|
%
|
99
|
%
|
77
|
%
|
||||
|
Net
realized gas price received ($/Mcf)
|
$
|
5.28
|
$
|
4.15
|
$
|
4.44
|
||||
|
Net
realized oil price received ($/Bbl)
|
$
|
24.62
|
$
|
24.10
|
$
|
26.85
|
||||
|
DD&A
rate ($/Mcfe)
|
$
|
2.11
|
$
|
1.87
|
$
|
1.69
|
||||
|
Average
lease operating expense ($/Mcfe)
|
$
|
0.72
|
$
|
0.70
|
$
|
0.48
|
||||
|
Average
production taxes ($/Mcfe)
|
$
|
0.57
|
$
|
0.50
|
$
|
0.34
|
||||
Due
to
higher
market prices and lower hedge percentages, net realized prices increased in
fiscal 2006. The increase in the 2006 DD&A rate was caused by production mix
and the addition of unproven capital and costs associated with the development
of both proven and unproven reserves.
On
February 23, 2006 the Company announced that it had acquired certain oil and
gas
properties in eastern Texas, northern Louisiana and Mississippi from Will-Drill
for approximately $139 million. The acquired properties, virtually all of which
are now operated by the Company, consist of approximately 60,000 gross acres
in
33 fields in the heart of the Cotton Valley / Travis Peak (Hosston) gas trend.
The acquisition initially added approximately 7.5 MMcfed to existing production
and an estimated 59 Bcfe of proven reserves. Approximately 47% of the acquired
reserves are developed. The Will-Drill acquisition added 4.8 MMcfed to the
annual average production. The Company expects to spend approximately $60
million of drilling capital on the acquired properties in fiscal
2007.
During
April 2005, the Company acquired properties in South Texas for approximately
$6
million. Although there was minimal production at the time of acquisition,
these
properties are providing current and future drilling opportunities.
On
July
30, 2004, the Company acquired certain oil and gas properties in eastern Texas
from a private entity for approximately $10 million. Initial development of
the
acquired reserves began in fiscal 2005 with capital spending on these properties
totaling $19.8 million. The acquired properties, which are operated by the
Company, are located in close proximity to the existing Peoples Energy
Production holdings in eastern Texas. On December 31, 2003, the Company
acquired, through a series of transactions, certain oil and gas properties
located in Texas for approximately $33.1 million. The acquired reserves, 88%
of
which are natural gas, contributed approximately 3.3 MMcfe per day of production
to the Company’s fiscal 2004 production. The majority of the acquired properties
are located adjacent to or in close proximity to existing holdings of the
Company, and each of the acquired properties is operated by the
Company.
Energy
Marketing Segment.
Revenues
for fiscal 2006 increased $155.2 million, primarily due to higher commodity
prices, partially offset by a decline in gas volumes sold. Operating income
for
fiscal 2006 was $9.0 million compared to $13.5 million in fiscal 2005. Energy
Marketing’s margins can be volatile and are small in relation to the market
value of the commodity. As a result, revenue statistics are not necessarily
indicative of Energy Marketing operating income results. Retail results declined
from a year ago due primarily to LOCOM and MTM accounting adjustments of energy
contracts, the impact of which was magnified by a significant decline in the
market price of natural gas during the latter half of September 2006, as well
as
higher operating expenses, partially due to higher sales and marketing expenses
associated with customer growth. Lower retail results were
partially
offset by higher wholesale marketing results, reflecting additional pipeline
and
storage capacity under contract and the positive impact of price volatility
and
spreads on storage and transportation optimization strategies, partially offset
by LOCOM adjustments and MTM accounting. For the year, the number of retail
customers increased approximately 60% from a year ago, to almost 41,000, as
Energy Marketing expanded its customer base in Michigan and Ohio. Retail gas
deliveries declined slightly to 48 Bcf, while electric deliveries increased
24%
to 1.7 million Mwh from 1.4 million Mwh a year ago. LOCOM inventory loss
adjustments ($16.3 million), fair value hedge accounting losses ($3.2 million),
ineffectiveness gains ($0.6 million) and MTM accounting gains ($1.3 million)
resulted in an unrealized loss for the Energy Marketing segment of $17.6 million
for fiscal 2006. This net unrealized loss includes both MTM activity of hedges
for settlement in future periods and settled within the current period, as
well
as LOCOM inventory loss adjustments that are expected to reverse when the gas
inventory is sold pursuant to existing contracts. Approximately $15 million
of
the year-end impact (net) is expected to reverse over the course of the next
fiscal year and relates primarily to the LOCOM adjustment of $16.3 million.
The
earnings variability resulting from accounting timing can be significant from
period to period, even when the underlying economic position is
unchanged.
The
Company uses derivatives to mitigate commodity price risk and substantially
lock
in the profit margin that it will ultimately realize when inventory volumes
are
withdrawn from storage. Under fair value hedge accounting, which Energy
Marketing is using for certain storage activity, the MTM adjustment to inventory
is computed using spot prices, while the derivatives used to mitigate the risk
of changes in inventory value are marked-to-market using forward prices. When
the spot price of natural gas changes disproportionately to the forward price,
the difference is recorded in operating results. As a result, earnings are
subject to volatility, even when the underlying expected profit margin over
the
duration of the contracts is unchanged. The volatility resulting from this
accounting can be significant from period to period.
Revenues
for fiscal 2005 increased $173.7 million primarily due to higher retail and
wholesale commodity prices and volumes. Operating income improved $3.6 million,
driven by higher retail margins, higher load and lower operating costs,
partially offset by a $3.3 million MTM loss related to the application of fair
value hedge accounting to certain storage inventory transactions.
The
following table summarizes operating statistics for the Energy Marketing
segment.
|
For
Fiscal Years Ended September 30,
|
||||||||||
|
(In
Thousands, Except Customers)
|
2006
|
2005
|
2004
|
|||||||
|
Wholesale
gas volumes sold (MDth)
|
48,160
|
56,391
|
52,815
|
|||||||
|
Retail
gas volumes sold (Dth)
|
48,289
|
49,923
|
47,965
|
|||||||
|
Number
of retail gas customers
|
37,084
|
23,389
|
24,744
|
|||||||
|
Retail
electric volumes sold (Mwh)
|
1,727
|
1,397
|
1,113
|
|||||||
|
Number
of electric customers
|
3,380
|
2,268
|
1,901
|
|||||||
Energy
Assets Segment.
All
financial results relating to power generation formerly included in this
business segment are now reported as discontinued operations, including prior
year results. Operating income for the Energy Assets segment reflects the
Company’s natural gas liquids (NGL) peaking facility, a 40 mile refinery gas
pipeline, 250 acres of land and related facilities, and certain limited business
development expenses related to ongoing asset investment
opportunities.
Revenues
for
fiscal
2006 increased $4.1 million, primarily due to higher commodity prices and
increased volumes associated with activity at the Company’s propane-based
peaking facility. Fiscal 2006 operating income of $1.8 million was flat compared
to fiscal 2005.
Discontinued
Operations.
The
Company announced in February 2006 its intention to exit the power generation
business. On January 31, 2006, the Company sold its 100% interest in the
Valencia Energy power development site in New Mexico. On May 31, 2006, the
Company completed the sale of its 27% interest in the SCEP facility to Exelon
Generation Company, LLC. On September 20, 2006, the Company announced that
it
signed an agreement
with
J-Power to sell its 50% interest in the Elwood power generation facility and
its
100% interest in a fully-permitted power development site, the COB Energy
Facility (COB), for $110 million, subject to certain closing adjustments. These
sales will complete the divestiture of substantially all power assets owned
by
Peoples Energy. The Board of Directors of J-Power's parent company approved
the
transactions on November 30, 2006. Financial results for power generation are
now being reported by Peoples Energy as discontinued operations. Through Elwood
and COB, the Company owned approximately 700 net Megawatts of power generation
assets.
Fiscal
2006 income from discontinued operations for the Energy Assets segment decreased
$1.6 million (before taxes) due to the absence of equity investment income
from
SCEP and the $1.8 million loss on the sale of the Valencia development site,
partially offset by the $4.1 million gain on the sale of SCEP. Amortization
of
capitalized interest related to the construction of the Elwood power generation
facility was formerly included in the Corporate and Other segment.
Fiscal
2005 income from discontinued operations for the Energy Assets segment increased
$7.4 million (before taxes) from the prior year largely as a result of lower
depreciation expense impact on equity investment income for the Elwood facility
and lower other expenses. In connection with its fiscal 2004 year-end audit,
the
Elwood partnership determined that depreciation expense related to current
and
prior periods should be adjusted, primarily to recognize greater salvage value
of its generating equipment. This adjustment positively impacted fiscal 2005
results by $4.1 million, of which $2.2 million related to prior
periods.
The
electric capacity of Elwood Energy LLC (Elwood) has been sold through long-term
contracts with Exelon Generation Company, LLC (Exelon), Engage Energy America
LLC (Engage) and Aquila, Inc. (Aquila). Effective December 31, 2004, the
contract with Engage terminated and the related electric capacity is being
purchased by Exelon. On June 15, 2006, Aquila assigned its Elwood power sales
agreement to Constellation Energy Commodities Group, Inc, a subsidiary of
Constellation Energy Group, Inc. In August 2006, S&P and Moody’s ratings on
Elwood’s bonds were upgraded to BB- and Ba1, respectively, with a stable
outlook.
Corporate
and Other Segment.
The
operating loss for fiscal 2006 increased $7.3 million and includes $8.9 of
merger-related expenses. Results for fiscal 2005 included $13.1 million in
restructuring charges. Absent these costs, corporate and other expenses
increased $11.5 million due primarily to a $6.8 million gain in fiscal 2005
associated with the sale of certain assets by Trigen-Peoples District Energy
(of
which Peoples Energy owned a 50% interest) and higher legal ($2.4 million)
and
incentive benefit expenses ($3.4 million).
The
operating loss for fiscal 2005 decreased $21.2 million primarily due to direct
labor savings of $6.8 million as a result of the restructuring, the $6.8 million
gain resulting from the sale of the Trigen-Peoples’ district heating and cooling
plant, and a $3.9 million decrease in costs resulting from the 2004
organizational restructuring.
Critical
Accounting Policies
In
preparing the Company’s financial statements using GAAP, management exercises
judgment in the selection and application of accounting principles, including
making estimates and assumptions. Management considers its critical accounting
policies to be those that are important to the representation of the Company’s
financial condition and results of operations. They require management’s most
difficult and subjective or complex judgments, including those that could result
in materially different amounts if the Company reported under different
conditions or using different assumptions. The Company discusses its critical
accounting policies, as well as other accounting policies, with senior members
of management and the Audit Committee, as appropriate. There were no material
changes in the application of each of the critical accounting policies listed
below during fiscal 2006. (See Note 2O of the Notes to the Consolidated
Financial Statements for a discussion of recent accounting pronouncements.)
Regulated
Operations.
Due to
the regulation of the Company’s utility subsidiaries, certain transactions are
recorded based on the accounting prescribed in SFAS No. 71. Regulatory assets
represent probable future revenue associated with certain incurred costs that
will be recovered from customers through the ratemaking process. Regulatory
liabilities represent probable future reductions in revenue or refunds to
customers. Accordingly, actions of the Commission could have an effect on the
amount recovered from or refunded to customers. Any
differences
between recoverable and refundable amounts and the amounts deferred would be
recorded as income or expense at the time of any Commission action (see Notes
2C
and 8 of the Notes to the Consolidated Financial Statements for a discussion
of
the gas charge settlement). If all or a reportable portion of the utility
operations becomes no longer subject to the provision of SFAS No. 71, a
write-off of related regulatory assets or liabilities would be required, unless
some form of transition cost recovery continued through rates established and
collected for the remaining regulated operations. No such change is foreseen
by
management. (See Note 2K of the Notes to Consolidated Financial Statements
for a
summary of regulatory assets and liabilities recorded under this
policy.)
Environmental
Activities Relating to Former Manufactured Gas Operations.
The
Company’s utility subsidiaries, their 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). The
utility subsidiaries are accruing and deferring the costs they incur in
connection with environmental activities at the manufactured gas sites pending
recovery through rates or from other entities. The amounts deferred include
costs incurred but not yet recovered through rates and management’s best
estimates of the costs that the utilities will incur in investigating and
remediating the manufactured gas sites. Management’s estimates are based upon a
probabilistic model and an ongoing review by management of future investigative
and remedial costs.
Management
considers this policy critical due to the substantial uncertainty in the
estimation of future costs with respect to the amount and timing of costs,
and
the extent of recovery from other PRPs. (See Notes 2K and 7 of the Notes to
Consolidated Financial Statements for deferred environmental costs recorded
as
regulatory assets and a discussion of environmental matters.)
Retirement
and Postretirement Benefits.
The
calculation of pension expense relies on actuarial assumptions including
discount rate, long-term rate of return on assets and assumed future increases
in compensation. These assumptions are determined annually and changes to the
assumptions can have a material effect on the amounts recorded from year to
year. The Company bases its discount rate assumption on yields of high quality
long-term, fixed-income bonds. A decrease in the assumed discount rate of 25
basis points would have increased fiscal 2006 pension expense by $1.3
million.
Additionally,
when an employee retires and takes his/her retirement benefit as a lump sum,
a
settlement amount under SFAS No. 88 is calculated representing a portion of
unrecognized gains and losses. The Company has chosen to record this amount
in
the current period instead of amortizing the difference over the expected
average service life of the remaining participants. Both methods are acceptable
under GAAP. Therefore, the timing of retirements can have an effect on the
amount recorded in any given year. (See Note 11 of the Notes to Consolidated
Financial Statements for current year assumptions.)
In
addition, the Company and its subsidiaries currently provide 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. Through the use of an independent actuary, the Company
accrues the expected costs of such benefits during a portion of the employees’
years of service. This accrual is based on assumptions regarding discount rates,
rate of return on assets and health care cost trend rates. 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 accumulated postretirement benefit
obligation at September 30, 2006, by $12.9 million and the aggregate of service
and interest cost components of the net periodic postretirement benefit cost
by
$2.1 million annually. Decreasing the assumed health care cost trend rate by
one
percentage point for each future year would have decreased the accumulated
postretirement benefit obligation at September 30, 2006, by $11.2 million and
the aggregate of service and interest cost components of the net periodic
postretirement benefit cost by $1.7 million annually. A decrease in the assumed
discount rate of 25 basis points would have increased postretirement benefit
cost expense by $0.4 million. (See Note 11 of the Notes to Consolidated
Financial Statements for current year assumptions.)
Derivative
Instruments and Hedging Activities.
The
Company enters into financial derivative contracts to hedge price risk on
natural gas and oil purchases and sales. For each contract, management must
determine whether the underlying transaction qualifies as a hedge under
derivative accounting rules prescribed in SFAS No.
133.
If
contracts do qualify as hedges, they have the effect of reducing, but not
completely eliminating, volatility in earnings. For contracts not qualifying
as
hedges, the change in the fair value of these contracts is recorded in income
monthly and results in potentially significant impacts, both positive and
negative. Additionally, due to the nature of the Company’s businesses, many of
the Company’s contracts for physical purchases and sales of gas, oil or power
meet the definition of a derivative, but are exempt from derivative accounting
requirements under the normal purchases and sales exemption. Under this
exemption, if the transactions are clearly intended to meet the requirements
of
customers, MTM accounting is not required. Management judgment is required
to
make this determination. The application of hedge accounting and the normal
purchase and sales exemption is also subject to contemporaneous documentation
requirements under SFAS No. 133. The Company also manages its levels of floating
and fixed rate interest payments within a specified range through the use of
derivative financial instruments. (See Note 2L of the Notes to Consolidated
Financial Statements for further discussion of the Company’s cash flow and fair
value hedging strategies and the MTM derivative instruments.)
Provision
for Uncollectible Accounts.
The
Company’s subsidiaries accrue for estimated uncollectible accounts as revenues
are recorded. The accrual rates are established based upon historical experience
and projections of future charge-offs resulting from various factors, including
the impacts of natural gas prices and weather. Each quarter, the Company’s
subsidiaries update the projection of future charge-offs based upon the most
current information available, and adjust the reserve for uncollectible
accounts, if necessary.
Depreciation,
depletion and amortization.
The
Company’s provision for depreciation at Peoples Gas and North Shore Gas
substantially reflects the systematic amortization of the original cost of
depreciable property, net of the accumulated reserve for depreciation, over
the
estimated composite remaining useful lives on the straight-line method.
Additionally, actual dismantling cost, net of salvage, is recorded as
depreciation expense in the month incurred. The depreciation rates of Peoples
Gas and North Shore Gas are subject to periodic review by the Commission, which
approves the depreciation rates used for rate-making purposes. Diversified
businesses’ depreciable properties, other than oil and gas producing properties,
are amortized over their estimated useful lives.
In
the
case of oil and gas producing properties, the Company is amortizing associated
capitalized costs by utilizing the successful efforts method of accounting
on
the units-of-production method based on estimated proved oil and gas reserves.
The successful efforts method provides for properties to be aggregated into
cost
centers, or “pools”, with depreciation, depletion and amortization calculated on
a pool- by- pool basis. These pools are comprised of properties in an area
that
share the same general geological characteristics. Unit of production
amortization rates and the aggregation of properties into pools are reviewed
at
least once a year or whenever there is an indication of the need for revision.
Those revisions are accounted for prospectively as changes in accounting
estimates. Acquisition costs are amortized over total proved reserves.
Development costs are amortized over total proved developed reserves. Costs
to
be amortized include all capitalized costs (less accumulated amortization)
and
estimated dismantlement and abandonment costs, net of estimated salvage. The
cost of investments in unproved properties and major development projects are
excluded from the amortization base. These costs and resulting proved reserves
are transferred into the amortization base or expensed at the point when a
determination can be made about the project’s success. (See Note 19 of the Notes
to Consolidated Financial Statements for supplemental disclosures of the
Company’s Oil and Gas Production segment.)
Recent
Accounting Pronouncements
See
Note
2O of the
Notes
to
Consolidated Financial Statements.
LIQUIDITY
AND CAPITAL RESOURCES
The
following is a summary of cash flows for the Company:
|
For
Fiscal Years Ended September 30,
|
||||||||||
|
(In
Thousands)
|
2006
|
2005
|
2004
|
|||||||
|
Net
cash provided by operating activities
|
$
|
131,162
|
$
|
282,152
|
$
|
202,292
|
||||
|
Net
cash used in investing activities
|
$
|
(340,265
|
)
|
$
|
(156,190
|
)
|
$
|
(164,763
|
)
|
|
|
Net
cash provided by (used in) financing activities
|
$
|
233,032
|
$
|
(115,004
|
)
|
$
|
(43,949
|
)
|
||
Cash
provided by operating activities for fiscal 2006 decreased as compared to fiscal
2005, primarily due to the decrease in net income resulting from the impact
of
the gas charge settlement refund (see Note 8 of the Notes to Consolidated
Financial Statements) and other factors described above under “Results of
Operations,” partially offset by favorable net changes in working capital. In
the accompanying cash flow statements, balance sheet changes in current deferred
tax assets, gas in storage and deposits with broker or trustee exclude certain
noncash transactions (primarily the effects of MTM accounting). Changes in
gas
in storage reflect lower-of-cost-or-market adjustments. Additionally, balance
sheet changes in intercompany assets/liabilities of Peoples Gas and North Shore
Gas exclude the noncash effects of derivative activity conducted on their behalf
by Peoples Energy. Net cash used in investing activities increased as a result
of an increase in capital spending, primarily in the Oil and Gas Production
segment. On February 23, 2006, the Company announced that it had acquired
certain oil and gas properties in eastern Texas, northern Louisiana and
Mississippi from Will-Drill for approximately $139 million. Increases in the
return of capital from the Company's equity method investments, primarily
related to the sale of properties by the EnerVest partnership and the
Trigen-Peoples partnership, as well as through the sale of the Company’s
interest in the SCEP facility which resulted in proceeds of approximately
$47 million, were largely offset by an increase in deposits associated with
the
Company’s commodity hedging activities. Net cash provided by financing
activities increased primarily due to additional commercial paper borrowing
($301.6 million) in fiscal 2006, partially related to the Oil and Gas Production
segment acquisition, compared to commercial paper retirement ($47.5 million)
in
fiscal 2005.
Cash
provided by operating activities for fiscal 2005 increased due to favorable
net
changes in working capital. Net cash used in investing activities in fiscal
2005
decreased compared to 2004 as a result of decreased capital spending primarily
in the Oil and Gas Production segment offset by an increase in deposits
associated with the Company's commodity hedging activities driven by price
declines and ratings downgrades on Company long-term debt. The increase in
net
cash used in financing activities in fiscal 2005 compared to 2004 was primarily
due to increased retirements of commercial paper, lower amounts of debt issued
(net of retirements) and to lower amounts of common stock issued under the
continuous equity program and the LTIC Plan in fiscal 2005 compared to fiscal
2004.
See
the
Consolidated Statements of Cash Flows and the discussion of major balance sheet
variations below for more detail.
Balance
Sheet Variations
Total
assets at September 30, 2006, increased $284.6 million as compared to September
30, 2005, due to additional capital investment in the Oil and Gas Production
segment resulting from the Will-Drill acquisition, increases in current
regulatory assets related primarily to MTM accounting for the utility gas costs
hedging program, and increases in noncurrent regulatory assets and capital
investments in the Gas Distribution segment resulting from the recognition
of
asset retirement obligations required under FIN 47. These increases were
partially offset by decreases in derivative assets that are marked-to-market
and
largely relate to utility hedge activity. The decrease in derivative assets
reflects price declines during fiscal 2006 relative to utility supply contracts
(long positions). Current liabilities increased due to additional levels of
commercial paper outstanding (primarily due to the oil and gas properties
acquisition) and an increase in gas costs refundable through rate adjustments,
partially offset by a decrease in accrued taxes due to lower taxable
income and by a decrease in regulatory liabilities largely corresponding
with the above decrease in derivative assets that are marked-to-market.
Settlement
of these assets is included as an adjustment to gas costs included in customer
bills. Deferred credits and other liabilities increased due to the recognition
of asset retirement obligations required under FIN 47. The increase in the
Company's capitalization was the result of the combined decrease in the
accumulated other comprehensive loss and increase in common stock (primarily
issued through the Direct Purchase and Investment Plan and the LTIC Plans),
partially offset by the reduction in retained earnings, due primarily to the
$64.7 million after tax charge related to the gas charge settlement and dividend
payments of $83.7 million. The decrease in the accumulated other comprehensive
loss reflects both price declines related to short position derivatives
accounted for as cash flow hedges at the Company's Oil and Gas Production and
Energy Marketing segments and a net decrease in derivative positions at the
Oil
and Gas Production segment.
Financial
Sources
The
Company and Peoples Gas have access to outside capital markets, commercial
paper
markets and internal sources of funds that together provide sufficient resources
to meet their working capital and long-term capital requirements. North Shore
Gas has access to outside capital markets to meet long-term capital requirements
and uses internal sources of funds and loans from the Company and Peoples Gas
to
meet working capital needs. Changes that could materially alter its liquidity
position include the effect of high gas prices on utility working capital and
on
hedge-related margin requirements for the upcoming heating season.
The
Company maintains lines of credit facilities to ensure sufficient liquidity
for
seasonal working capital requirements and other short-term financial needs.
As
forecasts of liquidity change throughout the year (due to high gas prices,
for
example), the Company may seek additional sources of liquidity in order to
meet
its objectives.
Due
to
the seasonal nature of gas usage, a major portion of the utilities’ cash
collections occurs between January and June. Because of timing differences
in
the receipt and disbursement of cash and the level of construction requirements,
the utility subsidiaries borrow from time to time on a short-term basis.
Short-term borrowings are repaid with cash from operations or other short-term
borrowings or are refinanced on a permanent basis with debt or equity, depending
on market conditions and capital structure considerations.
In
addition to cash generated internally by operations, as of September 30,
2006, the Company and its subsidiaries had committed credit facilities of
$650 million (Peoples Energy, $400 million; Peoples Gas,
$250 million). These facilities primarily support the Company’s and Peoples
Gas’ ability to borrow using commercial paper. As of September 30, 2006,
$89.6 million of Peoples Energy’s $400 million line and all of Peoples
Gas’ $250 million facilities were available. The Peoples Energy
$400 million credit agreement expires in June 2011, and the Peoples Gas
$250 million credit agreement expires in July 2010. The long-term credit
facilities are expected to be renewed when they expire, although the exact
amount of the renewals will be evaluated at that time and may change from the
current levels. North Shore Gas intends to meet its future short term borrowing
requirements through loans from Peoples Energy or Peoples Gas.
The
Company’s and Peoples Gas’ credit facilities generally contain debt triggers
that permit the lenders to terminate the credit commitments to the borrowing
company and declare any outstanding amounts due and payable if the borrowing
company’s consolidated debt-to-total capital ratio, excluding the impact of
accumulated other comprehensive income (AOCI), exceeds 65%. At
September 30, 2006, the Company’s total debt was 59% of total debt plus
equity (58% excluding AOCI), up from 53% a year ago due primarily to the impacts
of the settlement charge and the Will-Drill oil and gas acquisition. Anticipated
proceeds from the sale of the Company’s remaining power generation assets by
calendar year end will be used to reduce short-term borrowing. The current
debt-to-total capital ratio for Peoples Gas is 44% (44% excluding AOCI).
Management does not expect the gas reconciliation settlement to have a material
adverse affect on the Company's liquidity or its ability to fund its strategic
initiatives and capital expenditures.
In
addition to the committed credit facilities discussed above, the Company has
uncommitted lines of credit and letters of credit backup of $25.0 million,
of
which $2.0 million was used for letters of credit backup and $23.0 million
was
unused as of September 30, 2006. Peoples Gas and North Shore have the
ability to loan up to
$50 million
between the two utilities and to borrow up to $150 million and $50 million,
respectively, from Peoples Energy. As of September 30, 2006, there were no
loans from Peoples Energy to Peoples Gas or North Shore Gas. As of
September 30, 2006, there were no loans between Peoples Gas and North Shore
Gas.
The
current credit ratings for the Company, Peoples Gas and North Shore Gas are
summarized in the table below.
|
Corporate
Credit
Rating
|
Company
Senior
Unsecured
Debt
|
Peoples
Gas/
North
Shore Gas
Senior
Secured
Debt
|
Company
Commercial
Paper
|
Peoples
Gas
Commercial
Paper
|
|
|
Moody's
|
n/a
|
Baa2
|
A1
|
P-2
|
P-1
|
|
Standard
and Poor’s
|
A-
|
BBB+
|
A-
|
A-2
|
A-2
|
Moody’s
describes double-A rated debt (Aa1, Aa2 and Aa3) as high-grade and single-A
rated debt (A1, A2 and A3) as upper-medium grade. S&P describes A-rated debt
(A+, A and A-) as strong and triple-B rated debt (BBB+, BBB and BBB-) as
adequate. The lowest investment grade credit ratings for Moody’s is Baa3 and for
S&P is BBB-. Thus, both credit rating agencies give the Company, Peoples Gas
and North Shore Gas investment grade ratings.
Regarding
short-term ratings applicable to commercial paper, Moody’s describes the P-1
rating as indicating a superior repayment ability and P-2 as indicating a strong
repayment ability. S&P describes an A-2 rating as satisfactory.
Changes
in Credit Lines and Debt Securities
On
October 20, 2006, the Company entered into (1) a $25 million revolving credit
agreement with ABN AMRO Bank, N.V.; (2) a $25 million revolving credit agreement
with Bank of America, N.A.; and (3) a $25 million revolving credit agreement
with JPMorgan Chase Bank to provide for potential seasonal liquidity needs.
Each
credit agreement is effective from October 20, 2006 through the earlier of
(i)
March 31, 2007 or (ii) the consummation of the merger between a subsidiary
of
WPS Resources Corporation and Peoples Energy. Funds may be used for general
corporate purposes and commercial paper back-up.
On
June
13, 2006, the Company and various institutions entered into a $400 million
5-year syndicated revolving credit agreement. The credit agreement is effective
through June 13, 2011 and funds may be used for general corporate purposes.
The
credit agreement supports the Company's commercial paper borrowing program.
This
credit agreement replaces the previous $225 million credit facility dated
March 8, 2004 that was scheduled to expire in March 2007.
On
July 12, 2005, Peoples Gas entered into a 5-year syndicated revolving
credit agreement with eleven financial institutions that provides backup for
Peoples Gas’ seasonal commercial paper borrowing program. The maximum amount
that may be borrowed under the credit agreement is $250 million. This
replaces the previous $200 million credit facility that was scheduled to
expire in August 2005.
During
fiscal 2005 the Company refinanced $50 million of Peoples Gas debt. (See
Note 14A of the Notes to Consolidated Financial Statements for details of
fiscal 2005’s refinancing activity.)
Changes
in Equity Securities
The
Company has filed a universal shelf registration statement on Form S-3 for
the issuance from time to time of up to 1.5 million shares of common stock
pursuant to a continuous equity offering in one or more negotiated transactions
or “at-the-market” offerings. As of September 30, 2006, a total of
1,235,700 shares of common stock had been issued through the continuous
equity offering. In fiscal 2004, 377,400 shares were issued, resulting in
proceeds of $15.5 million, net of issuance costs. During fiscal 2005 and 2006
and through the date of filing the Company’s Form 10-K with the SEC, the
Company has not issued any additional shares under this registration
statement.
However, the Company did issue common stock through its LTIC Plan, Direct
Purchase and Investment Plan, DDC Plan, DSOP and its ESPP. (See Note 17 of
the Notes to Consolidated Financial Statements.)
During
fiscal 2006, Peoples Gas issued 540,000 shares of its common stock to the
Company for $53.9 million.
Financial
Uses
Capital
Spending
.
In
fiscal 2006, the Company's capital expenditures totaled $344.0 million,
including $0.6 million related to assets of discontinued operations. The Gas
Distribution segment spent $101.6 million on property, plant and equipment,
of
which $92.2 million related to Peoples Gas and $9.4 million to North Shore
Gas.
Capital expenditures at the Oil and Gas Production segment on the acquisition
of
reserves, drilling projects and the exploitation of the acquired and existing
assets totaled $236.4 million. Management currently estimates that capital
spending for fiscal 2007 will total approximately $250 million.
Dividends
.
The
Company's dividends have not changed since February 4, 2005, when the Company's
Board of Directors voted to raise the regular quarterly dividend on the
Company's common stock from 54 cents per share to 54 1/2 cents per share. The
first payment at this new level was made on April 15, 2005, to shareholders
of
record at the close of business on March 22, 2005.
Interest
Coverage
The
fixed
charges coverage ratios for the Company, Peoples Gas and North Shore Gas are
as
follows:
|
For
Fiscal Years Ended
|
||||||||||
|
September
30,
|
||||||||||
|
2006
|
2005
|
2004
|
||||||||
|
Peoples
Energy
|
0.52
|
3.23
|
3.29
|
|||||||
|
Peoples
Gas
|
(1.28
|
)
|
4.20
|
4.30
|
||||||
|
North
Shore Gas
|
3.58
|
5.87
|
5.83
|
|||||||
The
decrease in the ratio for the Company in fiscal 2006 from 2005 reflects higher
interest rates, lower pretax income, due primarily to the settlement charge
in
fiscal 2006, and an increase in gas costs refundable to customers through rate
adjustments. The decrease in the ratio in fiscal 2005 from 2004 reflects higher
interest rates in fiscal 2005.
The
decrease in the ratio for Peoples Gas in fiscal 2006 from 2005 reflects higher
interest rates, lower pretax income, due primarily to the settlement charge
in
fiscal 2006, and an increase in gas costs refundable to customers through rate
adjustments. The decrease in the ratio in fiscal 2005 from 2004 reflects higher
interest rates in fiscal 2005.
The
decrease in the ratio for North Shore Gas in fiscal 2006 from 2005 and 2004
levels reflects lower pretax income, due primarily to the settlement charge
in
fiscal 2006, and an increase in gas costs refundable to customers through rate
adjustments.
Commitments
and Contractual Obligations
Off-Balance
Sheet Arrangements.
Off-balance sheet debt at September 30, 2006 and 2005, consists of the Company's
pro rata share of nonrecourse debt of various equity investments, including
EnerVest (zero and $2.9 million) and Elwood ($165.1 million and $174.3 million).
The Company believes this off-balance sheet financing will not have a material
effect on the Company's future financial condition. The Company also has
commercial obligations of $34.6 million in guarantees, $6.7 million in letters
of credit, $1.6 million in surety bonds and $35.2 million in operating leases
at
September 30, 2006. (See Notes 5 and 10 of the Notes to Consolidated Financial
Statements for further descriptions and details of the Company’s off-balance
sheet arrangements.)
Contractual
Obligations.
The
Company has certain contractual obligations directly related to the Company’s
operations and unconsolidated equity investees. The majority of these are
guarantees of debt service and performance (related to unconsolidated equity
investees), as well as substantial commitments for gas supply, transportation
and storage. (See Note 10 of the Notes to the Consolidated Financial
Statements.)
The
following table summarizes the Company’s long-term minimum contractual
obligations.
|
Payments
Due by Period
|
||||||||||||||||
|
|
|
|
|
|
|
Less
than
|
|
|
1
to 3
|
|
|
4
to 5
|
|
|
More
than
|
|
|
(In
Millions)
|
|
|
Total
|
|
|
1
Year
|
|
|
Years
|
|
|
Years
|
|
|
5
Years
|
|
|
Total
debt (See Note 14)
|
$
|
1,204.4
|
$
|
309.7
|
$
|
-
|
$
|
373.5
|
$
|
521.2
|
||||||
|
Estimated
interest payments on debt (1)
|
631.5
|
46.7
|
93.4
|
79.3
|
412.1
|
|||||||||||
|
Operating
leases (See Note 10C)
|
35.2
|
3.9
|
8.2
|
8.6
|
14.5
|
|||||||||||
|
Purchase
obligations (2)
|
1,108.8
|
471.9
|
407.1
|
96.9
|
132.9
|
|||||||||||
|
Minimum
pension funding (3) (See Note 11)
|
92.8
|
-
|
26.1
|
33.3
|
33.4
|
|||||||||||
|
Total
contractual cash obligations
|
$
|
3,072.7
|
$
|
832.2
|
$
|
534.8
|
$
|
591.6
|
$
|
1,114.1
|
||||||
| (1) |
Includes
interest on fixed and adjustable rate debt. The adjustable rate interest
is calculated based on the indexed rate in effect at September 30,
2006.
|
| (2) |
Includes
gas purchases, storage, transportation, information technology-related
and
miscellaneous long-term and short-term capital
purchase
commitments.
|
| (3) |
Minimum
pension funding is an estimate of the contributions that would be
required
pursuant to the Employee Retirement Income Security
Act
to fund benefits earned as of October 1, 2006. Additional contributions
may be made to fund benefits accruing after October 1, 2006, or
on
a discretionary basis.
|
Merger.
In
the
event that the pending merger with WPS Resources is successfully completed,
the
Company will recognize expenses estimated to total approximately $14 million
in
addition to expenses recognized in fiscal 2006. These payments are for
transaction fees and other costs, as well as additional compensation expense
resulting from the change in control provisions in the Company’s long-term
incentive plans. (See Note 17 of the Notes to Consolidated Financial
Statements.) Note 1 of the Notes to Consolidated Financial Statements discusses
the termination fees and related expenses in the event the merger is not
completed.
Environmental
Matters
.
Peoples
Gas and North Shore Gas are conducting environmental investigations and remedial
work at certain sites that were the locations of former manufactured gas
operations. (See Note 7A of the Notes to Consolidated Financial Statements.)
North Shore Gas received a demand from a responsible party under CERCLA for
environmental costs associated with a site in Denver, Colorado. (See Note 7B
of
the Notes to Consolidated Financial Statements.)
Gas
Charge Reconciliation Proceedings and Related Matters.
For each
utility subsidiary, the Commission conducts annual proceedings regarding the
reconciliation of revenues from the Gas Charge and related gas costs. In these
proceedings, the accuracy of the reconciliation of revenues and costs is
reviewed and the prudence of gas costs recovered through the Gas Charge is
examined by interested parties. On March 21, 2005, the Illinois Attorney General
(AG) and Chicago filed lawsuits against the Company and several of its
subsidiaries alleging violations against its customers under certain state
and
city consumer fraud laws, respectively. On March 28, 2006, the Commission issued
an order approving a settlement that resolved Peoples Gas' and North Shore
Gas'
fiscal 2001 - 2004 gas charge cases and the AG and Chicago lawsuits. (See Note
8A of the Notes to Consolidated Financial Statements.)
In
February 2004, a purported class action was filed against the Company and
Peoples Gas by a Peoples Gas customer alleging, among other things, violation
of
the Illinois Consumer Fraud and Deceptive Business Practices Act related to
maters at issue in Peoples Gas' gas charge reconciliation proceedings. (See
Note
8B
of the
Notes to Consolidated Financial Statements.)
Indenture
Restrictions
North
Shore Gas’ 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, 2006, such restrictions
amounted to $6.9 million of North Shore Gas’ total retained earnings of
$
76.3 million.
Peoples
Energy Resources owns a 50% equity interest in Elwood. Elwood's trust indenture
and other agreements related to its project financing prohibit Elwood from
making distributions unless Elwood has maintained certain minimum historic
and
projected debt service coverage ratios. At July 5, 2006, a minimum debt service
coverage ratio of 1.2 to 1.0 was required to make a cash distribution and
Elwood's actual debt service coverage ratio was approximately 1.4 to
1.0.
PEOPLES
GAS AND NORTH SHORE GAS DISCUSSIONS
The
financial results of Peoples Gas (including its hub operations) and North Shore
Gas are reported primarily within the Gas Distribution segment. Operating income
(GAAP) and ongoing operating income (non-GAAP) by business segment for Peoples
Gas and North Shore Gas is presented below.
|
|
|
Peoples
Gas
|
|
North
Shore Gas
|
|||||||||||||||
|
Corporate
|
|
|
Corporate
|
|
|||||||||||||||
|
Gas
|
and
|
|
|
Gas
|
and
|
|
|||||||||||||
|
(In
Thousands)
|
Distribution
|
|
Other
|
Total
|
Distribution
|
Other
|
Total
|
||||||||||||
|
For
the Fiscal Year Ended
|
|||||||||||||||||||
|
September
30, 2006 (GAAP)
|
$
|
(27,472
|
)
|
$
|
(12,662
|
)
|
$
|
(40,134
|
)
|
$
|
15,022
|
$
|
(1,694
|
)
|
$
|
13,328
|
|||
|
September
30, 2006 (non-GAAP)
(1)
|
75,558
|
(12,662
|
)
|
62,896
|
19,322
|
(1,694
|
)
|
17,628
|
|||||||||||
|
September
30, 2005 (GAAP)
|
113,669
|
(18,110
|
)
|
95,559
|
22,909
|
(1,864
|
)
|
21,045
|
|||||||||||
|
September
30, 2005 (non-GAAP)
(1)
|
113,669
|
(9,320
|
)
|
104,349
|
22,909
|
(1,242
|
)
|
21,667
|
|||||||||||
|
September
30, 2004 (GAAP)
|
118,144
|
(30,336
|
)
|
87,808
|
24,825
|
(3,493
|
)
|
21,332
|
|||||||||||
|
September
30, 2004 (non-GAAP)
(1)
|
118,144
|
(20,650
|
)
|
97,494
|
24,825
|
(2,611
|
)
|
22,214
|
|||||||||||
|
(1)
|
Fiscal
2006 ongoing operating income (non-GAAP) is defined as GAAP operating
(loss) adjusted to exclude the effects of a charge of $103.0 million
and
$4.3 million at Peoples Gas and North Shore Gas, respectively, associated
with the settlement of gas charge proceedings. Fiscal 2005 ongoing
operating income (non-GAAP) is defined as GAAP operating income adjusted
to exclude the effects of pension expense related restructuring costs
of
$8.8 million and $0.6 million at Peoples Gas and North Shore Gas,
respectively. Fiscal 2004 ongoing operating income (non-GAAP) is
defined
as GAAP operating income adjusted to exclude the effects of pension
expense related restructuring costs of $9.7 million and $0.9 million
at
Peoples Gas and North Shore Gas, respectively. See Item 7 - MD&A -
Executive Summary for a discussion of management's use of non-GAAP
financial measures and a reconciliation of GAAP and non-GAAP
earnings.
|
The
following discussions supplement Peoples Gas' and North Shore Gas' information
included in Liquidity and Capital Resources and in the Company's Gas
Distribution segment discussion within this MD&A.
Peoples
Gas Discussion
GAAP
net
loss for Peoples Gas for fiscal 2006 was $35.4 million compared to net income
of
$49.3 million in fiscal 2005. Excluding the charge related to the settlement
of
gas charge proceedings ($62.1 million, after tax), ongoing net income (non-GAAP)
was $26.6 million. Excluding pension-related charges ($5.3 million, after tax)
resulting from the fiscal year 2004 organizational restructuring, ongoing net
income (non-GAAP) for fiscal 2005 was $54.6 million.
Revenues
for fiscal 2006 increased $197.6 million compared with fiscal 2005. These
results were due to the impact on revenues of changes in gas prices (an increase
of $270 million) that are recovered on a dollar-for-dollar basis. These results
also reflected the impact on revenues of decreased deliveries due to weather
($16 million) that was 2% warmer compared with the prior year,
lower
weather-normalized demand ($88 million) and the impact of the change in the
regulatory treatment of Hub revenues ($10.7 million) due to the gas charge
settlement agreement. The $135.7 million decrease in operating income for fiscal
2006 was primarily due to the $103.0 million charge related to the amended
settlement of the gas charge proceedings, higher operation and maintenance
expense
($21.0 million), the change in treatment of Hub revenues ($10.7 million), lower
deliveries resulting from warmer weather ($2 million) and lower normalized
deliveries ($8 million). The increase in operation and maintenance expense
was
due to higher labor, pension, group insurance, bad debt, outside services and
rate case expenses. These increases were partially offset by the impact of
the
fiscal 2005 restructuring-related pension charge of $8.8 million.
Interest
expense for Peoples Gas for fiscal 2006 increased $3.2 million due to higher
interest rates and an increase in gas costs refundable to customers through
rate
adjustments.
Fiscal
2005 revenues for Peoples Gas increased $145.3 million from the previous period.
The main reason for the increase was the impact on revenues of higher gas prices
($179 million). Partially offsetting these effects were lower revenues resulting
from a decrease in deliveries due to weather ($27 million) that was 4% warmer
than the previous period and a decrease in normalized deliveries. GAAP operating
income increased $7.8 million from fiscal 2004. Operating income was favorably
impacted by decreased labor costs related to the organizational restructuring
($8.6 million) and a decrease in depreciation expense ($5.7 million) primarily
due to the Commission Depreciation Order. Negative impacts on 2005 results
include lower deliveries resulting from warmer weather ($4.5
million).
Fiscal
2005 interest expense for Peoples Gas increased $2.7 million over fiscal 2004
primarily due to higher interest rates.
Total
assets at September 30, 2006 increased $135.7 million compared to September
30, 2005 due primarily to an increase in current regulatory assets related
to
MTM accounting for the utility gas costs hedging program, an increase in
noncurrent regulatory assets and capital investments related to the recognition
of asset retirement obligations required under FIN 47, an increase in cash
and
cash equivalents, an increase in gas in storage (due to higher prices and
volume), and an increase in prepaid pension costs (due to the elimination of
the
additional minimum pension liability as a result of increased plan funding
and
an increase in the discount rate). These increases were partially offset by
a
decrease in intercompany receivables due to of a decrease in derivative assets
contracted by Peoples Energy on behalf of Peoples Gas that are marked-to-market.
The decrease in derivative assets reflects price declines during fiscal 2006
relative to utility supply contracts (long positions). The increase in current
liabilities was driven by an increase in intercompany payables (made up largely
of unrealized losses on derivatives contracted by Peoples Energy on behalf
of
Peoples Gas that are marked-to-market) and increases in gas costs refundable
through rate adjustments. These increases were partially offset by a decrease
in
current regulatory liabilities. The decrease in current regulatory liabilities
largely corresponds with above decrease in derivative assets that are
marked-to-market. Settlement of these assets is included as an adjustment to
gas
costs included in customer bills. Deferred credits and other liabilities
increased primarily due to the recognition of asset retirement obligations
required under FIN 47, which largely correspond with the above increase in
noncurrent regulatory assets. Peoples Gas’ capitalization increased with a $53.9
million equity contribution by the Company in Peoples Gas and a decrease in
the
accumulated other comprehensive loss. These increases were partially offset
by
the reduction in retained earnings due primarily to dividend payments of $15.4
million and a $35.4 million fiscal 2006 net loss, which reflects the $62.1
million after tax charge related to the gas charge settlement.
North
Shore Gas Discussion
GAAP
net
income for North Shore Gas for fiscal 2006 was $6.7 million compared to $11.4
million in fiscal 2005. Excluding the net charge related to the settlement
of
gas charge proceedings ($2.6 million, after tax), ongoing net income (loss)
(non-GAAP) was $9.3 million. Excluding pension-related charges ($0.4 million,
after tax) resulting from the fiscal year 2004 organizational restructuring,
ongoing net income (non-GAAP) for fiscal 2005 was $11.8 million.
Revenues
for North Shore Gas for fiscal 2006 increased $39.1 million compared to fiscal
2005, mainly due to the impact on revenues of higher gas prices ($48 million),
partially offset by the impact of decreased deliveries due to weather ($4
million) that was 2% warmer compared with the same year ago period and lower
weather-normalized demand ($11 million). Operating income decreased $7.7 million
for fiscal 2006. Results were unfavorably
impacted
by the net charge ($4.3 million) related to the amended settlement of the gas
charge proceedings, lower deliveries resulting from warmer weather ($0.5
million), lower normalized deliveries ($0.5 million), and higher operation
and
maintenance expenses
($3.7
million) which included $0.7 million of rate case costs, partially offset by
the
impact of the fiscal 2005 restructuring-related pension charge of $0.6
million.
Interest
expense for North Shore Gas for fiscal 2006 increased $0.4 million primarily
due
to an increase in gas costs refundable to customers through rate
adjustments.
Fiscal
2005 revenues for North Shore Gas increased $37.8 million over the prior period
mainly due to the impact on revenues of higher gas prices ($42 million).
Partially offsetting these effects were lower revenues resulting from a decrease
in deliveries due to weather ($4 million) that was 4% warmer compared to the
prior period. GAAP operating income for fiscal 2005 was flat compared to fiscal
2004. The fiscal 2005 results were favorably impacted by a decrease in
depreciation expense ($1.4 million) primarily due to the Commission Depreciation
Order and negatively impacted by an increase in pension expense ($1.0 million).
Total
assets at September 30, 2006 increased $28.8 million compared to September
30, 2005 due to an increase in current regulatory assets related primarily
to
MTM accounting for the utility gas costs hedging program, an increase in
noncurrent regulatory assets related to the recognition of asset retirement
obligations required under FIN 47, and an increase in gas in storage. These
increases were partially offset by a decrease in intercompany receivables made
up largely of a decrease in derivative assets contracted by Peoples Energy
on
behalf of North Shore Gas that are marked-to-market. The decrease in derivative
assets reflects price declines during fiscal 2006 relative to utility supply
contracts (long positions). The increase in current liabilities was driven
by an
increase in intercompany payables (made up largely of unrealized losses on
derivatives contracted by Peoples Energy on behalf of North Shore Gas that
are
marked-to-market) and an increase in gas costs refundable through rate
adjustments. This decrease was partially offset by a decrease in regulatory
liabilities. The decrease in regulatory liabilities largely corresponds with
the
above decrease in derivative assets that are marked-to-market. Settlement of
these assets is included as an adjustment to gas costs included in customer
bills. The Company's capitalization decreased with the reduction in retained
earnings due primarily to dividend payments of $11.0 million, partially offset
by $6.7 million of net income, which was negatively affected by the $2.6 million
after tax charge related to the gas charge settlement.
|
The
Peoples Gas Light and Coke Company
|
||||||||||||||||
|
Gas
Distribution Statistics
|
||||||||||||||||
|
For
Fiscal Years Ended
|
Increase/(Decrease
)
|
|||||||||||||||
|
Margin
Data
|
September
30,
|
Fiscal
2006 vs.
|
Fiscal
2005 vs.
|
|||||||||||||
|
(In
Thousands)
|
2006
|
2005
|
2004
|
Fiscal
2005
|
Fiscal
2004
|
|||||||||||
|
Gas
Distribution revenues:
|
||||||||||||||||
|
Sales
|
||||||||||||||||
|
Residential
|
$
|
1,249,993
|
$
|
1,086,435
|
$
|
974,143
|
$
|
163,558
|
$
|
112,292
|
||||||
|
Commercial
|
203,005
|
175,904
|
155,934
|
27,101
|
19,970
|
|||||||||||
|
Industrial
|
32,936
|
28,720
|
24,112
|
4,216
|
4,608
|
|||||||||||
|
Total
sales
|
1,485,934
|
1,291,059
|
1,154,189
|
194,875
|
136,870
|
|||||||||||
|
Transportation
|
||||||||||||||||
|
Residential
|
33,260
|
30,699
|
30,645
|
2,561
|
54
|
|||||||||||
|
Commercial
|
43,734
|
42,329
|
41,131
|
1,405
|
1,198
|
|||||||||||
|
Industrial
|
15,995
|
16,994
|
16,656
|
(999
|
)
|
338
|
||||||||||
|
Contract
pooling
|
26,643
|
18,381
|
14,017
|
8,262
|
4,364
|
|||||||||||
|
Total
transportation
|
119,632
|
108,403
|
102,449
|
11,229
|
5,954
|
|||||||||||
|
Total
Hub revenues
|
-
|
10,662
|
7,620
|
(10,662
|
)
|
3,042
|
||||||||||
|
Other
Gas Distribution revenues
|
16,725
|
14,579
|
15,117
|
2,146
|
(538
|
)
|
||||||||||
|
Total
Gas Distribution revenues
|
1,622,291
|
1,424,703
|
1,279,375
|
197,588
|
145,328
|
|||||||||||
|
Less:
Gas costs
|
1,052,333
|
853,453
|
723,771
|
198,880
|
129,682
|
|||||||||||
|
Gross
margin
|
569,958
|
571,250
|
555,604
|
(1,292
|
)
|
15,646
|
||||||||||
|
Less:
Revenue taxes and surcharges
|
149,786
|
136,115
|
125,500
|
13,671
|
10,615
|
|||||||||||
|
Environmental costs recovered
|
31,588
|
28,574
|
16,206
|
3,014
|
12,368
|
|||||||||||
|
Net
margin (1)
|
$
|
388,584
|
$
|
406,561
|
$
|
413,898
|
$
|
(17,977
|
)
|
$
|
(7,337
|
)
|
||||
|
Gas
Distribution deliveries (MDth):
|
||||||||||||||||
|
Gas
sales
|
||||||||||||||||
|
Residential
|
85,381
|
91,217
|
97,035
|
(5,836
|
)
|
(5,818
|
)
|
|||||||||
|
Commercial
|
15,021
|
16,022
|
16,856
|
(1,001
|
)
|
(834
|
)
|
|||||||||
|
Industrial
|
2,571
|
2,801
|
2,790
|
(230
|
)
|
11
|
||||||||||
|
Total
gas sales
|
102,973
|
110,040
|
116,681
|
(7,067
|
)
|
(6,641
|
)
|
|||||||||
|
Transportation
|
||||||||||||||||
|
Residential
|
18,637
|
19,134
|
20,210
|
(497
|
)
|
(1,076
|
)
|
|||||||||
|
Commercial
|
35,645
|
35,024
|
37,287
|
621
|
(2,263
|
)
|
||||||||||
|
Industrial
|
16,101
|
17,662
|
18,139
|
(1,561
|
)
|
(477
|
)
|
|||||||||
|
Total
transportation
|
70,383
|
71,820
|
75,636
|
(1,437
|
)
|
(3,816
|
)
|
|||||||||
|
Total
Gas Distribution deliveries
|
173,356
|
181,860
|
192,317
|
(8,504
|
)
|
(10,457
|
)
|
|||||||||
|
Total
Hub volumes
|
-
|
22,784
|
19,381
|
(22,784
|
)
|
3,403
|
||||||||||
|
Gross
margin per Dth delivered (3)
|
$
|
3.29
|
$
|
3.08
|
$
|
2.85
|
$
|
0.21
|
$
|
0.23
|
||||||
|
Net
margin per Dth delivered (3)
|
$
|
2.24
|
$
|
2.18
|
$
|
2.11
|
$
|
0.06
|
$
|
0.07
|
||||||
|
Average
cost per Dth of gas sold
|
$
|
10.22
|
$
|
7.76
|
$
|
6.20
|
$
|
2.46
|
$
|
1.56
|
||||||
|
Actual
heating degree days
|
5,775
|
5,864
|
6,091
|
(89
|
)
|
(227
|
)
|
|||||||||
|
Normal
heating degree days (2)
|
6,408
|
6,427
|
6,427
|
|||||||||||||
|
Actual
heating degree days as a percent
|
||||||||||||||||
|
of
normal (actual/normal)
|
90
|
91
|
95
|
|||||||||||||
| (1) |
As
used above, net margin is not a financial measure computed under
GAAP but
represents an operating performance measure. Gross margin is the
GAAP
measure most closely related to net margin. Management believes net
margin
to be useful in understanding Peoples Gas' operations because the
utility
subsidiaries are allowed, under their tariffs, to recover gas costs,
revenue taxes and environmental costs from their customers on a
dollar-for-dollar basis.
|
| (2) |
Normal
heating degree days for fiscal 2004 and 2005 are based on a 30-year
average of monthly temperatures at Chicago's O'Hare Airport for the
years
1970-1999. Normal heating degree days for fiscal 2006 are based on
a
30-year average of monthly temperatures at Chicago's O'Hare Airport
for
the years 1975-2004.
|
| (3) |
Margin
per Dth is based upon gas distribution and transportation activity
and
excludes the impact of hub revenues and hub
volumes.
|
|
North
Shore Gas Company
|
||||||||||||||||
|
Gas
Distribution Statistics
|
||||||||||||||||
|
For
Fiscal Years Ended
|
Increase/(Decrease
)
|
|||||||||||||||
|
Margin
Data
|
September
30,
|
Fiscal
2006 vs.
|
Fiscal
2005 vs.
|
|||||||||||||
|
(In
Thousands)
|
2006
|
2005
|
2004
|
Fiscal
2005
|
Fiscal
2004
|
|||||||||||
|
Gas
Distribution revenues:
|
||||||||||||||||
|
Sales
|
||||||||||||||||
|
Residential
|
$
|
235,760
|
$
|
204,281
|
$
|
174,356
|
$
|
31,479
|
$
|
29,925
|
||||||
|
Commercial
|
39,191
|
33,808
|
28,822
|
5,383
|
4,986
|
|||||||||||
|
Industrial
|
8,639
|
7,648
|
6,212
|
991
|
1,436
|
|||||||||||
|
Total
sales
|
283,590
|
245,737
|
209,390
|
37,853
|
36,347
|
|||||||||||
|
Transportation
|
||||||||||||||||
|
Residential
|
1,896
|
1,661
|
1,709
|
235
|
(48
|
)
|
||||||||||
|
Commercial
|
6,810
|
6,390
|
6,154
|
420
|
236
|
|||||||||||
|
Industrial
|
2,833
|
2,886
|
2,781
|
(53
|
)
|
105
|
||||||||||
|
Contract
pooling
|
2,805
|
2,313
|
1,355
|
492
|
958
|
|||||||||||
|
Total
transportation
|
14,344
|
13,250
|
11,999
|
1,094
|
1,251
|
|||||||||||
|
Other
Gas Distribution revenues
|
1,655
|
1,474
|
1,320
|
181
|
154
|
|||||||||||
|
Total
Gas Distribution revenues
|
299,589
|
260,461
|
222,709
|
39,128
|
37,752
|
|||||||||||
|
Less:
Gas costs
|
220,300
|
180,923
|
144,747
|
39,377
|
36,176
|
|||||||||||
|
Gross
margin
|
79,289
|
79,538
|
77,962
|
(249
|
)
|
1,576
|
||||||||||
|
Less:
Revenue taxes and surcharges
|
14,487
|
14,210
|
13,341
|
277
|
869
|
|||||||||||
|
Environmental costs recovered
|
2,065
|
1,863
|
1,178
|
202
|
685
|
|||||||||||
|
Net
margin (1)
|
$
|
62,737
|
$
|
63,465
|
$
|
63,443
|
$
|
(728
|
)
|
$
|
22
|
|||||
|
Gas
Distribution deliveries (MDth):
|
||||||||||||||||
|
Gas
sales
|
||||||||||||||||
|
Residential
|
18,275
|
19,212
|
19,904
|
(937
|
)
|
(692
|
)
|
|||||||||
|
Commercial
|
3,188
|
3,327
|
3,447
|
(139
|
)
|
(120
|
)
|
|||||||||
|
Industrial
|
722
|
806
|
807
|
(84
|
)
|
(1
|
)
|
|||||||||
|
Total
gas sales
|
22,185
|
23,345
|
24,158
|
(1,160
|
)
|
(813
|
)
|
|||||||||
|
Transportation
|
||||||||||||||||
|
Residential
|
867
|
793
|
851
|
74
|
(58
|
)
|
||||||||||
|
Commercial
|
6,829
|
6,215
|
6,359
|
614
|
(144
|
)
|
||||||||||
|
Industrial
|
5,045
|
5,469
|
5,617
|
(424
|
)
|
(148
|
)
|
|||||||||
|
Total
transportation
|
12,741
|
12,477
|
12,827
|
264
|
(350
|
)
|
||||||||||
|
Total
Gas Distribution deliveries
|
34,926
|
35,822
|
36,985
|
(896
|
)
|
(1,163
|
)
|
|||||||||
|
Gross
margin per Dth delivered
|
$
|
2.27
|
$
|
2.22
|
$
|
2.11
|
$
|
0.05
|
$
|
0.11
|
||||||
|
Net
margin per Dth delivered
|
$
|
1.80
|
$
|
1.77
|
$
|
1.72
|
$
|
0.03
|
$
|
0.05
|
||||||
|
Average
cost per Dth of gas sold
|
$
|
9.93
|
$
|
7.75
|
$
|
5.99
|
$
|
2.18
|
$
|
1.76
|
||||||
|
Actual
heating degree days
|
5,775
|
5,864
|
6,091
|
(89
|
)
|
(227
|
)
|
|||||||||
|
Normal
heating degree days (2)
|
6,408
|
6,427
|
6,427
|
|||||||||||||
|
Actual
heating degree days as a percent
|
||||||||||||||||
|
of
normal (actual/normal)
|
90
|
91
|
95
|
|||||||||||||
| (1) |
As
used above, net margin is not a financial measure computed under
GAAP but
represents an operating performance measure. Gross margin is the
GAAP
measure most closely related to net margin. Management believes net
margin
to be useful in understanding North Shore Gas' operations because
the
utility subsidiaries are allowed, under their tariffs, to recover
gas
costs, revenue taxes and environmental costs from their customers
on a
dollar-for-dollar basis.
|
| (2) |
Normal
heating degree days for fiscal 2004 and 2005 are based on a 30-year
average of monthly temperatures at Chicago's O'Hare Airport for the
years
1970-1999. Normal heating degree days for fiscal 2006 are based on
a
30-year average of monthly temperatures at Chicago's O'Hare Airport
for
the years 1975-2004.
|
The
Company is exposed to various business risks associated with commodity prices,
weather, interest rates, and credit. These financial exposures are monitored
and
managed by the Company as an integral part of its overall risk management
program. The Company’s risk management program includes, among other things, the
use of financial derivatives.
Quantitative
and qualitative disclosures about market risk are reported under Item 1A—Risk
Factors and below under Risk Management Activities.
RISK
MANAGEMENT ACTIVITIES
Commodity
Price Risk
The
Company’s earnings may vary due to changes in commodity prices (market risk)
that affect its subsidiaries’ operations and investments. To manage this market
risk, the Company uses forward contracts and financial instruments, including
commodity futures contracts, swaps and options. It is the policy of the Company
to use these instruments solely for the purpose of managing risk and not for
any
speculative purpose.
Derivative
Summary.
The
following table summarizes the changes in valuation of all outstanding
derivative contracts during fiscal 2006 and 2005. All amounts are based on
fair
values at the end of the period and do not necessarily indicate that a gain
or
loss on the derivative will be recognized in income in future periods.
Generally, hedges are held to maturity, which coincides with recognition of
the
transaction being hedged (e.g., anticipated sales or cost of purchases in
income), thereby achieving the realization of prices contemplated by the
underlying risk management strategies.
|
Derivative
Type
|
|||||||||||||||||||
|
Cash
Flow
|
Fair
Value
|
||||||||||||||||||
|
Hedges
|
Hedges
|
Mark-to-Market
|
|||||||||||||||||
|
(In
Thousands)
|
2006
|
2005
|
2006
|
2005
|
2006
|
2005
|
|||||||||||||
|
Value
of contracts outstanding at October 1
|
$
|
(202,904
|
)
|
$
|
(89,306
|
)
|
$
|
(21,457
|
)
|
$
|
(139
|
)
|
$
|
204,276
|
$
|
27,678
|
|||
|
Loss
on contracts discontinued as cash flow hedges
|
-
|
2,956
|
-
|
-
|
-
|
(2,956
|
)
|
||||||||||||
|
Less:
Gain (loss) on contracts realized or otherwise
|
|||||||||||||||||||
|
settled
during the year
|
(87,020
|
)
|
(64,841
|
)
|
6,192
|
(2
|
)
|
(19,603
|
)
|
17,159
|
|||||||||
|
Plus:
Unrealized gain (loss) on new contracts entered
|
|||||||||||||||||||
|
into
during the period and outstanding at year-end
|
6,144
|
(20,797
|
)
|
10,449
|
(20,790
|
)
|
(147,720
|
)
|
199,012
|
||||||||||
|
Plus:
Other unrealized gain (loss), primarily changes
|
|||||||||||||||||||
|
in
market prices on contracts outstanding at the
|
|||||||||||||||||||
|
beginning
of the year
|
85,958
|
(160,598
|
)
|
26,101
|
(530
|
)
|
(227,719
|
)
|
(2,299
|
)
|
|||||||||
|
Value
of contracts outstanding at September 30
|
$
|
(23,782
|
)
|
$
|
(202,904
|
)
|
$
|
8,901
|
$
|
(21,457
|
)
|
$
|
(151,560
|
)
|
$
|
204,276
|
|||
The change in the value of derivative contracts for the fiscal year ended September 30, 2006 was due primarily to the dramatic change in the forward price curve of natural gas over this same period. The increase in the value of contracts designated as cash flow hedges was driven primarily by the effect of lower forward prices and a reduction of hedged volumes in the Oil and Gas Production segment’s derivatives portfolio. The increase in the value of contracts designated as fair value hedges was driven primarily by an increase in value in the Energy Marketing segment’s storage optimization portfolio, partially offset by the decrease in value of the Company’s floating rate interest rate swap reflecting the rise in short term interest rates. The primary cause of the decrease in the value of contracts designated as MTM is attributable to the impact of the change in the forward price curve on the derivative instruments of Peoples Gas and North Shore Gas used to manage each utility’s cost of gas supply. This was partially offset by the positive impact of changes in prices on MTM portfolios at the Energy Marketing segment. For the fiscal year ended September 30, 2006, unrealized losses on contracts attributed to Peoples Gas and North Shore Gas were $322 million and $61 million, respectively. SFAS No. 71 allows for these MTM derivative gains and losses to be recorded as regulatory assets or regulatory liabilities. Realized gains and losses
are
recorded as an adjustment to the cost of gas supply in the period that the
underlying gas purchase transaction takes place. The costs and benefits of
this
activity are passed through to customers under the tariffs of Peoples Gas and
North Shore Gas.
The
following table is a summary of the fair market value of commodity derivatives
by type at September 30, 2006. Valuations are based on the NYMEX closing prices
for the respective NYMEX Henry Hub futures contracts and on the closing prices
published in various commodity pricing publications for the geographical
differential between a specific location price and the NYMEX Henry Hub futures
contract closing price where applicable.
|
Commodity
Derivatives
|
||||||||
|
(Fair
Value amounts in thousands)
|
||||||||
|
Futures/Forwards
|
Maturity
|
Volumes
(MMbtu's)
|
Price
Per
MMbtu
|
Fair
Value
|
||||
|
Long
Natural Gas
|
Less
than 1 Year
|
13,538,565
|
3.53
- 11.98
|
$
(13,787)
|
||||
|
Short
Natural Gas
|
Less
than 1 Year
|
11,443,642
|
3.50
- 12.34
|
18,922
|
||||
|
Long
Natural Gas
|
1
-
3 Years
|
2,599,737
|
7.27
- 11.00
|
(127)
|
||||
|
Short
Natural Gas
|
1
-
3 Years
|
860,000
|
8.63
- 9.99
|
(111)
|
||||
|
28,441,944
|
$
4,897
|
|||||||
|
Options
|
Maturity
|
Volumes
(MMbtu's)
|
Price
Per
MMbtu
|
Fair
Value
|
||||
|
Long
Natural Gas
|
Less
than 1 Year
|
9,394,500
|
5.00
- 15.00
|
$
4,702
|
||||
|
Short
Natural Gas
|
Less
than 1 Year
|
10,434,500
|
|
5.50
- 15.00
|
(17,440)
|
|||
|
Long
Natural Gas
|
1
-
3 Years
|
2,852,000
|
7.00
- 9.00
|
3,465
|
||||
|
Short
Natural Gas
|
1
-
3 Years
|
2,852,000
|
|
5.50
- 12.00
|
(2,011)
|
|||
|
25,533,000
|
$
(11,284)
|
|||||||
|
Swaps
(NG)
|
Maturity
|
Volumes
(MMbtu's)
|
Price
Per
MMbtu
|
Fair
Value
|
||||
|
Long
Natural Gas
|
Less
than 1 Year
|
77,515,502
|
2.83
- 13.04
|
$
(151,621)
|
||||
|
Short
Natural Gas
|
Less
than 1 Year
|
27,007,500
|
0.96
- 12.54
|
4,844
|
||||
|
Long
Natural Gas
|
1
-
3 Years
|
15,896,721
|
6.57
- 10.82
|
(11,908)
|
||||
|
Short
Natural Gas
|
1
-
3 Years
|
10,955,000
|
3.84
- 11.83
|
3,373
|
||||
|
Long
Natural Gas
|
4
-
5 Years
|
1,920,000
|
6.60
- 7.10
|
91
|
||||
|
Short
Natural Gas
|
4
-
5 Years
|
1,920,000
|
8.99
- 9.50
|
1,498
|
||||
|
Long
Natural Gas
|
More
than 5 Years
|
900,000
|
6.86
|
49
|
||||
|
Short
Natural Gas
|
More
than 5 Years
|
2,820,000
|
8.31
- 9.15
|
1,180
|
||||
|
138,934,723
|
$
(152,494)
|
|||||||
|
Total
(NG)
|
Maturity
|
Volumes
(MMbtu's)
|
Price
Per
MMbtu
|
Fair
Value
|
||||
|
Long
Natural Gas
|
Less
than 1 Year
|
100,448,567
|
2.83
- 15.00
|
$
(160,706)
|
||||
|
Short
Natural Gas
|
Less
than 1 Year
|
48,885,642
|
0.96
- 15.00
|
6,326
|
||||
|
Long
Natural Gas
|
1
-
3 Years
|
21,348,458
|
6.57
- 11.00
|
(8,570)
|
||||
|
Short
Natural Gas
|
1
-
3 Years
|
14,667,000
|
3.84
- 12.00
|
1,251
|
||||
|
Long
Natural Gas
|
4
-
5 Years
|
1,920,000
|
6.60
- 7.10
|
91
|
||||
|
Short
Natural Gas
|
4
-
5 Years
|
1,920,000
|
8.99
- 9.50
|
1,498
|
||||
|
Long
Natural Gas
|
More
than 5 Years
|
900,000
|
6.86
|
49
|
||||
|
Short
Natural Gas
|
More
than 5 Years
|
2,820,000
|
8.31
- 9.15
|
1,180
|
||||
|
192,909,667
|
$
(158,881)
|
|||||||
|
Swaps
(OIL)
|
Maturity
|
Volumes
(Bbl's)
|
Price
Per
Bbl
|
Fair
Value
|
||||
|
Short
WTI Crude Oil
|
Less
than 1 Year
|
182,500
|
37.50
|
$
(5,227)
|
||||
|
Short
WTI Crude Oil
|
1
-
3 Years
|
73,200
|
56.60
|
(837)
|
||||
|
255,700
|
$
(6,064)
|
|||||||
|
Futures/Forwards
(Megawatt-hours)
|
Maturity
|
Amounts
(Mwh's)
|
Price
Per
Mwh
|
Fair
Value
|
||||
|
Long
Megawatt-hours
|
Less
than 1 Year
|
633,938
|
(0.20)
- 0.36
|
$
52
|
||||
|
633,938
|
$
52
|
|||||||
|
Grand
Total - Fair Value of Commodity Derivatives
|
$
(164,893)
|
|||||||
|
Fair
Value of Interest Rate Swap
|
(1,548)
|
|||||||
|
Grand
Total - Fair Value of all Derivatives
|
$
(166,441)
|
|||||||
Cash
Flow Hedges.
The
Company has positions in oil and gas reserves, natural gas, and transportation
as part of its Oil and Gas Production and Energy Marketing businesses, and
related to its company use gas in the Gas Distribution segment. The Company
uses
derivative financial instruments to protect against loss of value of future
anticipated cash transactions (sales and purchases) caused by changes in the
marketplace. These instruments are designated cash flow hedges, which allow
for
the effective portion of unrealized changes in value during the life of the
hedge to be recorded in other comprehensive income. Realized gains and losses
from cash flow hedges are recorded in the statement of operations in the same
month the related physical sales and purchases and interest expense are
recorded. Cash flow hedge accounting is discontinued when it is no longer
probable that the original forecasted transactions will occur. The carrying
value of contracts which no longer qualify for hedge accounting are
prospectively marked-to-market, with the change in value recorded in the
statement of operations. If the original forecasted transactions are probable
of
not occurring, any amounts previously recorded in other comprehensive income
are
immediately recorded in the statement of operations. Hedge ineffectiveness
can
result from differences in critical terms (such as location) between the hedging
instrument and the hedged transaction and result in the immediate recognition
of
gains or losses.
Fair
Value Hedges.
The
Company uses financial and physical hedges to protect the value of a portion
of
Energy Marketing’s gas in storage and these are accounted for as fair value
hedges. The change in value of these hedges and the change in value of the
inventory hedged are expected to largely offset in each reporting period in
the
statement of operations. During the years ended September 30, 2006 and 2005,
the
Energy Marketing segment recorded MTM losses of $3.2 million and $3.3 million,
respectively, related to the application of fair value hedge accounting to
certain storage inventory transactions. The Energy Marketing segment uses
derivatives to mitigate commodity price risk and substantially lock in the
profit margin that it will ultimately realize when inventory volumes are
withdrawn from storage. Under fair value accounting, which is used for certain
storage activity, the MTM adjustment to inventory is computed using spot prices,
while the derivatives used to mitigate the risk of changes in inventory value
are marked to market using forward prices. When the spot price of natural gas
changes disproportionately to the forward price, the difference is recorded
in
operating results. As a result, earnings are subject to volatility, even when
the underlying expected profit margin over the duration of the contracts is
unchanged. The volatility resulting from this accounting can be significant
from
period to period. A portion of this accounting loss will reverse next year
if
the volumes are withdrawn from storage. At September 30, 2006, gas inventory
hedged using fair value accounting at Energy Marketing had a fair value of
$18.0
million, including MTM decreases in inventory totaling $16.8 million for changes
in spot prices. Derivative assets totaling $10.3 million were recorded for
the
fair value of the derivatives used to hedge this inventory. At September 30,
2005, hedged gas inventory at Energy Marketing had a fair value of $44.1
million, including MTM increases in inventory totaling $17.6 million for changes
in spot prices. Derivative liabilities totaling $20.9 million were recorded
for
the fair value of the derivatives used to hedge this inventory.
The
Company also uses certain financial instruments to adjust the portfolio
composition of its debt from fixed-rate to floating-rate debt. These derivative
instruments are accounted for as fair value hedges and are not material to
the
Company's financial condition or results of operations. The change in value
of
these hedges along with the offsetting change in value of the debt hedged (to
the extent the hedge is effective) are recorded in each reporting period in
interest expense in the statement of operations.
Mark-To-Market
Derivative Instruments.
Peoples
Gas and North Shore Gas use derivative instruments to manage each utility’s cost
of gas supply and mitigate price volatility. All such derivative instruments
are
measured at fair value. The regulated utilities’ tariffs allow for full recovery
from their customers of prudently incurred gas supply costs, including gains
or
losses on these derivative instruments. As a result, SFAS No. 71 allows these
MTM derivative gains or losses to be recorded as regulatory assets or regulatory
liabilities. Realized gains or losses are recorded as an adjustment to the
cost
of gas supply in the period that the underlying gas purchase transaction takes
place. The costs and benefits of this activity are passed through to customers
under the tariffs of Peoples Gas and North Shore Gas.
The
Energy Marketing segment uses certain derivative contracts (such as NYMEX or
Basis swaps) that do not qualify for hedge accounting under SFAS No. 133.
Included in these contracts are hedges of location differentials associated
with
its wholesale natural gas contracts and transactions involving storage assets.
In the fiscal year
ended
September 30, 2006, the Energy Marketing segment recognized MTM pretax gains
(losses) (included in revenues) of $1.3 million related to these derivatives.
As
physical volumes are delivered under natural gas contracts or withdrawn under
certain gas storage contracts, these MTM accounting impacts are reversed. The
above amounts include net MTM activity both for hedges for settlement in future
periods and the reversal of amounts recorded in prior periods and settled within
the current period.
The
following table summarizes the market value of these outstanding instruments
and
other derivative instruments that do not qualify for hedge accounting and are
recorded on a MTM basis. All amounts are expected to be settled during the
next
12 months.
|
September
30,
|
|||||||
|
(In
Thousands)
|
2006
|
2005
|
|||||
|
Peoples
Gas mark-to-market asset (liability)
|
$
|
(128,417
|
)
|
$
|
172,549
|
||
|
North
Shore Gas mark-to-market asset (liability)
|
(24,135
|
)
|
33,754
|
||||
|
Other
mark-to-market asset (liability)
|
992
|
(2,027
|
)
|
||||
|
Total
|
$
|
(151,560
|
)
|
$
|
204,276
|
||
Weather Risk
The
Company’s Gas Distribution earnings vary due to the warmth or severity of the
weather. The Company has managed this risk through the purchase of weather
insurance and the use of block rates in utility rate design. Block rates help
mitigate the effect of warm weather by allowing greater cost recovery on the
first volumes through the meter and less on the last volumes. The insurance
in
place for fiscal 2005 was provided by a subsidiary of X.L. America, Inc. and
protected the Company for a portion of lost revenue incurred when weather was
more than 5% warmer than normal. In fiscal 2005 the Company recognized as
additional revenues $3.5 million in insurance recoveries. No weather insurance
was purchased for fiscal 2006 as the Company views the current market pricing
for this product as excessive relative to the risk it would protect
against.
The
Energy Marketing business segment can also be affected by weather variations.
Storage, swing supply and weather derivatives are used or are available to
protect earnings and ensure performance.
Interest
Rate Risk
The
Company uses interest rate derivatives to adjust the portfolio composition
of
fixed-rate and floating rate debt and it accounts for these derivatives as
fair
value hedges.
In
August
2004, the Company entered into a six-month LIBOR-based interest rate swap
agreement on $50.0 million of its $325.0 million 6.90% Series A
Notes, due January 15, 2011. Under this agreement, the Company will receive
the fixed price of 6.90% and pay six-month LIBOR plus a defined spread on the
notional amount of $50.0 million. The payments will reset on the
15th day of each January and July until maturity of the Series A
Notes.
Credit
Risk
The
Company has established a credit policy to mitigate the effect of nonperformance
on wholesale transactions. Pursuant to this policy, a credit limit is
established for all counterparties based on a review of their financial
condition. The Company reviews, and changes when necessary, its credit
underwriting and monitoring procedures. The Company has adequate financial
assurance provisions in its commercial agreements that permit the Company to
call for credit support when warranted. Action may include the calling of
collateral, adjusting credit lines, changing payment terms or reducing future
business. In addition, netting arrangements and requirements to post margin
are
used to further reduce credit exposure.
Credit
risk for the utility companies is spread over a diversified base of residential,
commercial and industrial customers. Customers’ payment records are continually
monitored and credit deposits are required, when appropriate.
* The Company's investment in Elwood meets certain "significance" tests pursuant to Rule 3-09 of SEC Regulation S-X. The Company intends to file by December 29, 2006, an amendment to its annual report on Form 10-K to include the separate financial statements of Elwood.
REPORT
OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To
the
Shareholders of Peoples Energy Corporation:
We
have
audited the accompanying consolidated balance sheets and consolidated
capitalization statements of Peoples Energy Corporation and subsidiary companies
(the Company) as of September 30, 2006 and 2005, and the related consolidated
statements of operations, stockholders’ equity, and cash flows for each of the
three years in the period ended September 30, 2006. Our audits also included
the
financial statement schedules listed in the Index at Item 15(a)2. These
consolidated financial statements and financial statement schedules are the
responsibility of the Company’s management. Our responsibility is to express an
opinion on these consolidated financial statements and financial statement
schedules based on our audits.
We
conducted our audits in accordance with standards of the Public Company
Accounting Oversight Board (United States). 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 consolidated financial statements referred to above present fairly,
in all material respects, the financial position of Peoples Energy Corporation
and subsidiary companies at September 30, 2006 and 2005, and the results of
their operations and their cash flows for each of the three years in the period
ended September 30, 2006, in conformity with accounting principles generally
accepted in the United States of America. Also, in our opinion, such financial
statement schedules, when considered in relation to the basic consolidated
financial statements taken as a whole, present fairly in all material respects
the information set forth therein.
As
discussed in Note 2 to the consolidated financial statements, effective
September 30, 2006, the Company changed its method of accounting for conditional
asset retirement obligations to adopt FASB Interpretation No. 47, “Conditional
Asset Retirement Obligations”.
We
have
also audited, in accordance with the standards of the Public Company Accounting
Oversight Board (United States), the effectiveness of the Company's internal
control over financial reporting as of September 30, 2006, based on the criteria
established in
Internal
Control—Integrated Framework
issued
by the Committee of Sponsoring Organizations of the Treadway Commission and
our
report dated December 14, 2006, expressed an unqualified opinion on management's
assessment of the effectiveness of the Company's internal control over financial
reporting and an unqualified opinion on the effectiveness of the Company's
internal control over financial reporting.
/s/
DELOITTE & TOUCHE LLP
DELOITTE
& TOUCHE LLP
Chicago,
Illinois
December
14, 2006
REPORT
OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To
The
Peoples Gas Light and Coke Company:
We
have
audited the accompanying consolidated balance sheets and consolidated
capitalization statements of The Peoples Gas Light and Coke Company and
subsidiary companies (hereinafter referred to as Peoples Gas, a wholly owned
subsidiary of Peoples Energy Corporation) as of September 30, 2006 and 2005,
and
the related consolidated statements of operations, stockholder’s equity, and
cash flows for each of the three years in the period ended September 30, 2006.
Our audits also included the financial statement schedules listed in the Index
at Item 15(a)2. These consolidated financial statements and financial statement
schedules are the responsibility of the management of Peoples Gas. Our
responsibility is to express an opinion on these consolidated financial
statements and financial statement schedules based on our audits.
We
conducted our audits in accordance with standards of the Public Company
Accounting Oversight Board (United States). Those standards require that we
plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. Peoples Gas is not required to
have, nor were we engaged to perform, an audit of its internal control over
financial reporting. Our audits included consideration of internal control
over
financial reporting as a basis for designing audit procedures that are
appropriate in the circumstances, but not for the purpose of expressing an
opinion on the effectiveness of the internal control over financial reporting
of
Peoples Gas. Accordingly, we express no such opinion. An audit also includes
examining, on a test basis, evidence supporting the amounts and disclosures
in
the financial statements, assessing the accounting principles used and
significant estimates made by management, 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 consolidated financial statements referred to above present fairly,
in all material respects, the financial position of Peoples Gas at September
30,
2006 and 2005, and the results of its operations and its cash flows for each
of
the three years in the period ended September 30, 2006, in conformity with
accounting principles generally accepted in the United States of America. Also,
in our opinion, such financial statement schedules, when considered in relation
to the basic consolidated financial statements taken as a whole, present fairly
in all material respects the information set forth therein.
As
discussed in Note 2 to the consolidated financial statements, effective
September 30, 2006, Peoples Gas changed its method of accounting for conditional
asset retirement obligations to adopt FASB Interpretation No. 47, “Conditional
Asset Retirement Obligations”.
/s/
DELOITTE & TOUCHE LLP
DELOITTE
& TOUCHE LLP
Chicago,
Illinois
December
14, 2006
REPORT
OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To
North
Shore Gas Company:
We
have
audited the accompanying consolidated balance sheets and consolidated
capitalization statements of North Shore Gas Company and subsidiary companies
(hereinafter referred to as North Shore Gas, a wholly owned subsidiary of
Peoples Energy Corporation) as of September 30, 2006 and 2005, and the related
consolidated statements of operations, stockholder’s equity, and cash flows for
each of the three years in the period ended September 30, 2006. Our audits
also
included the financial statement schedules listed in the Index at Item 15(a)2.
These consolidated financial statements and financial statement schedules are
the responsibility of the management of North Shore Gas. Our responsibility
is
to express an opinion on these consolidated financial statements and financial
statement schedules based on our audits.
We
conducted our audits in accordance with standards of the Public Company
Accounting Oversight Board (United States). Those standards require that we
plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. North Shore Gas is not required
to
have, nor were we engaged to perform, an audit of its internal control over
financial reporting. Our audits included consideration of internal control
over
financial reporting as a basis for designing audit procedures that are
appropriate in the circumstances, but not for the purpose of expressing an
opinion on the effectiveness of the internal control over financial reporting
of
North Shore Gas. Accordingly, we express no such opinion. An audit also includes
examining, on a test basis, evidence supporting the amounts and disclosures
in
the financial statements, assessing the accounting principles used and
significant estimates made by management, 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 consolidated financial statements referred to above present fairly,
in all material respects, the financial position of North Shore Gas at September
30, 2006 and 2005, and the results of its operations and its cash flows for
each
of the three years in the period ended September 30, 2006, in conformity with
accounting principles generally accepted in the United States of America. Also,
in our opinion, such financial statement schedules, when considered in relation
to the basic consolidated financial statements taken as a whole, present fairly
in all material respects the information set forth therein.
As
discussed in Note 2 to the consolidated financial statements, effective
September 30, 2006, North Shore Gas changed its method of accounting for
conditional asset retirement obligations to adopt FASB Interpretation No. 47,
“Conditional Asset Retirement Obligations”.
/s/
DELOITTE & TOUCHE LLP
DELOITTE
& TOUCHE LLP
Chicago,
Illinois
December
14, 2006
| (1) |
Accumulated
other comprehensive income balance is net of $17.0 million and
$5.2
million of deferred income tax credits
related
to minimum pension liabilities at September 30, 2005 and 2004,
respectively. At September 30, 2006, there was no
minimum
pension liability; the related balance in accumulated other comprehensive
income was reduced to
zero.
|
| (2) |
Accumulated
other comprehensive income balance is net of $12.8 million,
$80.9 million
and $37.9 million of deferred
income
tax credits related to unrealized hedge losses at September
30, 2006, 2005
and 2004,
respectively.
|
| (1) |
Accumulated
other comprehensive income balance is net of $14.0 million and
$4.4
million of deferred
income
tax credits related to minimum pension liabilities at September
30, 2005
and 2004, respectively. At September 30, 2006,
there
was no minimum pension liability; the related balance in accumulated
other
comprehensive income was reduced to
zero.
|
| (2) |
Accumulated
other comprehensive income balance is net of $0.9 million, $0.2
million
and $0.2 million of deferred
income
tax credits related to unrealized hedge losses at September 30,
2006, 2005
and 2004,
respectively.
|
| (1) |
Accumulated
other comprehensive income balance is net of $1.5 million
and $0.8 million
of deferred income tax credits related
to
minimum pension liabilities at September 30, 2005 and 2004,
respectively.
At September 30, 2006, there was no minimum
pension
liability; the related balance in accumulated other comprehensive
income
was reduced to zero.
|
| (2) |
Accumulated
other comprehensive income balance is net of $0.1 million,
$0.1 million
and $0.1 million of deferred income tax
credits
related to unrealized hedge losses at September 30, 2006,
2005 and 2004,
respectively.
|
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
On
July 8,
2006, WPS Resources Corporation (WPS Resources), Wedge Acquisition Corporation
(Sub), a wholly owned subsidiary of WPS Resources, and Peoples Energy
Corporation (the Company or Peoples Energy) entered into an Agreement and Plan
of Merger (the Agreement).
The
Agreement provides for the merger of Sub with and into Peoples Energy (the
Merger) on the terms and subject to the conditions set forth in the Agreement,
with Peoples Energy continuing as the surviving corporation. As a result of
the
Merger, Peoples Energy will become a wholly owned subsidiary of WPS Resources,
and Peoples Energy shareholders will receive shares of WPS Resources common
stock in exchange for their shares of common stock of Peoples Energy. At the
effective time of the Merger, each share of common stock of Peoples Energy
issued and outstanding immediately prior to the effective time will be cancelled
and converted into the right to receive 0.825 shares of common stock of WPS
Resources. The companies expect that upon consummation of the Merger Peoples
Energy shareholders will own approximately 42.4% of the common stock of WPS
Resources and WPS Resources shareholders will own approximately 57.6% of the
common stock of WPS Resources.
WPS
Resources and Peoples Energy have each made customary representations,
warranties and covenants in the Agreement, including, among others, covenants
to
conduct their businesses in the ordinary course between the execution of the
Agreement and the consummation of the Merger and covenants not to engage in
certain kinds of transactions during that period. During such period, Peoples
Energy will not declare cash dividends in excess of $0.545 per share per quarter
without the prior consent of WPS Resources. Immediately after the effective
time
of the Merger, WPS Resources will adopt a dividend policy providing for a
quarterly dividend of $0.66 per share of WPS Resources common stock, subject
to
evaluation over time as future business needs dictate. WPS Resources and Peoples
Energy have made certain additional customary covenants, including, among
others, covenants, subject to certain exceptions, (A) to cause a shareholders
meeting to be held to consider approval of the Merger and the other transactions
contemplated by the Agreement, (B) not to solicit proposals relating to
alternative business combination transactions, and (C) not to enter into
discussions concerning, or provide confidential information in connection with,
alternative business combination transactions.
Consummation
of the Merger is subject to customary conditions, including, among others,
(i)
approval of the shareholders of each of WPS Resources and Peoples Energy, (ii)
absence of any material adverse effect, (iii) expiration or termination of
the
applicable Hart-Scott-Rodino Act waiting period, (iv) absence of any order
or
injunction prohibiting the consummation of the Merger, (v) the registration
statement on Form S-4 shall have become effective, (vi) the shares of WPS
Resources common stock issuable to Peoples Energy’s shareholders pursuant to the
Agreement and under the employee benefit plans of Peoples Energy shall have
been
approved for listing on the New York Stock Exchange, (vii) subject to certain
exceptions, the accuracy of representations and warranties with respect to
WPS
Resources’ and Peoples Energy’s business, as applicable, (vii) receipt of
customary tax opinions and (viii) receipt of all required statutory approvals
from, among others, the FERC, the Federal Communications Commission, and state
public service and utility commissions.
The
Agreement contains certain termination rights for both WPS Resources and Peoples
Energy, and further provides that, upon termination of the Agreement under
specified circumstances, a party would be required to pay the other party a
termination fee of $45 million. In addition, under specified circumstances
each
party may be obligated to reimburse the other party for up to $15 million of
expenses, which would reduce the amount of any required termination fee payable
by that party.
The
consummation of the Merger is subject to the satisfaction or waiver of closing
conditions applicable to both WPS
Resources
and Peoples Energy, including the receipt of required regulatory approvals
and
the approval of the transaction by the shareholders of both WPS Resources and
Peoples Energy. On August 2, 2006, WPS Resources, Peoples Energy, Peoples Gas
and North Shore Gas jointly filed an application for approval of the Merger
with
the Commission. The companies seek the expedited consideration of the
application by the
Commission,
with requested approval by December 28, 2006 so that the Merger could close
on
or shortly after January 1, 2007. The application indicates that The Peoples
Gas
Light and Coke Company (Peoples Gas) and North Shore Gas Company (North Shore
Gas) will further postpone filing rate cases until early 2007, with new rates
to
take effect in 2008 due to the normal 11-month rate case process in Illinois.
On
October 31, 2006, Commission Staff and Interveners filed Direct Testimony and
opinion on the Merger proposal. On November 13, 2006, the Companies filed
rebuttal testimony.
WPS
Resources and Peoples Energy filed their joint application for FERC approval
on
August 15, 2006. The comment period on the FERC filing passed with no comments
received. On November 2, 2006, the FERC issued a deficiency letter identifying
an item about which additional information was required, and WPS Resources
and
Peoples Energy responded on November 6, 2006. The comment period for this
response was concluded on November 13, 2006. No comments were
received.
On
August
15, 2006, WPS Resources filed with PSCW for approval of amendments to its
“affiliated interest” agreements so that they include and apply to Peoples
Energy and its subsidiaries, as appropriate, upon closing of the merger. These
agreements govern the provision by and among WPS Resources and its regulated
and
non-regulated subsidiaries of services, property, and other things of value.
Modification of these agreements requires the approval of the PSCW. WPS
Resources had concluded that no other PSCW approvals were required prior to
the
closing of the merger. However, on August 9, 2006, the PSCW issued a notice
of
investigation of the merger to consider, among other things, whether the PSCW
has jurisdiction and pre-approval authority over the merger. Subsequently,
the
PSCW asserted jurisdiction and pre-approval authority over the merger, and,
on
September 27, 2006, the PSCW re-noticed the investigatory matter as a contested
case proceeding in which it would consider whether the merger is in the public
interest and whether certain conditions should be placed upon WPS Resources
(and
affiliate arrangements within its holding company system) as a result of the
merger. WPS Resources acknowledges the PSCW’s continuing jurisdiction from time
to time to consider and, if appropriate, impose additional conditions upon
Wisconsin public utility holding companies. However, WPS Resources does not
believe that the PSCW has jurisdiction and pre-approval authority over the
merger, even though the PSCW has asserted such jurisdiction and authority.
The
PSCW has established a schedule for completion of the proceeding that would
accommodate a closing of the merger in the first quarter of 2007. WPS Resources’
participation in the proceeding will be subject to its right to challenge the
PSCW’s asserted jurisdiction before the PSCW and on appeal of an adverse PSCW
order.
Pursuant
to the Agreement, management from both companies jointly selected Integrys
Energy Group, Inc. (Integrys) as the new name for the combined company. Upon
consummation of the Merger, WPS Resources’ Board of Directors will be comprised
of sixteen directors, nine of whom will have been designated by WPS Resources
and seven of whom will have been designated by Peoples Energy. Mr. Larry Weyers,
currently Chairman, President and Chief Executive Officer of WPS Resources,
will
remain President and Chief Executive Officer of Integrys following the Merger.
Mr. James Boris, currently the Lead Director of Peoples Energy will become
the
non-executive Chairman of Integrys as of the effective time of the Merger.
Upon
the consummation of the Merger, WPS Resources will amend bylaws consistent
with
the foregoing.
On
October 9, 2006, the Company identified many of Integrys’ senior leaders, who
will manage Integrys after the transaction closes through a holding company,
operating companies and a services group. Following the Merger, Integrys will
establish its headquarters in Chicago, Illinois. The headquarters of the
Integrys’ unregulated energy marketing business will be located in Green Bay,
Wisconsin and the headquarters of the utilities’ businesses will be located in
the same place as immediately prior to the effective time of the Merger. The
headquarters of the oil and gas production business will remain in Houston,
Texas.
On
October 18, 2006, the WPS Resources registration statement on Form S-4 was
made
effective by the SEC.
On
October 25, 2006, the Federal Trade Commission granted termination of the
waiting period for the Hart-Scott-Rodino filing for the Merger.
On
December 6, 2006, at special meetings of shareholders held by WPS Resources
and
Peoples Energy, shareholders of both companies approved the proposed merger
transaction. WPS Resources’ shareholders also
approved
an amendment to WPS Resources Corporation’s restated articles of incorporation
to change the name of WPS Resources Corporation to Integrys Energy Group, Inc.,
when the closing of the merger has been completed.
For
the
fiscal year ended September 30, 2006, the Company incurred merger related costs
of $8.9 million, primarily legal, consulting and investment banking fees. Under
SFAS No. 141, such costs are expensed as incurred by the Company as the acquired
entity in the merger. The Company has recorded the income tax impact of merger
costs based upon its current estimate of their ultimate treatment, however,
this
estimate is subject to change based upon the outcome of future
events.
A.
General
Peoples
Energy is a holding company whose income is derived principally from its
regulated utility subsidiaries, Peoples Gas and North Shore Gas. The utilities
are primarily engaged in the sale and transportation of natural gas to
residential, commercial and industrial customers in Chicago and the northeast
section of Illinois. Peoples Gas’ and North Shore Gas’ utility operations are
subject to regulation by the Commission. Regulated operations are accounted
for
in accordance with SFAS No. 71. This standard controls the application of GAAP
for companies whose rates are determined by an independent regulator such as
the
Commission. Under this standard, certain costs or revenues are deferred on
the
balance sheet until recovered or refunded through rates. Other business segments
of the Company include Oil and Gas Production, Energy Marketing (both retail
and
wholesale activity), Energy Assets (primarily power generation), and Corporate
and Other.
The
Company makes certain estimates and assumptions in preparing its consolidated
financial statements in accordance with GAAP. These estimates and assumptions
affect the reported amounts of assets and liabilities, the disclosure of
contingent assets and liabilities at the date of the financial statements and
the reported amounts of revenues and expenses for the periods presented. Actual
results may differ from those estimates.
All
subsidiaries are included in the consolidated financial statements. All
significant intercompany transactions have been eliminated in consolidation.
Investments for which the Company or its subsidiaries have at least a 20%
interest, but less than a majority ownership, are accounted for under the equity
method, as the Company has the ability to exercise significant influence, but
not control, over the investee’s operating and financial policies.
B.
Discontinued Operations
The
Company announced in February, 2006 its intention to exit the power generation
business. On January 31, 2006, the Company sold its 100% interest in the
Valencia Energy power development site in New Mexico. On May 31, 2006, the
Company completed the sale of its 27% interest in the SCEP facility to Exelon
Generation Company, LLC. On September 20, 2006, the Company announced that
it
signed an agreement with J-Power USA Development Co., Ltd. to sell its 50%
interest in the Elwood power generation facility and its 100% interest in a
fully-permitted power development site, the COB Energy Facility (COB), for
$110
million, subject to certain closing adjustments. These sales will complete
the
divestiture of substantially all power assets owned by Peoples Energy. The
Board
of Directors of J-Power's parent company approved the transactions on November
30, 2006. Financial results for power generation are now being reported by
Peoples Energy as discontinued operations. Through Elwood and COB, the Company
owned approximately 700 net Megawatts of power generation assets.
The
operating results of the Company’s power generation business were reported under
the Power Generation segment and included in consolidated operating income
prior
to the change in segment reporting described below and the treatment as
discontinued operations. Effective in the second quarter of fiscal 2006, the
Company reports the results of operations of its power generation business
as
discontinued operations in accordance with SFAS No. 144. Results of operations
and assets for all periods have been reclassified to conform with the
discontinued operations presentation.
The
following table summarizes the power generation items which are reflected as
assets of and deferred credit related to discontinued operations in the
Company’s consolidated balance sheets.
|
|
September
30,
|
||||||
|
2006
|
2005
|
||||||
|
(In
Thousands)
|
|||||||
|
Investments
in unconsolidated affiliates
|
$
|
74,071
|
$
|
115,168
|
|||
|
Other
investments
|
10,400
|
12,245
|
|||||
|
Property,
plant and equipment, net
|
-
|
906
|
|||||
|
Total
assets
|
$
|
84,471
|
$
|
128,319
|
|||
|
Deferred
credit
|
$
|
-
|
$
|
2,201
|
|||
The
summarized financial results for the Company’s discontinued operations were as
follows:
| Fiscal Year Ended September 30, | 2006 | 2005 | 2004 | |||||||
| (In Thousands) | ||||||||||
| Operation and maintenance | $ | (3,600) | $ | (2,009) | $ | (4,055) | ||||
| Taxes, other than income taxes | (84) | (63) | (104) | |||||||
| Gains on property sales | 4,139 | - | - | |||||||
| Impairments and losses on property sales | (2,156) | (143) | - | |||||||
| Equity investment income | 18,803 | 20,944 | 15,481 | |||||||
| Income before income taxes | 17,102 | 18,729 | 11,322 | |||||||
| Income tax expense | 6,797 | 7,444 | 4,500 | |||||||
| Income from discontinued operations, net of | ||||||||||
|
income
taxes
|
$ | 10,305 | $ | 11,285 | $ | 6,822 |
C.
Gas Charge Settlement
On
March
28, 2006, the Commission approved orders that settle gas charge reconciliation
proceedings for fiscal years 2001 through 2004 for Peoples Energy Corporation
and its utility subsidiaries. The orders, which became publicly available March
30, adopt a January 17, 2006 Settlement Agreement and Release, as amended by
an
Amendment and Addendum dated March 6, 2006 (the Agreement).
Pursuant
to the Agreement, Peoples Gas and North Shore Gas agreed to refund (through
a
credit applied to customer bills) the total sum of $100 million to their
customers. In its orders approving the Agreement, the Commission determined
that
$96 million
should
be
refunded to customers of Peoples Gas and $4 million should be refunded to
customers of North Shore Gas. In April 2006, the refund was credited to customer
accounts.
Pursuant
to the Agreement, Peoples Energy also paid $5 million jointly to the City of
Chicago and the Illinois Attorney General in 2006. The Company also agreed
to
pay up to $5 million per year over the next five years towards the funding
of
conservation and weatherization programs for low and moderate-income residential
dwellings (Conservation Programs). The five subsequent payments of up to $5
million shall be paid based upon Conservation Programs to be developed by the
City of Chicago and/or the Illinois Attorney General. Peoples Gas and North
Shore Gas will not seek recovery in any future rate or reconciliation cases
of
any amounts associated with the Conservation Programs.
Peoples
Gas and North Shore Gas agreed to forgive all outstanding bad debt from fiscal
years 2000-2005 existing as of March 6, 2006, estimated at $207 million, remove
the bad debt from customers’ records and to not use any forgiven indebtedness as
a reason to deny gas service. Peoples Gas and North Shore Gas had written off
the estimated $207 million in prior periods.
Peoples
Gas and North Shore Gas agreed to credit fiscal 2005 and fiscal 2006 revenues
derived from the provision of gas Hub services as an offset to utility
customers’ gas charges and to account for such revenues received from gas Hub
services in the same manner in all future gas charge reconciliation cases.
The
Company has reported for the fiscal year ended September 30, 2006 a charge
reflecting the terms of the settlement. This charge totaled $107.3 million
pretax or $1.68 per share after tax. The charge reflects $100 million in refunds
to customers, $10.7 million to reflect a change in the regulatory accounting
treatment for fiscal 2005 Hub revenues, $5 million in estimated additional
bad
debt expense
due
to
termination of collection activity on amounts previously written off and $5
million related to the first payment to the Illinois Attorney General and City
of Chicago under the settlement, and is net of approximately $13.3 million
in
previously recorded liabilities related to the cases. The $107.3 million charge
has been allocated $103.0 million to Peoples Gas and $4.3 million to North
Shore Gas in accordance with the Order. Accrued liabilities totaling $11.3
million at September 30, 2006 are included in the consolidated balance sheet
caption regulatory liabilities under current liabilities. Following is a
reconciliation of the total gas charge settlement per the statement of
operations and the related liability.
|
Total
|
|
Peoples
Gas
|
|
North
Shore Gas
|
||||||
|
(Dollars
in Thousands)
|
||||||||||
|
Refund
|
$
|
100,000
|
$
|
96,000
|
$
|
4,000
|
||||
|
Payment
to Illinois Attorney General and City of Chicago
|
5,000
|
4,800
|
200
|
|||||||
|
Hub
fiscal 2005 revenues
|
10,662
|
10,662
|
-
|
|||||||
|
Bad
debt expense
|
5,000
|
4,900
|
100
|
|||||||
|
Amounts
recognized prior to fiscal 2006
|
(13,332
|
)
|
(13,332
|
)
|
-
|
|||||
|
Gas
charge settlement per consolidated statements of
operations
|
||||||||||
|
for
fiscal 2006
|
$
|
107,330
|
$
|
103,030
|
$
|
4,300
|
||||
|
Add:
|
||||||||||
|
Amounts
recognized prior to fiscal 2006
|
13,332
|
13,332
|
-
|
|||||||
|
Interest
on Hub fiscal 2005 revenues refundable
|
||||||||||
|
and
other minor amounts refundable
|
588
|
587
|
1
|
|||||||
|
Less:
|
||||||||||
|
Addition
to reserve for uncollectible accounts
|
5,000
|
4,900
|
100
|
|||||||
|
Less
payments in fiscal 2006:
|
||||||||||
|
Refund
credited to customer accounts
|
100,000
|
96,000
|
4,000
|
|||||||
|
Payment
to Illinois Attorney General and City of Chicago
|
5,000
|
4,800
|
200
|
|||||||
|
Gas
charge settlement liability per consolidated balance
sheets
|
||||||||||
|
at
September 30, 2006 (1)
|
$
|
11,250
|
$
|
11,249
|
$
|
1
|
||||
| (1) |
Represents
2005 Hub Revenue and related interest that will be refunded to
customers
pending close of
the
Commission's review of 2005 gas charge reconciliation and minor
amounts to
be refunded to customers
through
the monthly gas charge filings in early fiscal
2007.
|
See
Note
8A for a complete discussion of the gas charge cases and the settlement
agreement.
D.
Use of Fair Value Measurements
The
Company reports certain contracts and instruments at fair value in accordance
with GAAP. Fair value is based on actively quoted market prices, if available.
In the absence of actively quoted market prices, the Company seeks indicative
price information from external sources, including broker quotes and industry
publications. If pricing information from external sources is not available,
the
Company must estimate prices based on available historical and near-term future
price information and certain statistical methods, including regression
analysis.
For
options and contracts with option-like characteristics where pricing information
is not available from external sources, the Company uses a modified
Black-Scholes model and considers time value, the volatility of the underlying
commodities and other relevant assumptions when estimating fair value. If
pricing information is not available from external sources, judgment is required
to develop the estimates of fair value. For individual contracts, the use of
different assumptions could have a material effect on the contract’s estimated
fair value.
The
following table summarizes the carrying amounts and fair values of long-term
debt financial instruments included in the Consolidated Balance Sheets of the
Company, Peoples Gas and North Shore Gas.
|
(In
Millions)
|
Peoples
Energy
|
Peoples
Gas
|
North
Shore Gas
|
||||||||||
|
Long-term
debt including
current
portion
|
Carrying
Amount
|
Estimated
Fair
Value
|
Carrying
Amount
|
Estimated
Fair
Value
|
Carrying
Amount
|
Estimated
Fair
Value
|
|||||||
|
At
September 30, 2006
|
$894.7
|
|
$907.1
|
|
$502.0
|
|
$499.6
|
|
$69.3
|
|
$67.4
|
||
|
At
September 30, 2005
|
$895.6
|
|
$912.8
|
|
$502.0
|
|
$499.9
|
|
$69.3
|
|
$67.4
|
||
The
estimated fair values are determined based on the long-term debt interest rates
that are currently available for issuance of debt with similar terms, call
dates
and remaining maturities. The carrying amount of all other financial instruments
approximate fair value.
Considerable
judgment is required to develop the fair value estimates; therefore, the values
are not necessarily indicative of the amounts that could be realized in a
current market exchange. The fair value estimates are based on information
available to management as of each fiscal year-end. Management is not aware
of
any subsequent factors that would affect significantly the estimated fair value
amounts.
E.
Revenue Recognition
Natural
gas and electricity sales and transportation revenues for the utilities and
Peoples Energy Services Corporation are recorded on the accrual basis for all
gas and electricity delivered during the month, including an estimate for gas
and electricity delivered but unbilled at the end of each month. The amount
of
accrued unbilled revenue included in gross receivables from customers is
summarized below.
|
September
30,
|
|||||||
|
(In
Thousands)
|
2006
|
2005
|
|||||
|
Peoples
Gas
|
$
|
31,247
|
$
|
32,282
|
|||
|
North
Shore Gas
|
5,933
|
6,136
|
|||||
|
Peoples
Energy Services
|
21,269
|
19,362
|
|||||
|
Consolidated
Peoples Energy
|
$
|
58,449
|
$
|
57,780
|
|||
In
Illinois, delivering, supplying, furnishing or selling gas for use or
consumption and not for resale is subject to state and, in some cases, municipal
taxes (revenue taxes). The Illinois Public Utilities Act provides that the
tax
may be recovered from utility customers by adding an additional charge to
customers' bills. These taxes are due only to the extent they are collected
as
cash receipts as opposed to amounts billed. As a result, most revenue taxes
are
reported on a gross basis, whereby the billed amounts for the recovery of these
taxes are included in revenues and an offsetting expense amount (net of an
administrative fee) representing the expected cash payment of the taxes is
included in taxes, other than income taxes on the statement of operations.
Revenue tax amounts included in utility revenues are as follows:
|
For
Fiscal Years Ended September 30,
|
|||||||||||||
|
(In
Thousands)
|
2006
|
2005
|
2004
|
||||||||||
|
Peoples
Gas
|
$
|
148,462
|
$
|
133,987
|
$
|
124,797
|
|||||||
|
North
Shore Gas
|
13,339
|
13,119
|
12,125
|
||||||||||
|
Consolidated
Peoples Energy
|
$
|
161,801
|
$
|
147,106
|
$
|
136,922
|
|||||||
In
the
Oil and Gas production segment, natural gas and crude oil production revenues
are recorded on the entitlement method. Under the entitlement method, revenue
is
recorded when title is transferred based on the
Company's
net interest. The Company records its entitled share of revenues based on
estimated monthly production volumes. Subsequently, these estimated volumes
are
adjusted to reflect actual volumes that are supported by third party statements
and/or cash receipts.
F.
Weather Insurance
The
Company was partially protected from the impact of unusually mild weather by
a
weather insurance program subject to certain deductibles and maximums for fiscal
year 2005. The contract settled annually at the fiscal year-end. The insurance
proceeds are reported as revenue and the premium is charged to operating expense
based on the guidance of EITF 99-02. The Company recorded $3.5 million in
weather insurance recovery as revenue in 2005 and no revenue was recorded in
2006 or 2004.
G.
Income Taxes
The
Company follows the asset and liability method of accounting for deferred income
taxes. Under this 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 Peoples Gas and North Shore Gas, certain adjustments
made to deferred income taxes are, in turn, recorded as regulatory assets
(liabilities). (See Note 2K.)
Income
taxes allocated to Peoples Gas and North Shore Gas are included in the
consolidated tax return of the Company. The separate return method has not
been
used, but the principles of that method are generally followed. Deferred taxes
exist at Peoples Gas and North Shore Gas only if the temporary differences
that
generate those deferred taxes are derived from assets and liabilities of Peoples
Gas and North Shore Gas. Additionally, the taxable income of Peoples Gas and
North Shore Gas is the basis for recording current income tax expense and cash
payments by each utility. Finally, tax benefits of loss companies, or tax
credits from nonutility subsidiaries of the Company, are allocated to those
nonutility subsidiaries.
There
are
specific deviations from the separate return method. North Shore Gas could
be an
alternative minimum tax (AMT) taxpayer if it were a stand-alone company but
only
records a deferred tax asset and pays amounts to the Company if the entire
group
is an AMT taxpayer. North Shore Gas uses the federal income tax marginal rate
of
35%, but on a stand-alone basis, it would use a marginal rate between 34% and
35%. Finally, if Peoples Gas or North Shore Gas were to have a capital loss,
and
another member of the group had capital gains to offset that loss, no deferred
tax asset or increase to income tax expense would result.
Each
utility subsidiary within the consolidated group nets its income tax-related
regulatory assets and liabilities. At September 30, 2006 and 2005, net
regulatory income tax assets for both the Company and Peoples Gas amounted
to
$22.6 million and $23.1 million, respectively. At September 30, 2006 and 2005,
net regulatory income tax liabilities for both the Company and North Shore
Gas
recorded in other liabilities equaled $2.1 million and $2.0 million,
respectively.
Investment
tax credits have been deferred and are being amortized to income over the
remaining book lives of related property.
H.
Asset Retirement Obligations
SFAS
No. 143
Legal
retirement obligations previously identified at the Company under the provisions
of SFAS No. 143, related primarily to reserve assets at the Oil and Gas
Production segment. Those obligations totaled $2.0 million and $1.6 million
at
September 30, 2006 and 2005, respectively.
Adoption
of FIN 47
The
Company adopted the provisions of FIN 47, as of September 30, 2006. Upon
adoption of this interpretation, the Company recorded liabilities for
conditional asset retirement obligations, which were previously believed to
be
outside the scope of SFAS No. 143.
As
of
September 30, 2006, the Company recorded as conditional asset retirement
obligations the following amounts:
| · |
Pipe
Removal - Distribution (including asbestos and PCBs in pipes) - $109.0
million
|
| · |
Asbestos
and PCBs in Property - $0.5 million
|
| · |
Above
Ground Storage Tanks - $0.8 million
|
The
Company, Peoples Gas and North Shore Gas also recorded an increase in the net
carrying value of related property, plant and equipment and an increase in
regulatory assets for future retirement costs as part of adopting FIN 47:
|
Total
|
||||||||||
|
(Millions)
|
|
Peoples
Gas
|
|
North
Shore Gas
|
Peoples
Energy
|
|||||
|
Property,
plant and equipment
|
$
|
22.2
|
$
|
5.1
|
$
|
27.3
|
||||
|
Accumulated
depreciation
|
(7.9
|
)
|
(1.7
|
)
|
(9.6
|
)
|
||||
|
Property,
plant and equipment, net
|
14.3
|
3.4
|
17.7
|
|||||||
|
Regulatory
assets
|
76.8
|
15.8
|
92.6
|
|||||||
|
Asset
retirement obligations - adoption of FIN 47
|
$
|
91.1
|
$
|
19.2
|
$
|
110.3
|
||||
The
cumulative effect of adopting FIN 47 has been deferred as a regulatory asset
in
anticipation that the actual costs to dispose of the assets will be recoverable
in future rates. Under SFAS No. 71, regulatory assets are recognized for timing
differences between the Company’s recovery of the asset retirement obligations
in rates and when the Company recognizes these costs under FIN 47.
If
the
Company had applied the provisions of FIN 47 as of October 1, 2003, the pro
forma impacts on net income and basic and diluted earnings per common share
would not be material. The following table lists the pro forma amount of the
liability for asset retirement obligations for prior years.
|
Gas
Distribution
|
|
Total
|
||||||||
|
(Millions)
|
|
Peoples
Gas
|
|
North
Shore Gas
|
Peoples Energy | |||||
|
September
30, 2005
|
$
|
86.2
|
$
|
18.1
|
$
|
104.3
|
||||
|
September
30, 2004
|
81.1
|
17.0
|
98.1
|
|||||||
|
October
1, 2003
|
77.4
|
15.9
|
93.3
|
|||||||
Changes to Asset Retirement Obligation Liabilities
The
following table describes all changes to the asset retirement obligations of
the
Company through September 30, 2006, including the adoption of FIN
47.
|
Gas
Distribution
|
|||||||||||||
|
(Millions)
|
|
Peoples
Gas
|
|
North
Shore Gas
|
Oil
and Gas Production
|
Total
|
|||||||
|
Asset
retirement obligations at October 1, 2003
|
$
|
-
|
$
|
-
|
$
|
0.7
|
$
|
0.7
|
|||||
|
Accretion
expense
|
-
|
-
|
0.1
|
0.1
|
|||||||||
|
Liabilities
incurred
|
-
|
-
|
0.4
|
0.4
|
|||||||||
|
Asset
retirement obligations at September 30, 2004
|
-
|
-
|
1.2
|
1.2
|
|||||||||
|
Accretion
expense
|
-
|
-
|
0.1
|
0.1
|
|||||||||
|
Liabilities
incurred
|
-
|
-
|
0.3
|
0.3
|
|||||||||
|
Asset
retirement obligations at September 30, 2005
|
-
|
-
|
1.6
|
1.6
|
|||||||||
|
Accretion
expense
|
-
|
-
|
0.1
|
0.1
|
|||||||||
|
Liabilities
incurred
|
-
|
-
|
0.4
|
0.4
|
|||||||||
|
Liabilities
settled
|
-
|
-
|
(0.1
|
)
|
(0.1
|
)
|
|||||||
|
Adoption
of FIN 47
|
91.1
|
19.2
|
-
|
110.3
|
|||||||||
|
Asset
retirement obligations at September 30, 2006
|
$
|
91.1
|
$
|
19.2
|
$
|
2.0
|
$
|
112.3
|
|||||
I.
Property, Plant and Equipment
Property,
plant and equipment is stated at original cost and includes amounts for
capitalized labor costs, payroll taxes, employee benefit costs, administrative
costs and an allowance for funds used during construction or capitalized
interest as appropriate.
The
Company’s utility subsidiaries charge 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, net of the accumulated reserve for depreciation, over
the
estimated composite remaining useful lives on the straight-line method.
Additionally, actual dismantling cost, net of salvage, is recorded as
depreciation expense in the month incurred. In April 2005, the Commission
approved new depreciation rates for both Peoples Gas and North Shore Gas that
reflect longer useful lives on utility plant. The $6.6 million impact ($5.4
million for Peoples Gas and $1.2 million for North Shore Gas) of the
depreciation change was retroactive to October 1, 2004, the effective date
of
the Commission Depreciation Order.
Diversified
businesses’ depreciable properties, other than oil and gas producing properties,
are amortized over their estimated useful lives. Gains and losses are recognized
at the time of asset sale or disposition.
The
consolidated provision for depreciation and amortization for the Company,
expressed as an annual percentage of the original cost of depreciable property,
was 2.7%, 2.7% and 3.0% for fiscal years 2006, 2005 and 2004, respectively.
For
Peoples Gas the annual percentage was 2.7%, 2.7% and 3.0% for fiscal years
2006,
2005 and 2004, respectively. For North Shore Gas the annual percentage was
1.8%,
1.8% and 2.3% for fiscal years 2006, 2005 and 2004, respectively.
In
the
case of oil and gas producing properties, the Company is amortizing associated
capitalized costs by utilizing the successful efforts method of accounting
on
the units-of-production method based on estimated proved oil and gas reserves.
The fiscal 2006, 2005 and 2004 average rate of depletion was
$2.11,
$1.87 and $1.69 per Mcfe unit of production, respectively.
At
September 30, 2006 and 2005, the Company did not have any exploratory
pre-production wells requiring additional major capital expenditures (to
determine presence of proved reserves) or any exploratory wells where more
than
one year had elapsed since the completion of drilling without a determination
of
well results.
At
September 30, 2006 and 2005, the Company had no capitalized exploratory well
costs pending determination of proved reserves. A portion of exploration expense
recognized in fiscal 2004 relates to the expensing of $2.7 million in costs
previously capitalized.
The
Company performs an evaluation for impairment whenever events or changes in
circumstances indicate that the carrying amount of long-lived assets or
intangible assets with finite lives may not be recoverable. These assets are
written down to fair value if the sum of the expected future undiscounted cash
flows is less than the carrying amounts. Fiscal 2006 results from discontinued
operations include impairments of $2.1 million. There were no impairments
recorded in 2005. Impairments recorded in 2004 were $1.1 million in the Energy
Marketing segment.
J.
Gas in Storage
The
Company’s utility subsidiaries price storage injections except for liquid
propane at North Shore Gas at the fiscal-year average of the costs of natural
gas supply purchased. Withdrawals from storage for the utilities except for
liquid propane at North Shore Gas are priced on the LIFO cost method. The
estimated replacement cost of gas in inventory at September 30, 2006 and 2005
exceeded the LIFO cost by approximately $83.7 million and $583.3 million,
respectively. North Shore Gas accounts for liquid propane inventory using the
average cost method.
The
estimated replacement cost of gas in inventory for Peoples Gas at September
30,
2006 and 2005 exceeded the LIFO cost by approximately $70.9 million and $498.4
million, respectively. The estimated replacement cost of
gas
in
inventory exclusive of the liquid propane for North Shore Gas at September
30,
2006 and 2005 exceeded the LIFO cost by approximately $12.7 million and $84.9
million, respectively. Both Peoples Gas’ and North Shore Gas’ calculation used a
year-end Chicago city-gate gas price per Dth of $3.67 for fiscal 2006 and $11.70
for fiscal 2005.
The
Energy Marketing and Energy Assets segments account for gas in inventory using
the average cost method. A portion of gas in storage for Energy Marketing is
reported at fair value to reflect the effects of fair value hedge accounting
in
accordance with SFAS No. 133.
K.
Regulated Operations
Peoples
Gas’ and North Shore Gas’ utility operations are subject to regulation by the
Commission. Regulated operations are accounted for in accordance with SFAS
No.
71. This standard controls the application of GAAP for companies whose rates
are
determined by an independent regulator such as the Commission.
Regulatory
assets represent probable future revenue associated with certain incurred costs
that will be recovered from customers through the ratemaking process. Regulatory
liabilities represent probable future reductions in revenue or refunds to
customers.
The
table
below summarizes the regulatory assets and liabilities of Peoples Gas and North
Shore Gas that were reflected on the Consolidated Balance Sheets.
|
Peoples
Gas
|
North
Shore Gas
|
||||||||||||
|
September
30,
|
September
30,
|
||||||||||||
|
2006
|
2005
|
2006
|
2005
|
||||||||||
|
(In
Thousands)
|
|||||||||||||
|
Regulatory
assets of subsidiaries
|
|||||||||||||
|
Environmental
costs, net of recoveries (see Note 7A)
|
$
|
243,990
|
$
|
248,520
|
$
|
69,225
|
$
|
65,834
|
|||||
|
Asset
retirement obligations (Note 2H)
|
76,804
|
-
|
15,771
|
-
|
|||||||||
|
Income
tax (see Note 2G)
|
22,550
|
23,120
|
-
|
-
|
|||||||||
|
Gas
costs recoverable through rate adjustments
|
4,514
|
6,889
|
2,165
|
1,719
|
|||||||||
|
Discount,
premium, expenses and loss on reacquired bonds
|
11,755
|
12,208
|
2,039
|
2,150
|
|||||||||
|
Gas
costs hedging program (see Note 2L)
|
131,410
|
-
|
24,692
|
-
|
|||||||||
|
Other
|
466
|
393
|
-
|
-
|
|||||||||
|
Total
regulatory assets of subsidiaries
|
491,489
|
291,130
|
113,892
|
69,703
|
|||||||||
|
Regulatory
liabilities of subsidiaries
|
|||||||||||||
|
Income
tax (see Note 2G)
|
-
|
-
|
2,117
|
2,001
|
|||||||||
|
Gas
costs hedging program (see Note 2L)
|
-
|
167,125
|
-
|
32,563
|
|||||||||
|
Gas
charge settlement (see Note 2C)
|
11,249
|
-
|
1
|
-
|
|||||||||
|
Gas
costs refundable through rate adjustments
|
49,726
|
29
|
12,427
|
264
|
|||||||||
|
Total
regulatory liabilities of subsidiaries
|
60,975
|
167,154
|
14,545
|
34,828
|
|||||||||
|
Net
regulatory assets and liabilities of subsidiaries
|
$
|
430,514
|
$
|
123,976
|
$
|
99,347
|
$
|
34,875
|
|||||
Environmental
costs, net of recoveries are the deferred costs associated with former
manufactured gas plant operations, which are allowed to be recovered by the
utilities from customers on a dollar-for-dollar basis. For each utility
subsidiary, the Commission conducts annual proceedings regarding the
reconciliation of revenues and related environmental costs. If the Commission
were to find that the reconciliation was inaccurate or any of the environmental
costs were imprudently incurred, the Commission would order the utility to
refund the affected amount to customers.
Under
the
tariffs of Peoples Gas and North Shore Gas, all prudently incurred gas costs
are
recoverable from customers. The difference for any month between costs
recoverable through the Gas Charge and the actual amount billed to customers
under the Gas Charge is recovered from or refunded to customers through future
adjustments to the Gas Charge. Such difference for any month is recorded either
as a current asset or as a current
liability
(with a contra entry to gas costs). Gas costs consist of two types—Commodity and
Non-Commodity costs. The two types are tracked independently and may cause
both
an accounts receivable from and an accounts payable to customers.
Gas
costs
recoverable and refundable through rate adjustments represent the regulatory
assets and liabilities, respectively, that result from the annual proceedings
conducted by the Commission regarding the reconciliation of revenues from the
Gas Charge and related gas costs. If the Commission were to find that the
reconciliation was inaccurate or any gas costs were imprudently incurred, the
Commission would order the utility to refund the affected amount to customers
through subsequent Gas Charge filings (see Note 8A).
Peoples
Gas and North Shore Gas use derivative instruments to manage each utility’s
respective cost of gas supply. SFAS No. 71 allows for MTM derivative gains
and
losses to be recorded as regulatory assets or regulatory liabilities. Realized
gains and losses are recorded as an adjustment to the cost of gas supply in
the
period that the underlying gas purchase transaction takes place. The costs
and
benefits of this activity are passed through to customers under the tariffs
of
Peoples Gas and North Shore Gas.
Costs
related to utility asset retirement obligations under SFAS No. 143 and FIN
47
are recoverable from utility customers. The Commission previously has approved
Company recovery of significant retirement (decommissioning) costs through
the
establishment of a regulatory asset. Amounts charged to customers for the costs
related to the retirement of long-lived assets may differ from the period costs
recognized in accordance with SFAS No. 143 and FIN 47 and, therefore, may result
in a difference in the timing of recognition of period costs for financial
reporting and rate-making purposes. Under the requirements of SFAS No. 71,
the
Company’s utility subsidiaries have recognized a regulatory asset for this
difference.
Certain
regulatory assets do not result from cash expenditures, and therefore do not
represent investments included in rate base or have offsetting liabilities
that
reduce the rate base of the utilities. Incremental environmental costs incurred
and not yet recovered from customers and recoverable gas costs, which are
generally recovered within one year, are not included in rate base. However,
the
Company is allowed to recover a carrying cost for amounts spent but not yet
collected from customers. The regulatory assets related to debt are not included
in rate base, but are recovered over the term of the debt through the rate
of
return authorized by the Commission.
L.
Derivative Instruments and Hedging Activities
The
Company's earnings may vary due to changes in commodity prices and interest
rates (market risk) that affect its operations and investments. To manage this
risk, the Company uses forward contracts and financial instruments, including
commodity futures contracts, swaps and options. It is the policy of the Company
to use these instruments solely for the purpose of managing risk and not for
any
speculative purpose. The Company accounts for derivative financial instruments
pursuant to SFAS No. 133. Under the provisions of SFAS No. 133, all derivatives
are recognized on the balance sheet at their fair value unless they qualify
for
the normal purchases and normal sales exception.
Cash
Flow Hedges.
The
Company has positions in oil and gas reserves, natural gas, and transportation
as part of its Oil and Gas Production and Energy Marketing businesses, and
related to its company use gas in the Gas Distribution segment. The Company
uses
derivative financial instruments to protect against loss of value of future
anticipated cash transactions caused by commodity price changes in the
marketplace. These instruments are designated as cash flow hedges, which allow
for the effective portion of unrealized changes in value during the life of
the
hedge to be recorded in other comprehensive income. Realized gains and losses
from commodity cash flow hedges are recorded in revenues or cost of energy
sold
in the statement of operations in the same month the related physical sales
or
purchases are recorded in the statement of operations.
Cash
flow
hedge accounting is discontinued when it is no longer probable that the original
forecasted transactions will occur. The carrying value of contracts which no
longer qualify for hedge accounting are prospectively marked-to-market, with
the
change in value recorded in each reporting period in the statement of
operations. If the original forecasted transactions are probable of not
occurring, any amounts previously recorded in other comprehensive income are
immediately recorded in the statement of operations. In fiscal 2005, the Company
recognized a pretax loss of $0.3 million against revenues in the statement
of
operations related to the
discontinuance
of oil cash flow hedges for which the forecasted transactions are probable
of
not occurring. In addition, cash flow hedge ineffectiveness can result from
differences in critical terms (such as location) between the hedging instrument
and the hedged transaction and result in the immediate recognition of gains
or
losses recorded in revenues. Hedge ineffectiveness pretax gains totaled $7.4
million in fiscal 2006 and were due primarily to the reversal of MTM
ineffectiveness recorded in previous years in the Oil and Gas Production
segment. Any actual ineffectiveness realized is reflected in revenue as an
offset to this gain. Hedge ineffectiveness pretax losses totaled $8.2 million
in
fiscal 2005 and were due primarily to unusually wide differentials between
NYMEX
prices and field prices in the Oil and Gas Production segment subsequent to
hurricanes Katrina and Rita.
The
following table summarizes selected information related to cash flow hedges
included in the Consolidated Statement of Operations and Balance Sheet through
September 30, 2006.
|
|
|
|
|
|
Interest
|
|
Partnership
|
||||||
|
(In
Thousands)
|
|
Commodities
|
|
Rate
|
Transactions
|
Total
|
|||||||
|
2006
|
|||||||||||||
|
Portion
of after-tax gains (losses) on hedging instruments
|
|||||||||||||
|
determined
to be ineffective and included in net income
|
$
|
4,481
|
$
|
-
|
N/A
|
$
|
4,481
|
||||||
|
Accumulated
other comprehensive income (loss) after tax at
|
|||||||||||||
|
September
30, 2006
|
$
|
(15,928
|
)
|
$
|
(431
|
)
|
$
|
(3,039
|
)
|
$
|
(19,398
|
)
|
|
|
Portion
of accumulated other comprehensive income (loss)
|
|||||||||||||
|
expected
to be reclassified to earnings during the next
|
|||||||||||||
|
12
months based on prices at September 30, 2006
|
$
|
(14,794
|
)
|
$
|
(65
|
)
|
N/A
|
$
|
(14,859
|
)
|
|||
|
Maximum
term
|
78
months
|
79
months
|
|||||||||||
|
2005
|
|||||||||||||
|
Portion
of after-tax gains (losses) on hedging instruments
|
|||||||||||||
|
determined
to be ineffective and included in net income
|
$
|
(4,967
|
)
|
$
|
-
|
N/A
|
$
|
(4,967
|
)
|
||||
|
After-tax
gains (losses) resulting from discontinuance of
|
|||||||||||||
|
cash
flow hedges
|
$
|
(196
|
)
|
$
|
-
|
$
|
-
|
$
|
(196
|
)
|
|||
|
Accumulated
other comprehensive income (loss) after tax at
|
|||||||||||||
|
September
30, 2005
|
$
|
(117,542
|
)
|
$
|
(497
|
)
|
$
|
(4,643
|
)
|
$
|
(122,682
|
)
|
|
|
2004
|
|||||||||||||
|
Portion
of after-tax gains (losses) on hedging instruments
|
|||||||||||||
|
determined
to be ineffective and included in net income
|
$
|
(987
|
)
|
$
|
-
|
N/A
|
$
|
(987
|
)
|
||||
|
Accumulated
other comprehensive income (loss) after tax at
|
|||||||||||||
|
September
30, 2004
|
$
|
(52,603
|
)
|
$
|
(562
|
)
|
$
|
(4,244
|
)
|
$
|
(57,409
|
)
|
|
Mark-to-Market
Derivative Instruments.
Peoples
Gas and North Shore Gas use derivative instruments to manage each utility's
cost
of gas supply and mitigate price volatility. All such derivative instruments
are
measured at fair value. The regulated utilities' tariffs allow for full recovery
from their customers of prudently incurred gas supply costs, including gains
or
losses on these derivative instruments. As a result, SFAS No. 71 allows for
these MTM derivative gains or losses to be recorded as regulatory assets or
regulatory liabilities. Realized gains or losses are recorded as an adjustment
to the cost of gas supply in the period that the underlying gas purchase
transaction takes place. The costs and benefits of this activity are passed
through to customers under the tariffs of Peoples Gas and North Shore
Gas.
Fair
Value Hedges.
The
Company uses financial hedges to protect the value of a portion of Energy
Marketing’s gas in storage and these are accounted for as fair value hedges. The
change in value of these hedges, along with the offsetting change in value
of
the inventory hedged (to the extent the hedge is effective), are recorded on
the
statement of operations in each reporting period's cost of energy sold.
The
Energy Marketing segment recorded in fiscal 2006 and 2005 $3.2 million and
$3.3
million in MTM losses, respectively, related to the application of fair value
hedge accounting to certain retail storage inventory
transactions.
The segment uses derivatives to mitigate commodity price risk and substantially
lock in the profit margin that it will ultimately realize when inventory volumes
are withdrawn from storage. Under fair value accounting, which this segment
is
using for certain storage activity, the MTM adjustment to inventory is computed
using spot prices, while the derivatives used to mitigate the risk of changes
in
inventory value are marked to market using forward prices. When the spot price
of natural gas changes disproportionately to the forward price, the difference
is recorded in operating results. As a result, earnings are subject to
volatility, even when the underlying expected profit margin over the duration
of
the contracts is unchanged. The volatility resulting from this accounting can
be
significant from period to period. This accounting loss will reverse next year
as the volumes are withdrawn from storage.
The
Company also uses certain financial instruments to adjust the portfolio
composition of its debt from fixed-rate to floating-rate debt. These derivative
instruments are accounted for as fair value hedges. The change in value of
these
hedges along with the offsetting change in value of the debt hedged (to the
extent the hedge is effective) are recorded in each reporting period in interest
expense in the statement of operations.
M.
Related Party Transactions
Peoples
Energy Corporation provides administrative services for its subsidiaries. These
services include purchasing, accounting, finance and treasury, tax, information
technology, auditing, insurance and pension administration, human resources
and
other miscellaneous services. Costs for these services amounted to $83.1
million, $69.0 million and $79.3 million in fiscal 2006, 2005 and 2004,
respectively. Specific and systematic cost allocation methodologies are used
to
allocate the costs and include such factors as payroll, number of employees,
space occupied and capital investment.
Peoples
Gas also provides certain billing, cash receipts processing, customer care,
gas
transportation and other services to North Shore Gas and bills for services
rendered. Peoples Gas billings to North Shore Gas were $6.6 million; $6.1
million and $6.7 million for fiscal years 2006, 2005 and 2004,
respectively.
Intercompany
receivables and payables at Peoples Gas and North Shore Gas at September 30,
2005 and 2004 primarily represent MTM gains on derivative instruments (see
Note
2L) executed by the Company on behalf of its utility subsidiaries. Intercompany
payables at Peoples Gas and North Shore Gas also relate to administrative
service provided by the Company.
For
the
fiscal years ended 2006, 2005 and 2004, Peoples Energy Resources sold natural
gas to Elwood for use at the Elwood power generation facility in the amounts
of
$20.4 million, $44.1 million and $13.7 million, respectively. Peoples Energy
Resources had $0.8 million and $9.4 million in accounts receivable from Elwood
at September 30, 2006 and 2005, respectively. These sales will cease in fiscal
2007 after the sale of Elwood (see Note 2B), however, the impact on income
from
continuing operations will not be material to the Company's consolidated
financial statements. At September 30, 2006, the Company had a 50% equity
interest in Elwood. (See Note 5.)
N.
Statement of Cash Flows
For
purposes of reporting cash flows, the Company considers all highly liquid
financial instruments with a maturity at the date of purchase of three months
or
less to be cash equivalents. Under the Company’s cash management practices,
checks issued pending clearance that result in overdraft balances for accounting
purposes are included in accounts payable and total $14.0 million and $9.1
million as of September 30, 2006 and 2005, respectively. For Peoples Gas, the
overdraft amounts in accounts payable at September 30, 2006 and 2005 were $8.0
million and $7.1 million, respectively. North Shore Gas’ overdraft amount in
accounts payable at September 30, 2006 and 2005, was zero and $0.4 million,
respectively.
Noncash
investing and financing activities in fiscal 2006 include the Company’s
recognition of conditional asset retirement obligations under FIN 47 and related
additional investments in property plant and equipment and regulatory assets.
(See Note 2H for a discussion of the impact of adoption of FIN 47 on the
Company, Peoples Gas and North Shore Gas.)
O.
Recent
Accounting Pronouncements
In
June
2006, the FASB issued FIN 48, which prescribes a recognition threshold and
measurement approach for the financial statement recognition and measurement
of
a tax position taken or expected to be taken in a tax return. Additionally,
FIN
48 provides guidance on the derecognition, classification, accounting in interim
periods and disclosure requirements for uncertain tax positions. The provisions
of FIN 48 are effective for fiscal years beginning after December 15, 2006,
with
the cumulative effect of the change in accounting principle recorded as an
adjustment to opening retained earnings. The Company is still evaluating whether
the requirements of FIN 48 will have a significant effect on its financial
condition or results of operations.
In
September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements.” SFAS
No. 157 defines fair value, establishes a framework for measuring fair value
in
generally accepted accounting principles, and expands disclosures about fair
value measurements. The provisions of this standard apply to other accounting
pronouncements that require or permit fair value measurements. This statement
is
effective for financial statements issued for fiscal years beginning after
November 15, 2007 and for interim periods within those fiscal years. The Company
is still evaluating whether the requirements of SFAS No. 157 will have a
significant effect on its financial condition or results of
operations.
In
September 2006, the FASB issued SFAS No. 158, which requires an employer to
recognize the overfunded or underfunded status of a defined benefit
postretirement plan (other than a multiemployer plan) as an asset or liability
in its statement of financial position and to recognize changes in that funded
status in the year in which the changes occur through comprehensive income.
This
Statement also requires an employer to measure the funded status of a plan
as of
the date of its year-end statement of financial position, with limited
exceptions. An employer with publicly traded equity securities is required
to
initially recognize the funded status of a defined benefit postretirement plan
and to provide the required disclosures as of the end of the fiscal year ending
after December 15, 2006. The Company expects that the requirements of SFAS
No.
158 may have a significant effect on its balance sheet (with a combined
reduction to accumulated other comprehensive income or increase in regulatory
assets estimated to be about $150 million based on current market and employee
data). The Company will also be required to move its measurement date from
June
30th to September 30th. As the actual impact of adopting SFAS No. 158 will
be
dependent upon the fair value of plan assets and the amount of projected benefit
obligations measured as of September 30, 2007, the above estimated amount may
not be reflective of the actual impact of the adoption.
In
September 2006, the SEC issued SAB No. 108, which provides interpretive guidance
on how the effects of the carryover or reversal of prior year misstatements
should be considered in evaluating whether current year financial
statements are materially misstated. The SEC staff believes that registrants
should quantify errors using both a balance sheet and an income statement
approach and evaluate whether either approach results in quantifying a
misstatement that, when all relevant quantitative and qualitative factors are
considered, is material. SAB No. 108 is effective as of the end of fiscal years
ending after November 15, 2006. The adoption of SAB No. 108 is not expected
to
have a material impact on the Company’s consolidated financial
statements.
P.
Contingencies, Indemnities and Commitments
Contingent
obligations, including indemnities, litigation and other possible commitments
are accounted for in accordance with SFAS No. 5, which requires that an
estimated loss be recorded if it is probable that an asset has been impaired
or
a liability has been incurred at the date of the financial statements and the
amount of the loss can be reasonably estimated. Accordingly, those contingencies
that are deemed to be probable and where the amount of loss is reasonably
estimable are accrued in the financial statements. If only a range of loss
can
be determined, the best estimate within that range is accrued; if none of the
estimates within that range is better than another, the low end of the range
is
accrued. Disclosure of a contingency is required if there is at least a
reasonable possibility that a loss has been or will be incurred, even if the
amount is not estimable. The assessment of contingencies is a highly subjective
process that requires judgments about future events. Contingencies are reviewed
at least quarterly to determine the adequacy of the accruals and related
financial statement disclosure. The ultimate settlement of contingencies may
differ materially from amounts accrued in the financial
statements.
Change
in Segment Reporting
Beginning
in fiscal 2006, the Company restructured the management and operations of
certain of its businesses and has realigned its segment reporting to match
these
changes. The financial data by business segment presented below has been
reclassified to conform with the new reportable segments. The Company's
reportable segments are Gas Distribution (including Peoples Gas hub operations,
formerly included as part of Midstream Services), Oil and Gas Production, Energy
Assets, Energy Marketing (both retail and wholesale activity, formerly included
as Retail Energy Services and part of Midstream Services, respectively), and
Corporate and Other.
Total
segment capital assets include net property, plant and equipment and certain
intangible assets classified in other investments. Financial data by business
segment is presented below.
|
Corporate
|
||||||||||||||||||||||
|
|
|
Gas
|
|
Oil
and Gas
|
Energy
|
Energy
|
and
|
|||||||||||||||
|
(In
Thousands)
|
|
Distribution
|
|
Production
|
Marketing
|
Assets
|
Other
|
Adjustments
|
Total
|
|||||||||||||
|
12
Months Ended September 30, 2006
|
||||||||||||||||||||||
|
Revenues
(1)
|
$
|
1,921,880
|
$
|
126,750
|
$
|
960,693
|
$
|
13,540
|
$
|
-
|
$
|
(4,893
|
)
|
$
|
3,017,970
|
|||||||
|
Cost
of energy sold
|
1,272,633
|
-
|
928,640
|
9,032
|
-
|
(5,992
|
)
|
2,204,313
|
||||||||||||||
|
Gas
charge settlement
|
107,330
|
-
|
-
|
-
|
-
|
-
|
107,330
|
|||||||||||||||
|
Operation
and maintenance, excluding merger,
|
||||||||||||||||||||||
|
gas
charge settlement and environmental costs
|
275,944
|
36,362
|
20,916
|
1,902
|
14,553
|
1,099
|
350,776
|
|||||||||||||||
|
Merger
costs
|
-
|
-
|
-
|
-
|
8,944
|
-
|
8,944
|
|||||||||||||||
|
Environmental
costs
|
33,654
|
-
|
-
|
-
|
-
|
-
|
33,654
|
|||||||||||||||
|
Depreciation,
depletion and amortization
|
62,574
|
52,479
|
1,606
|
356
|
1,388
|
-
|
118,403
|
|||||||||||||||
|
Taxes,
other than income taxes
|
183,329
|
14,553
|
560
|
119
|
2,357
|
-
|
200,918
|
|||||||||||||||
|
(Gains)
losses on property sales and impairments, net
|
(860
|
)
|
10
|
12
|
365
|
137
|
-
|
(336
|
)
|
|||||||||||||
|
Equity
investment income (2)
|
-
|
7,751
|
-
|
-
|
67
|
-
|
7,818
|
|||||||||||||||
|
Operating
income (loss)
|
$
|
(12,724
|
)
|
$
|
31,097
|
$
|
8,959
|
$
|
1,766
|
$
|
(27,312
|
)
|
$
|
-
|
$
|
1,786
|
||||||
|
Income
(loss) from discontinued operations, net of income taxes
|
$
|
-
|
$
|
-
|
$
|
-
|
$
|
10,324
|
$
|
(19
|
)
|
$
|
-
|
$
|
10,305
|
|||||||
|
Segment
capital assets of continuing operations, net (3)
|
$
|
1,637,198
|
$
|
532,742
|
$
|
3,596
|
$
|
5,176
|
$
|
8,127
|
$
|
-
|
$
|
2,186,839
|
||||||||
|
Investments
in equity investees (4)
|
$
|
-
|
$
|
-
|
$
|
-
|
$
|
250
|
$
|
-
|
$
|
-
|
$
|
250
|
||||||||
|
Capital
spending (5)
|
$
|
101,620
|
$
|
238,169
|
$
|
31
|
$
|
315
|
$
|
3,316
|
$
|
-
|
$
|
343,451
|
||||||||
|
12
Months Ended September 30, 2005
|
||||||||||||||||||||||
|
Revenues
(1)
|
$
|
1,688,674
|
$
|
100,602
|
$
|
805,515
|
$
|
9,482
|
$
|
-
|
$
|
(4,688
|
)
|
$
|
2,599,585
|
|||||||
|
Cost
of energy sold
|
1,034,376
|
-
|
773,565
|
4,480
|
-
|
(7,052
|
)
|
1,805,369
|
||||||||||||||
|
Operation
and maintenance, excluding
|
||||||||||||||||||||||
|
restructuring
and environmental costs
|
257,652
|
28,972
|
16,012
|
2,926
|
11,809
|
2,364
|
319,735
|
|||||||||||||||
|
Restructuring
costs
|
-
|
-
|
-
|
-
|
13,141
|
-
|
13,141
|
|||||||||||||||
|
Environmental
costs
|
30,437
|
-
|
-
|
-
|
-
|
-
|
30,437
|
|||||||||||||||
|
Depreciation,
depletion and amortization
|
61,894
|
45,764
|
1,797
|
485
|
948
|
-
|
110,888
|
|||||||||||||||
|
Taxes,
other than income taxes
|
169,072
|
12,399
|
648
|
139
|
1,948
|
-
|
184,206
|
|||||||||||||||
|
(Gains)
losses on property sales and impairments, net
|
(2,092
|
)
|
(983
|
)
|
22
|
(275
|
)
|
8
|
-
|
(3,320
|
)
|
|||||||||||
|
Equity
investment income (2)
|
-
|
2,403
|
-
|
-
|
7,885
|
-
|
10,288
|
|||||||||||||||
|
Operating
income (loss)
|
$
|
137,335
|
$
|
16,853
|
$
|
13,471
|
$
|
1,727
|
$
|
(19,969
|
)
|
$
|
-
|
$
|
149,417
|
|||||||
|
Income
(loss) from discontinued operations, net of income taxes
|
$
|
-
|
$
|
-
|
$
|
-
|
$
|
11,304
|
$
|
(19
|
)
|
$
|
-
|
$
|
11,285
|
|||||||
|
Segment
capital assets of continuing operations, net (3)
|
$
|
1,586,174
|
$
|
347,606
|
$
|
5,495
|
$
|
5,525
|
$
|
6,244
|
$
|
-
|
$
|
1,951,044
|
||||||||
|
Investments
in equity investees (4)
|
$
|
-
|
$
|
10,317
|
$
|
-
|
$
|
-
|
$
|
10,534
|
$
|
-
|
$
|
20,851
|
||||||||
|
Capital
spending (5)
|
$
|
82,836
|
$
|
74,155
|
$
|
148
|
$
|
956
|
$
|
2,827
|
$
|
-
|
$
|
160,922
|
||||||||
|
12
Months Ended September 30, 2004
|
||||||||||||||||||||||
|
Revenues
(1)
|
$
|
1,502,083
|
$
|
123,777
|
$
|
631,774
|
$
|
6,432
|
$
|
178
|
$
|
(4,045
|
)
|
$
|
2,260,199
|
|||||||
|
Cost
of energy sold
|
868,518
|
-
|
601,098
|
3,749
|
94
|
(5,682
|
)
|
1,467,777
|
||||||||||||||
|
Operation
and maintenance, excluding
|
||||||||||||||||||||||
|
restructuring
and environmental costs
|
253,233
|
28,846
|
17,201
|
861
|
21,219
|
1,637
|
322,997
|
|||||||||||||||
|
Restructuring
costs
|
-
|
-
|
-
|
-
|
17,000
|
-
|
17,000
|
|||||||||||||||
|
Environmental
costs
|
17,384
|
-
|
-
|
-
|
-
|
-
|
17,384
|
|||||||||||||||
|
Depreciation,
depletion and amortization
|
68,939
|
47,338
|
1,914
|
315
|
480
|
-
|
118,986
|
|||||||||||||||
|
Taxes,
other than income taxes
|
156,350
|
9,884
|
517
|
53
|
3,130
|
-
|
169,934
|
|||||||||||||||
|
(Gains)
losses on property sales and impairments, net
|
(3,499
|
)
|
(99
|
)
|
1,165
|
(121
|
)
|
7
|
-
|
(2,547
|
)
|
|||||||||||
|
Equity
investment income (2)
|
-
|
3,729
|
-
|
-
|
632
|
-
|
4,361
|
|||||||||||||||
|
Operating
income (loss)
|
$
|
141,158
|
$
|
41,537
|
$
|
9,879
|
$
|
1,575
|
$
|
(41,120
|
)
|
$
|
-
|
$
|
153,029
|
|||||||
|
Income
(loss) from discontinued operations, net of income taxes
|
$
|
-
|
$
|
-
|
$
|
-
|
$
|
6,841
|
$
|
(19
|
)
|
$
|
-
|
$
|
6,822
|
|||||||
|
Segment
capital assets of continuing operations, net (3)
|
$
|
1,571,966
|
$
|
319,099
|
$
|
7,227
|
$
|
5,718
|
$
|
4,374
|
$
|
-
|
$
|
1,908,384
|
||||||||
|
Investments
in equity investees (4)
|
$
|
-
|
$
|
19,150
|
$
|
-
|
$
|
-
|
$
|
3,674
|
$
|
-
|
$
|
22,824
|
||||||||
|
Capital
spending (5)
|
$
|
78,245
|
$
|
102,376
|
$
|
1,818
|
$
|
964
|
$
|
3,440
|
$
|
-
|
$
|
186,843
|
||||||||
| (1) |
Oil
and Gas Production revenues are net of gains and losses from
hedging
activities.
|
| (2) |
Excludes
equity investment income from discontinued operations. See
Note
5.
|
| (3) |
Excludes
segment assets of discontinued operations at September 30,
2006, 2005 and
2004 of $9,490, $12,209 and $10,783,
respectively.
|
| (4) |
Excludes
investments in equity investees of discontinued operations
at September
30, 2006, 2005 and 2004 of $74,071, $115,168 and $112,995,
respectively.
|
| (5) |
Excludes
capital spending relating to assets of discontinued operations
at
September 30, 2006, 2005 and 2004 of $566, $1,836 and
$2,546
respectively.
|
The
table
below reconciles the Company’s net capital investments reported on the
Consolidated Balance Sheets to segment totals:
|
|
For
Fiscal Years Ended September 30,
|
|||||||||
|
2006
|
2005
|
2004
|
||||||||
|
(In
Thousands)
|
||||||||||
|
Capital
investments
|
||||||||||
|
Segment
capital assets of
|
||||||||||
|
continuing
operations, net
|
$
|
2,186,839
|
$
|
1,951,044
|
$
|
1,908,384
|
||||
|
Investments
in equity investees
|
250
|
20,851
|
22,824
|
|||||||
|
Other
investments not included in
|
||||||||||
|
above
categories
|
8,577
|
9,135
|
7,966
|
|||||||
|
Total
capital investments—net
|
$
|
2,195,666
|
$
|
1,981,030
|
$
|
1,939,174
|
||||
During
the fourth quarter of fiscal 2004, the Company commenced a restructuring plan
to
enhance operating efficiency and customer service and to mitigate the impact
of
rising operating costs on utility customers, while maintaining solid financial
results for the Company. The restructuring activities were designed to result
in
a reduction of over 100 nonunion permanent positions at all levels in the
utility business and corporate support functions. An enhanced voluntary
termination severance package was offered to nonunion employees including a
termination allowance of three weeks' pay for each completed year of service
up
to a maximum of 52 weeks of pay, outplacement assistance, enhanced educational
assistance, and reduced Consolidated Omnibus Budget Reconciliation Act (COBRA)
rates. Approximately 300 employees accepted the package, resulting in about
200
open positions, some of which have been filled in fiscal 2005 and
2006.
The
restructuring activities were substantially completed by September 30, 2004.
The
restructuring plan resulted in aggregate costs of $17.0 million to the
Consolidated Statement of Operations for fiscal 2004. Included in this amount
were costs of $9.7 million and $0.9 million related to Peoples Gas and North
Shore Gas, respectively, based primarily upon severance payments and related
employer payroll taxes at each respective utility. The table below summarizes
the total Company charge by major type of cost.
|
(In
Thousands)
|
||
|
Severance
payments including payroll taxes
|
$15,490
|
|
|
Enhanced
educational and outplacement assistance
|
1,050
|
|
|
Medical
costs due to reduced COBRA rates
|
400
|
|
|
Legal
fees
|
60
|
|
|
Total
|
$17,000
|
A
total
of $16.6 million has been paid for severance payments, program expenses,
employer taxes and legal fees. Substantially all payments were made during
fiscal 2005, and no significant future payments are anticipated. In addition,
approximately $0.4 million in severance costs originally accrued were reversed
in connection with the revocation of severance agreements during fiscal
2005.
In
fiscal
2005, the Company recorded $13.1 million for pension settlements and
curtailments, net of capitalized amounts, associated with the restructuring
plan
described above (see Note 11). Included in this amount were charges of $8.8
million and $0.6 million for Peoples Gas and North Shore Gas, respectively.
As
the Company’s pension plan measurement year ends June 30, these restructuring
costs for settlements and curtailments subsequent to June 30, 2004 were required
to be recognized in fiscal 2005.
The
Company has several investments in the form of partnerships that are accounted
for as unconsolidated equity method investments. Individually, the Company's
equity investments do not meet the requirements for separate financial statement
disclosure. However, in aggregate these investments are material. The Company
records its share of equity investment income based on financial information
it
receives from the partnerships. All information is current or based on estimated
results for the quarter. The Company is not a managing partner in any of these
investments.
On
May
31, 2006 the Company completed the sale of its interest in the SCEP facility
and
recognized a pretax gain of $4.1 million. On September 20, 2006, the Company
announced that it signed an agreement with J-Power to sell its 50% interest
in
Elwood by December 2006. (See Note 2B.)
In
fiscal
2006 Peoples Energy Production, through its equity investment in EnerVest
Energy, L.P. (EnerVest), recognized a $7.8 million gain related to the sale
of
all remaining properties in the partnership.
The
partnership is in the process of winding up its affairs. Peoples Energy
Production has no remaining capital investment commitments with the EnerVest
partnership.
On
September 30, 2005, Trigen-Peoples District Energy Company (Trigen-Peoples),
a
50%-50% partnership between the Company and Trigen Energy Company (Trigen),
sold
its district heating and cooling plant. The Company liquidated its partnership
with Trigen effective with the sale of the plant.
The
following table summarizes the combined partnership financial results and
financial position of the Company’s unconsolidated equity method investments
(including investments reported by the Company as discontinued
operations).
|
For
Fiscal Years Ended
|
||||||||||
|
September
30,
|
||||||||||
|
(In
Thousands)
|
2006
|
2005
|
2004
|
|||||||
|
Revenues
|
$
|
103,212
|
$
|
212,774
|
$
|
175,284
|
||||
|
Operating
income
|
59,409
|
105,141
|
86,664
|
|||||||
|
Interest
expense
|
28,847
|
37,302
|
38,594
|
|||||||
|
Net
income
|
32,016
|
74,646
|
47,288
|
|||||||
|
Current
assets
|
58,643
|
107,927
|
72,103
|
|||||||
|
Noncurrent
assets
|
439,490
|
666,527
|
745,485
|
|||||||
|
Current
liabilities
|
29,647
|
57,923
|
47,962
|
|||||||
|
Noncurrent
liabilities
|
322,081
|
397,826
|
448,973
|
|||||||
The
following table summarizes the Company’s equity method investment ownership
percentage and its equity share of the net income shown in the previous
table.
Peoples
Gas provides natural gas service to approximately 815,000 customers within
Chicago. North Shore Gas provides natural gas service to about 156,000 customers
within approximately 275 square miles in northeastern Illinois. Credit risk
for
the utility companies is spread over a diversified base of residential,
commercial and industrial customers.
Peoples
Gas and North Shore Gas encourage customers to participate in their
long-standing budget payment programs, which allow 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.
Peoples
Energy Services, one of the Company’s Energy Marketing subsidiaries, sells
natural gas to approximately 37,100 commercial, industrial and residential
customers in northern Illinois, Michigan, Ohio, and New York. It also sells
electricity to approximately 3,400 commercial and industrial customers in
Illinois. Customers’ payment records are continually monitored and credit
deposits are required, when appropriate. Peoples Energy Wholesale Marketing,
also included in the Company’s Energy Marketing segment, buys and sells natural
gas through a variety of counterparties.
The
Company has ownership interests in one natural gas-fired power plant, Elwood
at
50%. Elwood’s plant capacity and output has been sold on a long-term basis to
two counterparties: Constellation and Exelon. This activity is included in
the
Energy Assets segment as discontinued operations.
In
August
2006, S&P and Moody’s ratings on Elwood’s bonds were upgraded to BB- and
Ba1, respectively, with a stable outlook.
As
of
September 30, 2006, Peoples Energy Production, the Company’s Oil and Gas
Production subsidiary, operated 394 wells with approximately 30% of the
production from these wells being sold to a single marketer, Cima Energy LLC.
In
addition, the Company owns nonoperated interests in 359 wells, which are managed
by 45 operators.
A.
Former Manufactured Gas Plant
The
Company's utility subsidiaries, their predecessors and certain former affiliates
operated facilities in the past at multiple sites for the purpose of
manufacturing gas and storing manufactured gas. In connection with manufacturing
and storing gas, waste materials were produced that may have resulted in soil
and groundwater contamination at these sites. Under certain laws and regulations
relating to the protection of the environment, the subsidiaries might be
required to undertake remedial action with respect to some of these materials.
The subsidiaries are addressing these sites under a program supervised by the
Illinois Environmental Protection Agency.
Peoples
Gas is addressing 29 manufactured gas sites, including several sites described
in more detail below. Investigations have been completed at all or portions
of
25 sites. Remediations have been completed at all or portions of nine of these
25 sites. Peoples Gas has determined that remediations are not required at
three
of these 25 sites.
North
Shore Gas is addressing five manufactured gas sites, including one site
described in more detail below. Investigations have been completed at all or
portions of four sites. Remediations have not yet been completed at any of
these
four sites. North Shore Gas has determined that remediation is not required
at
one of these four sites.
The
United States Environmental Protection Agency (EPA) has identified North Shore
Gas as a potentially responsible party (PRP) under the Comprehensive
Environmental Response, Compensation and Liability Act of 1980, as amended
(CERCLA), at the Waukegan Coke Plant Site located in Waukegan, Illinois
(Waukegan Site). The Waukegan Site is part of the Outboard Marine Corporation
(OMC) Superfund Site. The EPA also has identified OMC, General Motors
Corporation and certain other parties as PRPs at the Waukegan Site. The EPA
has
issued a record of decision (ROD) selecting the remedial action for the Waukegan
Site. The selected remedy consists of on-site treatment of groundwater and
off-site disposal of soil containing polynuclear aromatic hydrocarbons and
arsenic. North Shore Gas and the other PRPs have executed a remedial action
consent decree which has been entered by the federal district court. The consent
decree requires North Shore Gas and General Motors, jointly and severally,
to
perform the remedial action and establish and maintain financial assurance
of
$27 million. The soil component of the remedial action was completed in August
2005. The groundwater component of the remedial action is undergoing design
and
is expected to begin in 2007. The EPA has agreed to reduce the financial
assurance requirement to $21 million to reflect completion of the soil component
of the remedial action
.
In
2004,
the owners (River Village West) of a property in the vicinity of the former
Pitney Court Station filed suit against Peoples Gas in the United States
District Court for the Northern District of Illinois under the Resource
Conservation and Recovery Act (RCRA). The suit,
River
Village West LLC et al v. The Peoples Gas Light and Coke Company
,
No.
04-C-3392 (N.D. Ill. 2004), seeks an order directing Peoples Gas to remediate
the site. In December 2005, Peoples Gas and the plaintiffs settled and the
litigation has been dismissed with prejudice. Pursuant to the terms of the
settlement agreement, Peoples Gas has agreed to remediate the site and to
investigate and, if necessary, remediate sediments in the area of the Chicago
River adjacent to the site.
With
respect to portions of certain other sites in the City of Chicago (Chicago),
Peoples Gas has received demands from site owners and others asserting standing
regarding the investigation or remediation of their parcels. Some of these
demands seek to require Peoples Gas to perform extensive investigations or
remediations. These demands include notice letters sent to Peoples Gas by River
Village West. These letters informed Peoples Gas of River Village West's intent
to file suit under RCRA seeking an order directing Peoples Gas to remediate
seven
former manufactured gas plant sites located on or near the Chicago River. In
April 2005, River Village West filed suit against Peoples Gas in the United
States District Court for the Northern District of Illinois under RCRA. The
suit,
River
Village West LLC et al v. The Peoples Gas Light and Coke Company
,
No.
05-C-2103 (N.D. Ill. 2005), seeks an order directing Peoples Gas to remediate
three of the seven sites: the former South Station, the former Throop Street
Station and the former Hough Place Station. Peoples Gas is currently engaged
in
settlement discussions with River Village West.
In
August
2006, an individual filed suit against Peoples Gas in the United States District
Court for the Northern District of Illinois under RCRA. The suit,
Thomas
A. Snitzer v. The Peoples Gas Light and Coke Company
,
No.
06-C-4465 (N.D. Ill. 2006), seeks an order directing Peoples Gas to remediate
the Willow Street Station former manufactured gas plant site which is located
along the Chicago River. Peoples Gas has filed an answer and the court has
set a
scheduling order. In October 2006, the same individual filed another suit in
the
United States District Court for the Northern District of Illinois under RCRA
and CERCLA. The suit,
Thomas
A. Snitzer v. The Peoples Gas Light and Coke Company
,
No.
06-C-5901 (N.D. Ill. 2006), seeks an order directing Peoples Gas to remediate
the following four former manufactured gas plant sites, which are located on
or
near the Chicago River: 22
nd
Street
Station, Division Street Station, Hawthorne Station, and North Shore Avenue
Station. This individual has also notified Peoples Gas of his intent to file
suit under RCRA and CERCLA seeking an order directing Peoples Gas to remediate
the following two former manufactured gas plant sites: Calumet Station and
North
Station.
The
utility subsidiaries are accruing liabilities and deferring costs (recorded
as
regulatory assets) incurred in connection with all of the manufactured gas
sites, including related legal expenses, pending recovery through rates or
from
other entities. At September 30, 2006, regulatory assets (stated in current
year dollars) were recorded in the following amounts: for Peoples Gas, $244
million; for North Shore Gas, $69 million; and for the Company on a consolidated
basis, $313 million. Each of the foregoing amounts reflects the net amount
of
(1) costs incurred to date, (2) carrying costs, (3) amounts recovered from
insurance companies, other entities and customers, and (4) management's best
estimates of the costs the utilities will spend in the future for investigating
and remediating the manufactured gas sites. Management has recorded liabilities
for the amounts described in clause (4) of the preceding sentence as follows:
for Peoples Gas, $201 million; for North Shore Gas, $68 million; and for the
Company on a consolidated basis, $269 million. Management also estimates that
additional costs in excess of the recorded liabilities are reasonably possible
in the following amounts: for Peoples Gas, $113 million; for North Shore Gas,
$79 million; and for the Company on a consolidated basis, $192
million.
Management's
foregoing estimates are developed with the aid of probabilistic modeling. They
are based upon an ongoing review and judgment by management of potential costs
associated with conducting investigative and remedial actions at the
manufactured gas sites, and of the likelihood of incurring such costs. The
liabilities recorded reflect the costs of all activities estimated, as a result
of this analysis, to have a 75% or greater likelihood of occurrence. The
additional costs described above as reasonably possible reflect the difference
between the costs reflected in the liabilities for manufactured gas sites and
costs that would result from the use of a lower probability threshold determined
for each subsidiary by management after considering the sites included for
that
subsidiary. Because these estimates reflect future expenditures, they are
sensitive to changes in assumptions with respect to the probability and
magnitude of the various factors used in the modeling. The estimates are also
affected by changes that result from the Company's actual experience in
remediating the sites.
Actual
costs, which may differ materially from these estimates, will depend on several
factors including whether contamination exists at all sites, the nature and
extent of contamination and the level of remediation that may be required.
Other
factors that may affect such costs include, but are not limited to, changes
in
remediation technology, fluctuations in unit costs and changes in environmental
laws and regulations.
With
respect to certain sites or portions of sites, the subsidiaries have received
demands to investigate and remediate to extensive levels. Management does not
believe that the utility subsidiaries are legally required to comply with such
demands. However, if the subsidiaries were required to do so at all of the
sites
that have not been remediated, the Company currently estimates that its
aggregate maximum potential liability would be approximately $420 million higher
than the total of the recorded liabilities and estimates of additional
reasonably possible costs indicated above.
Each
subsidiary intends to seek contribution from other entities for the costs
incurred at the sites, but the full extent of such contributions cannot be
determined at this time.
Peoples
Gas and North Shore Gas are recovering the costs of environmental activities
relating to
the
utilities
'
former
manufactured gas operations, including carrying charges on the unrecovered
balances, under
rate
mechanisms approved by the
Illinois
Commerce Commission (Commission) which authorize recovery
of
prudently
incurred
costs.
Costs
incurred in each fiscal year are subject to a prudence review by the Commission
during a reconciliation proceeding for such fiscal year. Costs
are
expensed in the statement of operations in the same period they are billed
to
customers and recognized as revenues.
Management
believes that any costs incurred by Peoples Gas and North Shore Gas for
environmental activities relating to former manufactured gas operations that
are
not recoverable through contributions from other entities or from insurance
carriers have been prudently incurred and are therefore recoverable through
rates for utility service. Accordingly, management believes that the costs
incurred by the subsidiaries in connection with former manufactured gas
operations will not have a material adverse effect on the financial position
or
results of operations of the utilities. However, any changes in the utilities'
approved rate mechanisms
for
recovery of these costs, or any adverse conclusions
by the
Commission
with respect to the prudence
of
costs
actually
incurred
,
could
materially affect the utilities' recovery of such costs through
rates.
B.
Former Mineral Processing Site in Denver, Colorado
In
1994,
North Shore Gas 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 Shattuck's Denver site. Shattuck
is a wholly owned subsidiary of Salomon, Inc. (Salomon). The demand alleges
that
North Shore Gas 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.
In 1992, the EPA issued the ROD for the Denver site. The remedy selected in
the
ROD consisted of the on-site stabilization, solidification and capping of soils
containing radioactive wastes. In 1997, the remedial action was completed.
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 of the site.
North
Shore Gas filed a declaratory judgment action against Salomon in the U.S.
District Court for the Northern District of Illinois. The suit asked the court
to declare that North Shore Gas 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 North Shore Gas'
motion for summary judgment, declaring that North Shore Gas is not liable for
any response costs in connection with the Denver site.
In
1998,
the United States 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 North Shore Gas has, for activities
at
the site.
In
1999,
the EPA announced that it was reopening the ROD for the Denver site. The EPA's
announcement followed a six-month scientific/technical review by the agency
of
the remedy's effectiveness. In 2000, the EPA amended the ROD to require removal
of the radioactive wastes from the site to a licensed off-site disposal
facility. The EPA estimates that this action will cost an additional $22.0
million (representing the present worth of estimated capital costs and estimated
operation and maintenance costs).
In
December 2001, Shattuck entered into a proposed settlement agreement with the
United States and the State of Colorado regarding past and future response
costs
at the site. In August 2002, the agreement was approved by the District Court
for the District of Colorado. Under the terms of the agreement, Shattuck agreed
to pay, in addition to amounts already paid for response costs at the site,
approximately $7.2 million in exchange for a release from further obligations
at
the site. The release will not apply in the event that new information shows
that the remedy selected in the amended ROD is not protective of human health
or
the environment or if it becomes necessary to remediate contaminated groundwater
beneath or emanating from the site.
The
remediation of the site was completed in July 2006. According to U.S. EPA,
all
radioactive waste has been removed and the site has been deemed protective
of
human health and the environment.
North
Shore Gas does not believe that it has liability for the response costs, but
cannot determine the matter with certainty. At this time, North Shore Gas cannot
reasonably estimate what range of loss, if any, may occur. In the event that
North Shore Gas incurs liability, it would pursue reimbursement from insurance
carriers, other responsible parties, if any, and through its rates for utility
service.
C.
Other
The
Company has identified other sites on which the Company’s subsidiaries, their
predecessors and affiliates have conducted operations which may have resulted
in
releases of contaminants to the soil and groundwater. While the Company does
not
expect to be required to investigate or remediate these sites, it cannot
determine the matter with certainty. In the event that the Company incurs costs
in connection with the investigation or remediation of these sites, it would
seek reimbursement from other responsible parties, if any, and, if appropriate,
through the utilities’ rates for utility services.
A.
Illinois Commerce Commission Proceedings
For
each
utility subsidiary, the Commission conducts annual proceedings regarding the
reconciliation of revenues from the Gas Charge and related gas costs. In these
proceedings, the accuracy of the reconciliation of revenues and costs is
reviewed and the prudence of gas costs recovered through the Gas Charge is
examined by interested parties. If the Commission were to find that the
reconciliation was inaccurate or any gas costs were imprudently incurred, the
Commission would order the utility to refund the affected amount to customers
through subsequent Gas Charge filings. The proceedings are initiated shortly
after the close of the fiscal year and historically take at least a year to
18
months to complete.
The
Commission issued orders on March 28, 2006, approving a settlement that resolved
all proceedings regarding Peoples Gas and North Shore Gas for fiscal 2001 -
2004
costs. The recommendation that proceedings for Peoples Gas’ and North Shore Gas’
fiscal 2000 be reopened was made moot by approval of the settlement. The orders
adopted a January 17, 2006 Settlement Agreement and Release among and between
Peoples Energy, Peoples Gas, Peoples MW, LLC, Peoples Energy Resources Company,
LLC and North Shore Gas (collectively, the Peoples Companies), the People of
the
State of Illinois through Lisa Madigan, Illinois Attorney General (AG), the
Chicago and the Citizens Utility Board, as amended by an Amendment and Addendum
dated March 6, 2006 (the Agreement).
The
Agreement provides for the following:
| (i) |
Peoples
Gas and North Shore Gas agreed to refund the total sum of $100 million
to
their customers (the Refund). In its orders approving the Agreement,
the
Commission determined that $96 million should be refunded to customers
of
Peoples Gas and $4 million should be refunded to customers of North
Shore
Gas. Pursuant to the orders, on April 6, 2006, Peoples Gas and North
Shore
Gas filed informational statements with the Commission showing the
amount
of the refund to various customer classes. In April 2006, the refund
was
credited to customer accounts.
|
| (ii) |
Peoples
Energy agreed to pay to the City and the AG, jointly $5 million.
The
Company also agrees to pay up to $5 million per year over the next
five
years towards the funding of conservation and weatherization programs
for
low and moderate-income residential dwellings (Conservation Programs).
The
five subsequent payments of up to $5 million shall be paid based
upon
Conservation Programs to be developed by the City of Chicago and/or
the
Illinois Attorney General. The Conservation Programs will have the
purpose
of providing energy and natural gas conservation programs for residents
within Peoples Gas’ and North Shore Gas’
|
|
service
areas and will have the goal of reducing those residents’ energy usage and
costs. Peoples Gas and North Shore Gas will not seek recovery in
any
future rate or reconciliation cases of any amounts associated with
the
Conservation Programs.
|
| (iii) |
Peoples
Gas and North Shore Gas agreed to forgive all outstanding bad debt
from
fiscal years 2000-2005 existing as of March 6, 2006, estimated at
$207
million, remove the bad debt from customers’ records and to not use any
forgiven indebtedness as a reason to deny gas service. Peoples Gas
and
North Shore Gas have written off the estimated $207 million in prior
periods. The Agreement does not affect the ability of Peoples Gas
and
North Shore Gas to recover any future bad debts as specifically authorized
by the Commission now or in the future.
|
| (iv) |
Peoples
Gas and North Shore Gas will cooperate with Chicago and the AG to
identify
those customers of Peoples Gas and North Shore Gas who were not receiving
gas as of the date of the Agreement (approximately 12,000 customers)
that
are financial hardship cases. The hardship cases may be identified
by
either the utilities or the AG and Chicago. Following identification,
Peoples Gas and North Shore Gas will reconnect the hardship cases.
Peoples
Gas and North Shore Gas will also forgive all outstanding debt for
such
customers, as described in paragraph (iii) above.
|
| (v) |
Peoples
Gas and North Shore Gas agree to credit fiscal 2005 and fiscal 2006
revenues derived from the provision of gas Hub services as an offset
to
utility customers’ gas charges and to account for such revenues received
from gas Hub services in the same manner in all future gas charge
reconciliation cases. The fiscal 2006 revenues are being credited
in
fiscal 2006. The fiscal 2005 revenues are expected to be credited
to
customers following an order in the fiscal 2005 gas charge reconciliation
case. For fiscal 2005 and 2006, only Peoples Gas had Hub revenues.
|
| (vi) |
Peoples
Gas and North Shore Gas agreed to implement recommendations proposed
by
the Commission’s staff and the intervenors to conduct internal and
external audits of their gas procurement practices.
|
The
terms
of the Agreement expressly provide that nothing in the Agreement, or any acts
performed or documents executed in furtherance of the Agreement, shall
constitute or may be used as an admission of liability against Peoples Energy
or
its utility subsidiaries. The Commission’s orders effectively adopted the
provisions of the Agreement as a resolution on the merits of the differences
between the parties concerning the gas charge reconciliation matters related
to
the years 2000 through 2004 for Peoples Energy, Peoples Gas and North Shore
Gas
and also made other findings and conclusions.
See
Note
2C for a summary of significant accounting matters related to the
settlement.
Fiscal
2005 Gas Charge reconciliation cases were initiated in November 2005. Peoples
Gas and North Shore Gas each filed direct testimony. These cases were heard
and
continued to February 22, 2007. Commission Staff and Intervener Direct Testimony
is due January 18, 2007. The settlement of the prior fiscal years' Gas Charge
reconciliation proceedings does not affect these cases, except for Peoples
Gas'
agreement to credit fiscal 2005 Hub revenues as an offset to
utility
customers’ gas charges
.
B.
Class Action
In
February 2004, a purported class action was filed in Cook County Circuit Court
against the Company and Peoples Gas by Stephen Alport, a Peoples Gas customer,
alleging, among other things, violation of the Illinois Consumer Fraud and
Deceptive Business Practices Act related to matters at issue in Peoples Gas'
fiscal year 2001 gas charge reconciliation proceedings. The suit seeks
unspecified compensatory and punitive damages. The Company and Peoples Gas
deny
the allegations and are vigorously defending the suit. Peoples Gas has been
dismissed as a defendant and the only remaining counts of the suit allege
violations of the Consumer Fraud and Deceptive Business Practices Act and that
the Company acted in concert with others to commit a tortious act.
Based
upon the settlement and dismissal of Peoples Gas’ fiscal years 2001 through 2004
reconciliation cases by the ICC, the court on September 25, 2006 ruled to limit
the potential class members in the suit seeking damages to
those
persons who were customers during the time that Peoples Energy’s joint venture
with Enron was in operation and did not receive part of the settlement proceeds
from the reconciliation cases. The court also denied Peoples Gas’ motion to
dismiss the case to the extent that the complaint seeks punitive damages (which
could not have been obtained in the administrative reconciliation cases).
Plaintiffs have filed a third amended complaint and a motion for class
certification, to which the Company is in the process of responding. Management
cannot predict the outcome of this litigation and has not recorded a liability
associated with this contingency.
A.
Corrosion Control Inspection Proceeding
State
and
federal law requires gas utilities to conduct periodic corrosion control
inspections on natural gas pipelines. On April 19, 2006 the Commission initiated
a citation proceeding related to such inspections that were required to be
performed by Peoples Gas during 2003 and 2004, but which were not completed
in
the requisite timeframe.
On
November 3, 2006, Peoples Gas and all intervening parties filed a stipulation
to
settle the Commission proceeding, and the Commission Staff separately filed
in
support of the stipulation. Under the stipulation, Peoples Gas agreed that
it
was not in compliance with applicable regulations, and further agreed to pay
a
penalty of $1 million, pay for a consultant to conduct a comprehensive
investigation of its compliance with Commission pipeline safety regulations,
become compliant with those regulations, not seek recovery in future rate cases
of certain costs related to non-compliance and hold meetings with the City
of
Chicago to exchange information. If approved by the Commission, the stipulation
will resolve only the Commission proceeding and does not constitute a release
related to any civil or criminal laws. Peoples Gas has recorded a liability
of
$1 million associated with this settlement.
On
May
16, 2006, the Attorney General of the State of Illinois served a subpoena
requesting documents relating to Peoples Gas' corrosion inspections. Peoples
Gas' counsel has met with representatives of the Attorney General’s office and
are providing documents relating to the subpoena. Management cannot predict
the
outcome of this investigation and has not recorded a liability associated with
this contingency.
On
July
10, 2006, the U. S. Attorney for the Northern District of Illinois served a
grand jury subpoena on Peoples Gas requesting documents relating to Peoples
Gas'
corrosion inspections. Peoples Gas' counsel has met with the U.S. Attorney's
office and are providing documents relating to corrosion inspections.
Discussions between the U.S. Attorney and counsel for Peoples Gas are ongoing.
Management cannot predict the outcome of this investigation and has not recorded
a liability associated with this contingency.
B
.
Builders Class Action
In
June
2005, a purported class action was filed against the Company by Birchwood
Builders, LLC in the Circuit Court of Cook County, Illinois alleging that
Peoples Gas and North Shore Gas were fraudulently and improperly charging fees
to customers with respect to utility connections, disconnections, reconnections,
relocations, extensions of gas service pipes and extensions of distribution
gas
mains and failing to return related customer deposits. The parties are
attempting to resolve this matter through mediation. The Company, Peoples Gas
and North Shore Gas also have filed two currently pending motions to dismiss
the
lawsuit. The Company and the utility subsidiaries believe
they
have meritorious defenses and intend to vigorously defend against the class
action lawsuit. Management cannot predict the outcome of this litigation and
has
not recorded a liability associated with this contingency.
10:
OTHER COMMITMENTS AND CONTINGENCIES
A.
Guarantees and Letters of Credit
As
of
September 30, 2006, the Company had issued approximately $34.6 million of
guarantees related to its unconsolidated equity investments as presented in
the
table below. In addition, the Company has authorized the issuance of standby
letters of credit by financial institutions in the amount of $6.7 million as
of
September 30,
2006.
Surety bonds totaling $1.6 million were issued by the Company as of September
30, 2006. The Company enters into these arrangements to secure financing and
facilitate commercial transactions by its investees and subsidiaries with third
parties. The Company is not required to record liabilities associated with
these
obligations in the Consolidated Financial Statements. No such liabilities have
been recognized as of September 30, 2006.
|
Unconsolidated
Equity
Investee
|
Nature
of Guarantee
|
Amount
(In
millions)
|
Expected
Expiration
Date
|
|
Elwood
|
Operational
|
$
20.9
|
August
31, 2017
|
|
Elwood
|
Debt
service
|
13.7
(1)
|
July
5, 2026
|
|
Total
|
$
34.6
|
| (1) |
Based
on the amount of the next semi-annual debt service payment as of
September
30, 2006. The amount of guarantee varies throughout the life of the
loan,
but cannot exceed $16.5 million.
|
The
Company's equity interests in Elwood have also been pledged as collateral for
the benefit of Elwood's bondholders.
At
September 30, 2006, Peoples Gas and North Shore Gas had no material letters
of
credit or surety bonds and no outstanding guarantees.
B.
Purchase Commitments
Peoples
Gas and North Shore Gas have purchase commitments for gas purchase, storage
and
transportation as well as materials, supplies, services and property, plant
and
equipment as part of the normal course of business. Certain contracts contain
penalty provisions for early termination. The Company does not expect potential
payments under these provisions to materially affect results of operations
or
its financial condition in any individual year. Purchase obligations are
summarized below in Note 10D.
C.
Operating Leases
The
Company and subsidiaries lease office space under agreements that expire in
various years through 2016. During fiscal 2003, the Company extended the lease
for its headquarters for an additional five years to August 31, 2014. The rental
obligations consist of a base rent plus operating expenses and taxes. Rental
expenses for the Company under operating leases were $8.3 million, $8.6 million
and $8.7 million for fiscal years 2006, 2005 and 2004, respectively. Rental
expenses for Peoples Gas under operating leases were $2.6 million, $2.6 million
and $3.6 million for fiscal years 2006, 2005 and 2004, respectively. Rental
expenses for North Shore Gas under operating leases were insignificant. The
minimum rental commitments payable in future years under all noncancelable
leases for the Company and Peoples Gas are summarized below in Note
10D.
D.
Contractual Obligations
The
following table summarizes Peoples Energy’s, Peoples Gas’ and North Shore Gas’
minimum contractual cash obligations as of September 30, 2006.
|
Payments
Due by Period
|
||||||||||||||||
|
(In
Millions)
|
Less
than
|
1
to 3
|
4
to 5
|
More
than
|
||||||||||||
|
Peoples
Energy (consolidated)
|
Total
|
1
Year
|
Years
|
Years
|
5
Years
|
|||||||||||
|
Total
debt (See Note 14)
|
$
|
1,204.4
|
$
|
309.7
|
$
|
-
|
$
|
373.5
|
$
|
521.2
|
||||||
|
Estimated
interest payments on debt (1)
|
631.5
|
46.7
|
93.4
|
79.3
|
412.1
|
|||||||||||
|
Operating
leases (See Note 10C)
|
35.2
|
3.9
|
8.2
|
8.6
|
14.5
|
|||||||||||
|
Purchase
obligations (2)
|
1,108.8
|
471.9
|
407.1
|
96.9
|
132.9
|
|||||||||||
|
Minimum
pension funding (3) (See Note 11)
|
92.8
|
-
|
26.1
|
33.3
|
33.4
|
|||||||||||
|
Total
contractual cash obligations
|
$
|
3,072.7
|
$
|
832.2
|
$
|
534.8
|
$
|
591.6
|
$
|
1,114.1
|
||||||
|
Peoples
Gas
|
||||||||||||||||
|
Total
debt (See Note 14)
|
$
|
502.0
|
$
|
-
|
$
|
-
|
$
|
50.0
|
$
|
452.0
|
||||||
|
Estimated
interest payments on debt (1)
|
485.9
|
21.2
|
42.5
|
39.5
|
382.7
|
|||||||||||
|
Operating
leases (See Note 10C)
|
26.3
|
3.2
|
6.5
|
6.9
|
9.7
|
|||||||||||
|
Purchase
obligations (2)
|
353.0
|
76.4
|
109.9
|
68.0
|
98.7
|
|||||||||||
|
Total
contractual cash obligations
|
$
|
1,367.2
|
$
|
100.8
|
$
|
158.9
|
$
|
164.4
|
$
|
943.1
|
||||||
|
North
Shore Gas
|
||||||||||||||||
|
Total
debt (See Note 14)
|
$
|
69.3
|
$
|
-
|
$
|
-
|
$
|
-
|
$
|
69.3
|
||||||
|
Estimated
interest payments on debt (1)
|
45.8
|
3.3
|
6.6
|
6.6
|
29.3
|
|||||||||||
|
Operating
leases (See Note 10C)
|
-
|
-
|
-
|
-
|
-
|
|||||||||||
|
Purchase
obligations (2)
|
79.2
|
17.7
|
28.6
|
9.9
|
23.0
|
|||||||||||
|
Total
contractual cash obligations
|
$
|
194.3
|
$
|
21.0
|
$
|
35.2
|
$
|
16.5
|
$
|
121.6
|
||||||
| (1) |
Includes
interest on fixed and adjustable rate debt. The adjustable rate interest
is calculated based on the indexed rate in effect at September 30,
2006.
|
| (2) |
Includes
gas purchases, storage, transportation, information technology-related
and
miscellaneous long-term and short-term capital purchase
commitments.
|
| (3) |
Minimum
pension funding is an estimate of the contributions that would be
required
pursuant to the Employee Retirement Income Security Act to fund benefits
earned as of October 1, 2006. Additional contributions may be made
to fund
benefits accruing after October 1, 2006, or on a discretionary
basis.
|
11:
RETIREMENT AND POSTRETIREMENT BENEFITS
The
Company and its subsidiaries participate in two noncontributory defined benefit
pension plans, the Retirement Plan and the Service Annuity System, 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. Employees who began
participation in the Retirement Plan July 1, 2001, and thereafter will have
their benefits determined based on their compensation during the five years
preceding termination of employment and an aged-based percentage credited to
them for each year of their participation. The Company and its subsidiaries
make
contributions to the plans based upon actuarial determinations and in
consideration of tax regulations and funding requirements under federal law.
The
Company also has a non-qualified pension plan (Supplemental Plan) that provides
certain employees with pension benefits in excess of qualified plan limits
imposed by federal tax law. Effective October 1, 2004, the Company began
including amounts related to executive deferred compensation (EDC) in the
calculation of supplemental pension expense. Retiring employees have the option
of receiving retirement benefits in the form of an annuity or a lump sum
payment.
The
Company follows SFAS No. 88 to account for unrecognized gains and losses related
to the settlement of its pension plans' Projected Benefit Obligations (PBO).
During fiscal 2006, as in past fiscal periods, a portion of each plans' PBO
was
settled by the payment of lump sum benefits, resulting in a settlement cost
under SFAS No. 88 for the Retirement Plan, Service Annuity System and
Supplemental Plan.
In
addition, the Company and its subsidiaries currently provide certain
contributory 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. These plans, like
the
pension plans, are funded based upon actuarial determinations, consideration
of
tax regulations and the Company's funding policy. The Company accrues the
expected costs of such benefits over the service lives of employees who meet
the
eligibility requirements of the plan.
A.
Benefit Obligations
|
Other
Postretirement
|
|||||||||||||
|
Pension
Benefits
|
Benefits
|
||||||||||||
|
Fiscal
Years Ended September 30
|
2006
|
2005
|
2006
|
2005
|
|||||||||
|
(In
Millions)
|
|||||||||||||
|
Change
in benefit obligation
|
|||||||||||||
|
Benefit
obligation at beginning of measurement period
|
$
|
508.6
|
$
|
458.3
|
$
|
133.1
|
$
|
147.1
|
|||||
|
Service
cost
|
21.0
|
15.9
|
7.1
|
6.1
|
|||||||||
|
Interest
cost
|
25.5
|
27.2
|
6.4
|
7.9
|
|||||||||
|
Participant
contributions
|
-
|
-
|
6.8
|
5.9
|
|||||||||
|
Curtailment
|
-
|
(1.6
|
)
|
-
|
(0.6
|
)
|
|||||||
|
Plan
amendments
|
-
|
-
|
-
|
(7.3
|
)
|
||||||||
|
Actuarial
(gain)/loss
|
(69.7
|
)
|
88.5
|
(7.5
|
)
|
(11.3
|
)
|
||||||
|
Benefits
paid
|
(46.5
|
)
|
(79.7
|
)
|
(15.8
|
)
|
(14.7
|
)
|
|||||
|
Benefit
obligation at end of measurement period (June 30)
|
$
|
438.9
|
$
|
508.6
|
$
|
130.1
|
$
|
133.1
|
|||||
|
Accumulated
benefit obligation at end of measurement period (June 30)
|
$
|
361.1
|
$
|
402.6
|
|||||||||
B.
Plan Assets
|
Other
Postretirement
|
|||||||||||||
|
Pension
Benefits
|
Benefits
|
||||||||||||
|
Fiscal
Years Ended September 30
|
2006
|
2005
|
2006
|
2005
|
|||||||||
|
(In
Millions)
|
|||||||||||||
|
Change
in plan assets
|
|||||||||||||
|
Fair
value of plan assets at beginning of measurement period
|
$
|
480.6
|
$
|
495.1
|
$
|
39.8
|
$
|
46.9
|
|||||
|
Actual
return on plan assets
|
38.1
|
33.3
|
1.1
|
1.7
|
|||||||||
|
Employer
contributions (including non-qualified plans)
|
23.2
|
31.9
|
0.2
|
-
|
|||||||||
|
Participant
contributions
|
-
|
-
|
6.8
|
5.9
|
|||||||||
|
Benefits
paid
|
(46.5
|
)
|
(79.7
|
)
|
(15.8
|
)
|
(14.7
|
)
|
|||||
|
Fair
value of plan assets at end of measurement
period
(June 30)
|
$
|
495.4
|
$
|
480.6
|
$
|
32.1
|
$
|
39.8
|
|||||
The
asset
allocation, by asset class, for the Company’s pension and other postretirement
benefit plans at the June 30 measurement date are as follows:
|
Target
|
Percentage
of Plan Assets
|
|||||
|
Allocation
|
at
June 30,
|
|||||
|
2006
|
2006
|
2005
|
||||
|
Pension
Benefits:
|
||||||
|
Equity
securities
|
70%
|
69%
|
69%
|
|||
|
Debt
securities
|
30%
|
30%
|
30%
|
|||
|
Other
|
0%
|
1%
|
1%
|
|||
|
Total
|
100%
|
100%
|
100%
|
|||
|
Other
Postretirement Benefits:
|
||||||
|
Equity
securities
|
60%
|
57%
|
58%
|
|||
|
Debt
securities
|
40%
|
38%
|
40%
|
|||
|
Other
|
0%
|
5%
|
2%
|
|||
|
Total
|
100%
|
100%
|
100%
|
|||
The
target asset allocation reflects the Company’s investment strategy of maximizing
the long-term rate of return on plan assets within an appropriate level of
risk.
Plan assets are rebalanced from time to time if the actual allocation deviates
from the target by more than allowable limits as defined under the Company's
investment policy.
C.
Funded Status
The
funded status of the plans, reconciled to the amount reported on the statement
of financial position, is as follows:
|
Other
Postretirement
|
|||||||||||||
|
Pension
Benefits
|
Benefits
|
||||||||||||
|
Fiscal
Years Ended September 30
|
2006
|
2005
|
2006
|
2005
|
|||||||||
|
(In
Millions)
|
|||||||||||||
|
Funded
status
|
|||||||||||||
|
Fair
value of plan assets
|
$
|
495.4
|
$
|
480.6
|
$
|
32.1
|
$
|
39.8
|
|||||
|
Benefit
obligations
|
438.9
|
508.6
|
130.1
|
133.1
|
|||||||||
|
Over
(under) funded status
|
56.5
|
(28.0
|
)
|
(98.0
|
)
|
(93.3
|
)
|
||||||
|
Unrecognized
net transition obligation (asset)
|
-
|
(0.1
|
)
|
8.6
|
9.8
|
||||||||
|
Unrecognized
prior service cost
|
32.8
|
35.4
|
-
|
-
|
|||||||||
|
Unrecognized
net actuarial (gain)/loss
|
85.0
|
167.1
|
21.6
|
28.4
|
|||||||||
|
Adjustment
for Medicare Part D receivable
|
-
|
-
|
(0.7
|
)
|
-
|
||||||||
|
Recognized
prepaid (accrued) benefit cost at September 30
|
$
|
174.3
|
$
|
174.4
|
$
|
(68.5
|
)
|
$
|
(55.1
|
)
|
|||
|
Amounts
recognized in the statement of financial
|
|||||||||||||
|
position
consist of:
|
|||||||||||||
|
Prepaid
pension cost
|
$
|
182.3
|
$
|
152.7
|
$
|
-
|
$
|
-
|
|||||
|
Accrued
benefit liability
|
(8.0
|
)
|
(42.6
|
)
|
(68.5
|
)
|
(55.1
|
)
|
|||||
|
Intangible
asset
|
-
|
21.5
|
-
|
-
|
|||||||||
|
Accumulated
other comprehensive income, pretax
|
-
|
42.8
|
-
|
-
|
|||||||||
|
Net
amount recognized
|
$
|
174.3
|
$
|
174.4
|
$
|
(68.5
|
)
|
$
|
(55.1
|
)
|
|||
The
Company’s Retirement Plan and Supplemental Plan had accumulated benefit
obligations in excess of (less than) plan assets as of June 30, 2006 and 2005,
as follows:
|
Retirement
Plan
|
Supplemental
Plan
|
||||||||||||
|
(In
Millions)
|
2006
|
2005
|
2006
|
2005
|
|||||||||
|
Benefit
obligation
|
$
|
211.4
|
$
|
270.0
|
$
|
7.1
|
$
|
6.9
|
|||||
|
Accumulated
benefit obligation (ABO)
|
$
|
173.7
|
$
|
223.3
|
$
|
6.2
|
$
|
6.2
|
|||||
|
Fair
value of plan assets
|
195.6
|
188.6
|
-
|
-
|
|||||||||
|
ABO
in excess of (less than) plan assets
|
$
|
(21.9
|
)
|
$
|
34.7
|
$
|
6.2
|
$
|
6.2
|
||||
Pretax
amounts included in other comprehensive income arising from a change in the
minimum liability are as follows:
|
Pension
Benefits
|
Other
Postretirement
Benefits
|
|||||||
|
Fiscal
years ended September 30,
|
2006
|
2005
|
2006
|
2005
|
||||
|
(In
Millions)
|
||||||||
|
Change
in minimum liability included
|
||||||||
|
in other comprehensive income as a loss (gain)
|
$(42.8)
|
$29.7
|
N/A
|
N/A
|
||||
D.
Expected Cash Flow
Information
about the expected cash flows for the pension and other postretirement benefit
plans follows:
|
(In
Millions)
|
Pension
Benefits
|
Other
Postretirement Benefits
|
|
|
Employer
contributions:
|
|||
|
2007
(expected)
|
$
3.7
|
$
-
|
|
|
|
|||
|
Expected
benefit payments:
|
|||
|
2007
|
$
35.5
|
$
8.5
|
|
|
2008
|
31.5
|
|
8.7
|
|
2009
|
34.3
|
9.0
|
|
|
2010
|
34.7
|
9.2
|
|
|
2011
|
42.0
|
9.8
|
|
|
Years
2012-2016
|
259.3
|
58.9
|
The
above
table reflects the total benefits expected to be paid from the plan or from
Company assets and does not include the participants’ share of the cost. The
above expected benefit payments for other postretirement benefits include
payments for prescription drug benefits and are net of the following expected
Medicare Part D subsidy receipts:
|
(In
Millions)
|
2007
|
2008
|
2009
|
2010
|
2011
|
2012-2016
|
|
Other
postretirement benefits
|
$0.8
|
$0.9
|
$0.9
|
$1.0
|
$1.0
|
$5.8
|
E.
Net Benefit Cost
|
Pension
Benefits
|
Other
Postretirement Benefits
|
||||||||||||||||||
|
Fiscal
Years Ended September 30
|
2006
|
2005
|
2004
|
2006
|
2005
|
2004
|
|||||||||||||
|
(In
Millions)
|
|||||||||||||||||||
|
Service
cost
|
$
|
21.0
|
$
|
15.9
|
$
|
17.8
|
$
|
7.1
|
$
|
6.1
|
$
|
5.3
|
|||||||
|
Interest
cost
|
25.5
|
27.2
|
27.7
|
6.4
|
7.9
|
7.3
|
|||||||||||||
|
Expected
return on plan assets
|
(40.8
|
)
|
(43.0
|
)
|
(46.6
|
)
|
(2.9
|
)
|
(3.3
|
)
|
(3.8
|
)
|
|||||||
|
Amortization
of:
|
|||||||||||||||||||
|
Net
transition (asset)/obligation
|
(0.1
|
)
|
(0.8
|
)
|
(1.1
|
)
|
1.2
|
1.8
|
1.9
|
||||||||||
|
Prior
service cost
|
2.6
|
2.7
|
3.0
|
-
|
-
|
-
|
|||||||||||||
|
Net
actuarial (gain)/loss
|
6.1
|
2.0
|
1.6
|
1.1
|
1.4
|
0.9
|
|||||||||||||
|
Net
periodic benefit cost
|
14.3
|
4.0
|
2.4
|
12.9
|
13.9
|
11.6
|
|||||||||||||
|
Curtailment
recognition
|
-
|
5.1
|
-
|
-
|
0.4
|
-
|
|||||||||||||
|
Contribution
shortfall recognition
|
-
|
-
|
-
|
-
|
-
|
0.7
|
|||||||||||||
|
One-time
recognition for EDC
|
-
|
2.2
|
-
|
-
|
-
|
-
|
|||||||||||||
|
Effects
of lump sum settlements upon retirement
|
9.0
|
15.5
|
9.4
|
-
|
-
|
-
|
|||||||||||||
|
Net
benefit cost
|
$
|
23.3
|
$
|
26.8
|
$
|
11.8
|
$
|
12.9
|
$
|
14.3
|
$
|
12.3
|
|||||||
|
Net
benefit cost by company
|
|||||||||||||||||||
|
Peoples
Gas
|
$
|
11.5
|
$
|
12.6
|
$
|
3.0
|
$
|
10.0
|
$
|
11.3
|
$
|
10.0
|
|||||||
|
North
Shore Gas
|
3.4
|
3.8
|
2.8
|
1.4
|
1.4
|
1.2
|
|||||||||||||
|
All
other companies
|
8.4
|
10.4
|
6.0
|
1.5
|
1.6
|
1.1
|
|||||||||||||
|
$
|
23.3
|
$
|
26.8
|
$
|
11.8
|
$
|
12.9
|
$
|
14.3
|
$
|
12.3
|
||||||||
In
fiscal
2005 the Company recorded a combined $15.9 million noncash expense (before
capitalization) for pension and other postretirement benefits associated with
the restructuring described in Note 4. The $15.9 million included approximately
$10.4 million related to effects of lump sum settlements and $5.5 million
related to curtailment charges. In addition, remeasurement of the pension plan’s
liabilities and assets when the plan curtailment was recognized during the
first
quarter of fiscal 2005 resulted in an increase of $22.6 million in the minimum
liability recognized in other comprehensive income.
On
December 8, 2003, the Medicare Prescription Drug, Improvement and Modernization
Act of 2003 (the Act) was signed into law. The Act introduces a prescription
drug benefit under Medicare (Medicare Part D) as well as a federal subsidy
to
sponsors of retiree health care benefit plans that provide a benefit that is
at
least actuarially equivalent to Medicare Part D.
FSP
No.
106-2 provides accounting guidance to employers that have determined that
prescription drug benefits available under their retiree health care benefit
plans are at least actuarially equivalent to Medicare Part D. The FSP requires
that the benefit attributable to past service be accounted for as an actuarial
gain and the benefit related to current service be reported as a reduction
in
service cost.
Detailed
regulations needed to implement the Act were issued in January of 2005 and
the
Company determined that the benefits provided by its retiree health care benefit
plans are at least actuarially equivalent to Medicare Part D and qualify for
the
federal subsidy. The impact of the Act on the Company's postretirement benefit
plan was considered a significant event and a remeasurement of plan assets
and
obligations was performed as of February 28, 2005. The impact of the Act reduced
accumulated postretirement benefit obligation by $37.9 million related to
benefits
attributed to past service. The reduction in the components of net periodic
benefit cost for 2006 and 2005 was as follows:
|
(In
millions)
|
2006
|
2005
|
|||||
|
Service
Cost
|
$
|
1.8
|
$
|
0.5
|
|||
|
Interest
Cost
|
2.0
|
0.7
|
|||||
|
Amortization
of actuarial gain
|
2.5
|
0.6
|
|||||
|
Total
reduction in net periodic benefit cost
|
$
|
6.3
|
$
|
1.8
|
F.
Primary Actuarial Assumptions
|
Pension
Benefits
|
Other
Postretirement
Benefits
|
|||||||
|
2006
|
2005
|
2006
|
2005
|
|||||
|
Weighted-average
assumptions used to determine benefit obligations, June
30:
|
||||||||
|
Discount
rate
|
6.50%
|
5.25%
|
6.25%
|
5.00%
|
||||
|
Future
compensation increases
|
3.75%
|
3.75%
|
||||||
|
Health
care cost trend rate assumed for next year
|
8.00%
|
9.00%
|
||||||
|
Rate
to which the cost trend rate is assumed
to
decline (the ultimate rate)
|
5.00%
|
5.00%
|
||||||
|
Year
that the rate reaches the ultimate trend rate
|
2010
|
2010
|
||||||
|
Pension
Benefits
|
Other
Postretirement Benefits
|
|||||||||||
|
2006
|
2005
|
2004
|
2006
|
2005
|
2004
|
|||||||
|
Weighted-average
assumptions used to determine
net
periodic benefit cost:
|
||||||||||||
|
Discount
rate
|
5.25%
|
6.13%
|
6.00%
|
5.00%
|
6.02%
|
6.00%
|
||||||
|
Expected
return on assets
|
8.75%
|
8.75%
|
8.75%
|
8.75%
|
8.75%
|
8.75%
|
||||||
|
Future
compensation increases
|
3.75%
|
3.75%
|
3.75%
|
|||||||||
|
Health
care cost trend rate assumed for
next
year
|
9.00%
|
10.00%
|
8.00%
|
|||||||||
|
Rate
to which the cost trend rate is
assumed
to
decline
(the ultimate rate)
|
5.00%
|
5.00%
|
5.00%
|
|||||||||
|
Year
that the rate reaches the ultimate
trend
rate
|
2010
|
2010
|
2007
|
|||||||||
The
Company utilized the assistance of its plan actuaries in determining the
discount rate assumption. The Company’s actuaries have developed an interest
rate yield curve to enable companies to make judgments pursuant to EITF Topic
No. D-36, “Selection of Discount Rates Used for Measuring Defined Benefit
Pension Obligations and Obligations of Post Retirement Benefit Plans Other
Than
Pensions.” The yield curve is comprised of Aaa and Aa bonds with maturities
between zero and thirty years. The plan actuaries then discount the expected
annual benefit cash flows for each of the Company’s pension and retiree welfare
plans using this yield curve and develop a single-point discount rate matching
each plan’s expected payout structure.
The
Company establishes its expected return on asset assumption based on
consideration of historical and projected asset class returns. For each asset
class, the expected return is calculated as the weighted-average of the
historical and projected returns, as determined by an independent source. This
amount is then compared to the historical investment performance of the Trust
as
well as a group of peer companies for reasonableness.
Assumed
health care cost trend rates have a significant effect on the amounts reported
for the health care plans. For fiscal 2006 a one-percentage-point change in
the
assumed health care cost trend rates would have the following
effects:
|
1-Percentage-Point
|
|||||||
|
(In
Millions)
|
Increase
|
Decrease
|
|||||
|
Effect
on total of service and interest cost
|
$
|
2.1
|
$
|
(1.7
|
)
|
||
|
Effect
on postretirement benefit obligation
|
$
|
12.9
|
$
|
(11.2
|
)
|
||
G.
Defined Contribution Plans
In
addition to the defined benefit pension plans, the Company has defined
contribution plans that allow eligible employees to contribute a portion of
their income in accordance with specified guidelines. The Company matches a
percentage of the employee contribution up to certain limits. The cost of the
Company’s matching contribution to the plans totaled $3.7 million, $3.6 million
and $4.0 million in fiscal 2006, 2005 and 2004, respectively.
12:
TAX MATTERS
A.
Income Tax Expense
Total
income tax expense (benefit) as shown for the Company on the Consolidated
Statements of Operations is composed of the following:
|
For
Fiscal Years Ended September 30,
|
||||||||||
|
2006
|
2005
|
2004
|
||||||||
|
(In
Thousands)
|
||||||||||
|
Current:
|
||||||||||
|
Federal
|
$
|
8,594
|
$
|
18,579
|
$
|
21,051
|
||||
|
State
|
(3,167
|
)
|
1,112
|
(1,216
|
)
|
|||||
|
Total
current income taxes
|
5,427
|
19,691
|
19,835
|
|||||||
|
Deferred:
|
||||||||||
|
Federal
|
(23,441
|
)
|
16,529
|
13,086
|
||||||
|
State
|
(5,093
|
)
|
1,653
|
1,531
|
||||||
|
Total
deferred income taxes
|
(28,534
|
)
|
18,182
|
14,617
|
||||||
|
Investment
tax credits—net:
|
||||||||||
|
Federal
amortization
|
(708
|
)
|
(712
|
)
|
(903
|
)
|
||||
|
State
ITC provision
|
471
|
286
|
-
|
|||||||
|
State
ITC amortization
|
(204
|
)
|
(187
|
)
|
(216
|
)
|
||||
|
Total
investment tax credits—net
|
(441
|
)
|
(613
|
)
|
(1,119
|
)
|
||||
|
Net
income tax expense (benefit)
|
||||||||||
|
from
continuing operations
|
(23,548
|
)
|
37,260
|
33,333
|
||||||
|
Income
tax expense from discontinued operations
|
6,797
|
7,444
|
4,500
|
|||||||
|
Net
income tax expense (benefit)
|
$
|
(16,751
|
)
|
$
|
44,704
|
$
|
37,833
|
|||
Total
income tax expense (benefit) as shown for Peoples Gas and North Shore Gas on
each of the respective Consolidated Statements of Operations is composed of
the
following:
|
Peoples
Gas
|
North
Shore Gas
|
||||||||||||||||||
|
For
Fiscal Years Ended September 30,
|
2006
|
2005
|
2004
|
2006
|
2005
|
2004
|
|||||||||||||
|
(In
Thousands)
|
|||||||||||||||||||
|
Current:
|
|||||||||||||||||||
|
Federal
|
$
|
12,343
|
$
|
24,479
|
$
|
17,565
|
$
|
702
|
$
|
575
|
$
|
2,976
|
|||||||
|
State
|
(920
|
)
|
5,482
|
3,915
|
(325
|
)
|
66
|
672
|
|||||||||||
|
Total
current income taxes
|
11,423
|
29,961
|
21,480
|
377
|
641
|
3,648
|
|||||||||||||
|
Deferred:
|
|||||||||||||||||||
|
Federal
|
(33,391
|
)
|
(2,964
|
)
|
2,721
|
2,389
|
4,816
|
2,655
|
|||||||||||
|
State
|
(3,732
|
)
|
257
|
1,199
|
1,057
|
1,248
|
555
|
||||||||||||
|
Total
deferred income taxes
|
(37,123
|
)
|
(2,707
|
)
|
3,920
|
3,446
|
6,064
|
3,210
|
|||||||||||
|
Investment
tax credits—net:
|
|||||||||||||||||||
|
Federal
amortization
|
(647
|
)
|
(649
|
)
|
(812
|
)
|
(61
|
)
|
(63
|
)
|
(90
|
)
|
|||||||
|
State
ITC provision
|
412
|
253
|
-
|
58
|
33
|
-
|
|||||||||||||
|
State
ITC amortization
|
(181
|
)
|
(168
|
)
|
(191
|
)
|
(23
|
)
|
(19
|
)
|
(25
|
)
|
|||||||
|
Total
investment tax credits—net
|
(416
|
)
|
(564
|
)
|
(1,003
|
)
|
(26
|
)
|
(49
|
)
|
(115
|
)
|
|||||||
|
Net
income tax expense (benefit)
|
$
|
(26,116
|
)
|
$
|
26,690
|
$
|
24,397
|
$
|
3,797
|
$
|
6,656
|
$
|
6,743
|
||||||
B.
Tax Rate Reconciliation
The
following is a reconciliation for the Company between the
federal
statutory income tax rate of 35% and the effective income tax rate for
continuing operations
.
|
Percent
of Pretax Income/Loss
|
|||||||
|
For
Fiscal Years Ended September 30,
|
2006
|
2005
|
2004
|
||||
|
Federal
statutory income tax rate
|
35.00
|
35.00
|
35.00
|
||||
|
Increase
(decrease) due to:
|
|||||||
|
State
income taxes—net
|
10.09
|
1.79
|
0.06
|
||||
|
Federal
medicare subsidy
|
3.20
|
(0.57
|
)
|
-
|
|||
|
Merger
costs—non-deductible
|
(3.16
|
)
|
-
|
-
|
|||
|
Other—net
|
0.60
|
(0.43
|
)
|
(4.22
|
)
|
||
|
Effective
income tax rate for continuing operations
|
45.73
|
35.79
|
30.84
|
||||
|
Effective
income tax rate for discontinued operations
|
39.74
|
39.75
|
39.75
|
||||
|
Total
effective income tax rate
|
48.71
|
36.39
|
31.69
|
||||
The
increase in the state income tax rate in fiscal 2006 is due to the impact
of
Illinois tax benefits relative to the Company’s disproportionately smaller
consolidated loss before income taxes caused by taxable income in states
other
than Illinois. The Medicare Prescription Drug, Improvement and Modernization
Act
of 2003 (see Note 11E) excludes receipt of the subsidy from taxable income
of
the employer for federal income tax purposes. Certain transaction costs incurred
to facilitate a merger are
estimated
to be non-deductible for tax purposes. (See Note 1 for a discussion of the
proposed merger between the Company and WPS Resources.
)
The
following
is a reconciliation for Peoples Gas between the
federal
statutory income tax rate of 35% and the total effective income tax
rate
.
|
Peoples
Gas
|
|||||||
|
Percent
of Pretax Income/Loss
|
|||||||
|
For
Fiscal Years Ended September 30,
|
2006
|
2005
|
2004
|
||||
|
Federal
statutory income tax rate
|
35.00
|
35.00
|
35.00
|
||||
|
Increase
(decrease) due to:
|
|||||||
|
State
income taxes—net
|
4.67
|
4.98
|
4.59
|
||||
|
Federal
medicare subsidy
|
2.16
|
(0.63
|
)
|
-
|
|||
|
Federal
accrual adjustments
|
1.42
|
(4.03
|
)
|
(1.28
|
)
|
||
|
Other—net
|
(0.83
|
)
|
(0.21
|
)
|
(3.34
|
)
|
|
|
Total
effective income tax rate
|
42.42
|
35.11
|
34.97
|
||||
The
following is a reconciliation for North Shore Gas between the
federal
statutory income tax rate of 35% and the total effective income tax
rate
.
|
North
Shore Gas
|
|||||||
|
Percent
of Pretax Income
|
|||||||
|
For
Fiscal Years Ended September 30,
|
2006
|
2005
|
2004
|
||||
|
Federal
statutory income tax rate
|
35.00
|
35.00
|
35.00
|
||||
|
Increase
(decrease) due to:
|
|||||||
|
State
income taxes—net
|
4.74
|
4.78
|
4.38
|
||||
|
Other—net
|
(3.59
|
)
|
(2.91
|
)
|
(1.45
|
)
|
|
|
Total
effective income tax rate
|
36.15
|
36.87
|
37.93
|
||||
C.
Deferred Income Taxes
Summarized
in the table below for the Company are the temporary differences which gave
rise
to the net deferred income tax liabilities (see Note 2G).
|
September
30,
|
||||||||
|
2006
|
2005
|
|||||||
|
(In
Thousands)
|
||||||||
|
Deferred
tax liabilities:
|
||||||||
|
Property—accelerated
depreciation
|
||||||||
|
and
other property-related items
|
$
|
434,073
|
$
|
409,553
|
||||
|
Pension
|
72,880
|
63,659
|
||||||
|
Partnership
items
|
28,512
|
26,323
|
||||||
|
Other
|
30,632
|
40,364
|
||||||
|
Total
deferred income tax liabilities
|
566,097
|
539,899
|
||||||
|
Deferred
tax assets:
|
||||||||
|
Derivative
instruments
|
(21,962
|
)
|
(85,496
|
)
|
||||
|
Alternative
minimum tax
|
(23,626
|
)
|
(8,517
|
)
|
||||
|
Group
insurance
|
(29,559
|
)
|
(21,103
|
)
|
||||
|
Other
|
(65,184
|
)
|
(42,872
|
)
|
||||
|
Total
deferred income tax assets
|
(140,331
|
)
|
(157,988
|
)
|
||||
|
Net
deferred income tax liabilities
|
$
|
425,766
|
(1)
|
$
|
381,911
|
(2)
|
||
| (1) |
Includes
$35.3 million of net current deferred tax assets that are classified
in
Other Current Assets and Other Accrued Liabilities on the balance
sheet.
|
| (2) |
Includes
$64.4 million of net current deferred tax assets that are classified
in
Other Current Assets and Other Accrued Liabilities on the balance
sheet.
|
Summarized
in the table below for Peoples Gas are the temporary differences which gave
rise
to the net deferred income tax liabilities (see Note 2G).
|
(In
Thousands)
|
Peoples
Gas
|
|||||||
|
September
30,
|
2006
|
2005
|
||||||
|
Deferred
tax liabilities:
|
||||||||
|
Property—accelerated
depreciation and
|
||||||||
|
other
property-related items
|
$
|
323,254
|
$
|
317,020
|
||||
|
Pension
|
73,393
|
60,818
|
||||||
|
Other
|
24,040
|
30,905
|
||||||
|
Total
deferred income tax liabilities
|
420,687
|
408,743
|
||||||
|
Deferred
tax assets:
|
||||||||
|
Alternative
minimum tax
|
(18,101
|
)
|
(4,318
|
)
|
||||
|
Group
insurance
|
(24,083
|
)
|
(17,399
|
)
|
||||
|
Other
|
(49,635
|
)
|
(30,458
|
)
|
||||
|
Total
deferred income tax assets
|
(91,819
|
)
|
(52,175
|
)
|
||||
|
Net
deferred income tax liabilities
|
$
|
328,868
|
(1)
|
|
$
|
356,568
|
(2)
|
|
| (1) |
Includes
$24.3 million of net current deferred taxes that is classified
in Other
Current Assets on the balance
sheet.
|
| (2) |
Includes
$7.6 million of net current deferred taxes that is classified
in Other
Current Assets on the balance
sheet.
|
Summarized
in the table below for North Shore Gas are the temporary differences which
gave
rise to the net deferred income tax liabilities (see Note 2G).
|
(In
Thousands)
|
North
Shore Gas
|
|||||||
|
September
30,
|
2006
|
2005
|
||||||
|
Deferred
tax liabilities:
|
||||||||
|
Property—accelerated
depreciation and
|
||||||||
|
other
property-related items
|
$
|
43,881
|
$
|
42,050
|
||||
|
Gas
cost reconciliation
|
-
|
2,571
|
||||||
|
Other
|
8,569
|
2,642
|
||||||
|
Total
deferred income tax liabilities
|
52,450
|
47,263
|
||||||
|
Deferred
tax assets:
|
||||||||
|
Group
insurance
|
(3,019
|
)
|
(2,217
|
)
|
||||
|
Gas
cost reconciliation
|
(1,142
|
)
|
-
|
|||||
|
Other
|
(5,050
|
)
|
(4,035
|
)
|
||||
|
Total
deferred income tax assets
|
(9,211
|
)
|
(6,252
|
)
|
||||
|
Net
deferred income tax liabilities
|
$
|
43,239
|
(1)
|
$
|
41,011
|
(2)
|
||
| (1) |
Includes
$2.5 million of net current deferred taxes that is classified in
Other
Current Assets on the balance
sheet.
|
| (2) |
Includes
$1.9 million of net current deferred taxes that is classified in
Other
Accrued Liabilities on the balance
sheet.
|
As
of
September 30, 2006, the Company had federal and state net operating loss
carryforwards of approximately $5.9 million and $4.7 million, respectively,
which, if unused, will expire in 2026 and 2018, respectively.
The
Company records a reserve for uncertain tax positions based upon its assessment
of the probabilities that certain deductions or income tax positions may not
be
sustained when income tax returns are audited by taxing
jurisdictions. The reserves recorded at September 30, 2006 and 2005 are
not material to the consolidated financial statements.
13:
DEBT COVENANTS
North
Shore Gas’ 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, 2006, such restrictions
amounted to $6.9 million out of North Shore Gas’ total retained earnings of
$76.3 million.
The
Company has revolving credit facilities which primarily support its commercial
paper borrowing. These credit facilities provide that the lenders under such
facilities may terminate the credit commitments to the borrowing company and
declare any outstanding amounts due and payable if the borrowing company’s
debt-to-total capital ratio excluding the impact of accumulated other
comprehensive income (AOCI), exceeds 65%. At September 30, 2006, this
ratio, as defined in the credit facilities, was 58% for Peoples Energy and
44%
for Peoples Gas.
The
Company’s indenture relating to its $325.0 million notes due
January 15, 2011, has a cross-default provision relating to any other
indebtedness greater than $15.0 million. The Company’s five-year revolving
credit facilities have a cross-default provision relating to any other
indebtedness greater than $15.0 million. Peoples Gas’ five-year revolving
credit facilities have a cross-default provision relating to any other
indebtedness greater than $15.0 million.
The
Indenture of Mortgage, dated January 2, 1926, as supplemented, securing the
First and Refunding Mortgage Bonds issued by Peoples Gas, constitutes a direct,
first-mortgage lien on substantially all property owned by Peoples Gas. The
Indenture, dated April 1, 1955, as supplemented, securing the first
mortgage bonds issued by North Shore Gas, constitutes a direct, first-mortgage
lien on substantially all property owned by North Shore Gas.
14:
LONG-TERM DEBT AND SHORT-TERM DEBT
Peoples
Gas and North Shore Gas utilize mortgage bonds to secure tax exempt interest
rates. The Illinois Finance Authority has issued tax exempt bonds for the
benefit of Peoples Gas and North Shore Gas and Chicago has issued tax exempt
bonds for the benefit of Peoples Gas. Each issuance is secured by an equal
principal amount of Peoples Gas’ or North Shore Gas’ first mortgage
bonds.
A.
Changes in Debt Securities
During
fiscal 2005, the Company took advantage of the low interest rate environment
to
refinance existing higher interest rate debt. During fiscal 2004, the Company
took advantage of the low interest rate environment to term-up adjustable rate
debt. In general, debt classified as short-term due to the technical tender
provisions was replaced by long-term debt.
Peoples
Gas has $51.0 million of Adjustable Rate, Series OO bonds, due October 1, 2037
and $51.0 million of Adjustable rate, Series PP bonds, due October 1, 2037
outstanding, which currently are in a 35-day period Auction Rate Mode. Fiscal
2006 weighted-average interest rate was 3.17% and 3.29% for Series OO and PP,
respectively.
The
following table summarizes the fiscal 2005 and 2004 changes in the composition
of the Company’s debt.
|
(Dollars
In Millions)
|
Issuances
(tax exempt
)
|
Retirements
(tax exempt
)
|
|||||||||||
|
Fiscal
2005
|
|||||||||||||
|
Peoples
Gas
|
$
|
50.0
|
Adjustable
rate, Series RR
|
$
|
50.0
|
6.10%
Series FF,
|
|||||||
|
due
June 1, 2035
|
Due
June 1, 2025
|
||||||||||||
|
(4.30%
fixed for 11 years)
|
|||||||||||||
|
Total
Fiscal 2005
|
$
|
50.0
|
$
|
50.0
|
|||||||||
|
Fiscal
2004
|
|||||||||||||
|
Peoples
Gas
|
$
|
51.0
|
Adjustable
rate, Series OO
|
$
|
27.0
|
Variable
rate, Series EE
|
|||||||
|
due
Oct. 1, 2037 (1)
|
|||||||||||||
|
51.0
|
Adjustable
rate, Series PP,
|
37.5
|
Variable
rate, Series II
|
||||||||||
|
due
Oct. 1, 2037 (1)
|
|||||||||||||
|
75.0
|
Adjustable
rate, Series QQ,
|
37.5
|
Variable
rate, Series JJ
|
||||||||||
|
due
Nov. 1, 2038
|
|||||||||||||
|
(4.875%
fixed for 15 years)
|
75.0
|
5.75%,
Series DD
|
|||||||||||
|
Total
Fiscal 2004
|
$
|
177.0
|
$
|
177.0
|
|||||||||
On
June
13, 2006, the Company entered into a 5-year syndicated revolving credit
agreement with twelve financial institutions that provides backup for the
Company’s commercial paper borrowing program. The maximum amount that may be
borrowed under the credit agreement is $400 million. This replaces the
previous $225 million credit facility that was scheduled to expire in March
2007.
On
July 12, 2005, Peoples Gas entered into a 5-year syndicated revolving
credit agreement with eleven financial institutions that provides backup for
Peoples Gas’ seasonal commercial paper borrowing program. The maximum amount
that may be borrowed under the credit agreement is $250 million. This
replaced the previous $200 million credit facility that was scheduled to
expire in August 2005.
B.
Short-Term Debt
The
following table presents a detail of short-term debt by type.
|
Fiscal
2006
|
|
Balance
At
|
|
Fiscal
2005
|
|
Balance
At
|
|||||
|
Weighted-Average
|
|
September
30,
|
|
Weighted-Average
|
|
September
30,
|
|||||
|
(In
Thousands)
|
Interest
Rate %
|
|
2006
|
|
Interest
Rate %
|
|
2005
|
||||
|
Commercial
Paper:
|
|||||||||||
|
Peoples
Energy
|
5.08
|
$
|
309,744
|
2.41
|
$
|
8,148
|
|||||
|
Peoples
Gas
|
4.41
|
-
|
2.07
|
-
|
|||||||
|
|
|||||||||||
|
Bank
Loans:
|
|||||||||||
|
Peoples
Energy
|
5.16
|
$
|
-
|
2.56
|
$
|
-
|
|||||
|
Total
short-term debt - Company
|
$
|
309,744
|
$
|
8,148
|
|||||||
|
Company
loans to Peoples Gas
|
4.07
|
$
|
-
|
-
|
$
|
-
|
|||||
|
North
Shore Gas loans to Peoples Gas
|
4.48
|
$
|
-
|
2.63
|
$
|
360
|
|||||
|
Company
loans to North Shore Gas
|
4.09
|
$
|
-
|
2.13
|
$
|
-
|
|||||
|
Peoples
Gas loans to North Shore Gas
|
4.23
|
$
|
-
|
2.38
|
$
|
-
|
|||||
Short-term
cash needs of Peoples Energy are met through bank loans or the issuance of
short-term debt. The outstanding total amount of commercial paper and bank
loans
under the revolving credit facilities cannot at any time exceed total bank
lines
of credit then in effect. At September 30, 2006, the Company and its
subsidiaries had combined lines of credit totaling $650 million. Of those
lines Peoples Energy Corporation had lines of credit totaling $400 million,
of which $89.6 million of credit was available. The agreements for the
$400 million will expire June 2011. Such lines of credit cover the
projected short-term credit needs of the Company. Payment for the lines of
credit is by fee. In addition, at September 30, 2006, the Company had
approximately $6.7 million of letters of credit outstanding for financial
and performance guarantees.
On
October 20, 2006, the Company entered into (1) a $25 million revolving credit
agreement with ABN AMRO Bank, N.V.; (2) a $25 million revolving credit agreement
with Bank of America, N.A.; and (3) a $25 million revolving credit agreement
with JPMorgan Chase Bank to provide for potential seasonal liquidity needs.
Each
credit agreement is effective from October 20, 2006 through the earlier of
(i)
March 31, 2007 or (ii) the consummation of the merger between a subsidiary
of
WPS Resources Corporation and Peoples Energy. Funds may be used for general
corporate purposes and commercial paper back-up.
Short-term
cash needs of Peoples Gas are met through inter-company loans from the Company,
inter-utility loans from North Shore Gas, bank loans or the issuance of
commercial paper. The outstanding total amount of commercial paper and bank
loans under the revolving credit facilities cannot at any time exceed total
bank
lines of credit then in effect. At September 30, 2006, Peoples Gas had
aggregate available lines of $250 million all of which was available.
Agreements covering these lines expire in July 2010. In addition, at
September 30, 2006 and 2005, Peoples Gas had approximately
$0.1 million and $0.1 million, respectively, of letters of credit
outstanding for financial and performance guarantees. The credit facilities
of
the Company and Peoples Gas are expected to be renewed when they expire,
although the exact amount of the renewals will be evaluated at that time and
may
change from the current levels.
North
Shore Gas’ short-term cash needs are met through loans from the Company and/or
inter-utility loans from Peoples Gas, which are sufficient resources to meet
working capital requirements. At September 30, 2006, North Shore had no
loans outstanding.
15:
EARNINGS PER SHARE
The
following table summarizes average and diluted shares for computing the
Company’s per-share amounts. The dilution is attributable to stock options and
performance shares outstanding under the Company’s LTIC and DSOP. The diluted
shares for the Company are as follows:
|
For
Fiscal Years Ended
September
30,
|
||||||||||
|
2006
|
2005
|
2004
|
||||||||
|
(In
Thousands)
|
||||||||||
|
Average
shares of common stock outstanding
|
38,365
|
37,977
|
37,318
|
|||||||
|
Effects
of options and performance shares
|
153
|
163
|
172
|
|||||||
|
Diluted
shares
|
38,518
|
38,140
|
37,490
|
|||||||
For
fiscal 2006, all outstanding options and performance shares were excluded from
the computation of diluted loss per share because inclusion would be
antidilutive.
16:
PREFERRED STOCK
The
Company has five million shares of Preferred Stock, no par value,
authorized for issuance, of which none were issued and outstanding at
September 30, 2006.
Peoples
Gas has 430,000 shares of Preferred Stock, $100 par value, authorized
for issuance, of which none were issued and outstanding at September 30,
2006. North Shore Gas has 160,000 shares of Preferred Stock, $100 par
value, authorized for issuance, of which none were issued and outstanding at
September 30, 2006.
17:
COMMON STOCK AND STOCK COMPENSATION PLANS
Common
Stock
The
Company has filed a universal shelf registration statement on Form S-3 for
the issuance from time to time of up to 1.5 million shares of common stock
pursuant to a continuous equity offering in one or more negotiated transactions
or “at-the-market” offerings. Since the Form S-3 was filed in 2002 and through
September 30, 2006, 1,235,700 shares of common stock have been issued
through the continuous equity offering. Proceeds, net of issuance costs, totaled
$47.9 million.
In
addition, the Company issues common stock through other plans such as the Direct
Purchase and Investment Plan and ESPP. In early fiscal 2003, the Company began
issuing new shares from open market transactions to satisfy the requirements
of
the Direct Purchase and Investment Plan. Stock activity is summarized
below.
|
For
Fiscal Years Ended September 30,
|
|||||||||||||||||
|
2006
|
2005
|
2004
|
|||||||||||||||
|
(Dollars
in Thousands)
|
Shares
|
|
Dollars
|
Shares
|
Dollars
|
Shares
|
Dollars
|
||||||||||
|
Beginning
of period
|
38,157,218
|
$
|
402,383
|
37,733,894
|
$
|
384,482
|
36,689,968
|
$
|
339,785
|
||||||||
|
Shares
issued:
|
|||||||||||||||||
|
Employee
Stock Purchase Plan
|
15,590
|
510
|
12,228
|
479
|
13,244
|
487
|
|||||||||||
|
Long-Term
Incentive Compensation
|
|||||||||||||||||
|
Plan—net
|
62,330
|
3,374
|
176,601
|
6,602
|
390,302
|
14,451
|
|||||||||||
|
Shares
issued through continuous
|
|||||||||||||||||
|
equity
offerings
|
-
|
-
|
-
|
-
|
377,400
|
15,458
|
|||||||||||
|
Directors
Deferred Compensation Plan
|
3,056
|
879
|
2,879
|
1,019
|
-
|
-
|
|||||||||||
|
Directors
Stock and Option Plan
|
-
|
-
|
1,092
|
43
|
766
|
(1)
|
3,347
|
||||||||||
|
Direct
Purchase and Investment Plan
|
250,586
|
9,262
|
230,524
|
9,758
|
262,214
|
10,954
|
|||||||||||
|
Total
activity for the period
|
331,562
|
14,025
|
423,324
|
17,901
|
1,043,926
|
44,697
|
|||||||||||
|
End
of period
|
38,488,780
|
$
|
416,408
|
38,157,218
|
$
|
402,383
|
37,733,894
|
$
|
384,482
|
||||||||
| (1) |
During
2004 Treasury Shares were reduced by 3,000, of which 766 were
re-issued in
accordance with the DSOP.
|
In
fiscal
2006, Peoples Gas issued
540,000
shares of its common stock to the Company for $53.9 million.
The
2004
Incentive Compensation Plan (Plan) is comprised of two sub-plans, the LTIC
Plan
and the Short-Term Incentive Compensation Plan. The Plan does not provide for
the grant of stock options or SARs, as under the prior plan, but instead
provides for the issuance of restricted stock, restricted stock units and
performance shares. All outstanding options from the prior plan became fully
vested as of December 31, 2003, and no options or restricted stock units were
subsequently granted.
Under
the
Plan, up to 700,000 shares of the Company's common stock are available for
issuance for awards under the LTIC Plan. However, no more than 350,000 shares
may be granted for restricted stock and for awards of restricted stock
units.
Restricted
stock awards are shares of the Company's common stock awarded to eligible
employees and are subject to forfeiture. Restricted stock awards granted vest
in
equal annual increments over a five-year period from the
date
of
grant and are subject to forfeiture if the recipient fails to remain employed,
other than by reason of death, disability or retirement on or after attaining
age 65 (or such earlier date as determined by the Compensation Committee of
the
Board of Directors (Compensation Committee)), until the applicable vesting
date.
Additionally, in the event of a change in control any grants of restricted
stock
under the Plan will become immediately fully vested. Restricted stock awards
have no exercise price and compensation cost is measured based upon the fair
market value of the Company's common stock at the date of grant. Such cost
is
recognized as expense over the vesting period.
A
performance share is a contingent right to receive a share of common stock
of
the Company in the future, pursuant to the terms of a grant made under the
Plan
and the related award agreement. One or more performance goals and a performance
cycle (period) of not less than one year is established for any grant of
performance shares. At the expiration of the performance cycle, the Compensation
Committee will determine the extent to which the performance goals were
achieved. The Compensation Committee will then determine the number of
performance shares to which a recipient of performance shares under the grant
is
entitled, based upon the number of performance shares originally granted to
the
recipient and the level of performance achieved. Performance shares will be
settled by the delivery of shares of common stock of the Company as soon as
practicable after the close of the performance cycle.
If
a
performance share recipient's employment with the Company terminates other
than
by reason of death, disability, or retirement on or after attaining age 65
(or
such earlier date as determined by the Compensation Committee) prior to the
last
day of a performance cycle, the recipient will forfeit the performance shares
granted with respect to such performance cycle. If a performance share
recipient's employment with the Company terminates by reason of death or
disability prior to the last day of a performance cycle, the performance goals
for the recipient's performance shares will be deemed to have been achieved
at
target levels, and the recipient will be entitled to a pro rata distribution
of
shares of common stock in settlement of the performance shares. If a performance
share recipient's employment with the Company terminates by reason of retirement
on or after attaining age 65 (or such earlier date as determined by the
Compensation Committee) prior to the last day of a performance cycle, the
recipient will be entitled to a pro rata distribution of shares of common stock
in settlement of the performance shares, based upon the performance goals
achieved. If there is a change in control of Peoples Energy, the performance
goals of all outstanding performance shares granted under the Plan will be
deemed to have been achieved at target levels, and a recipient will be entitled
to a pro rata distribution of shares of common stock in settlement of the
performance shares, based on the number of months during the performance cycle
that the recipient was employed by the Company, up to the date of the change
in
control. Performance shares have no exercise price.
Under
the
Plan, performance goals may be based on various criteria measuring the
performance of the Company generally or relative to peer company performance,
and may be based on a comparison of actual performance during a performance
period against budget for such period.
The
Company's prior plan awarded grants of options enabling the recipient to
purchase Company common stock at a price equal to the fair market value of
the
shares on the date the option was granted. The grant of a 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 Company common stock on the
date
the SAR is exercised over the fair market value of one share on the date the
SAR
was granted. Before an option or SAR may be exercised, the recipient must
generally 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 for other reasons.
The
Company also offers employees periodic opportunities to purchase shares of
its
common stock at a discount from the then current market price under its ESPP.
As
of November 30, 2006, the Company may sell up to 853,312 shares of common stock
to its employees under the ESPP. Under the terms of this plan, all employees
are
eligible to purchase shares at 90% of the stock's market price at the date
of
purchase.
As
a
result of the merger agreement between the Company and WPS Resources, it is
necessary to limit the amount of stock that employees not covered under
collective bargaining agreements can purchase under the ESPP. Therefore,
effective September 1, 2006: (1) employees currently enrolled in payroll
deduction cannot increase the payroll deduction for the plan from what it was
on
July 8, 2006; (2) participation in the plan can only be done through payroll
deductions; no other forms of payment will be accepted; and (3) employees who
did not participate in payroll deduction on July 8, 2006 and new employees
cannot purchase stock under the ESPP.
If
the
merger with WPS Resources becomes probable of occurring, the change in control
provisions for the stock awards described above would become effective. See
Note
1 for further discussion regarding the merger.
Nonemployee
directors participate in the Company's DSOP. Under the DSOP, as amended by
the
Board of Directors in December 2002, each nonemployee director of the Company
will receive, as part of his or her annual retainer, an annual award of 1,000
deferred shares of common stock of the Company. With certain exceptions under
the DSOP, shares are automatically deferred until the director's retirement.
The
director is entitled to receive amounts representing dividends from such
deferred shares equal to dividends paid with respect to a like number of shares
of common stock of the Company. Compensation expense is based upon the fair
market value of the Company's common stock at the date of issuance.
Nonemployee
directors also have an opportunity to defer their compensation in the form
of
cash or Company common stock. Compensation expense in the form of common stock
is based upon the fair market value of the Company's common stock at the date
of
issuance.
The
Company has a policy of issuing additional shares to satisfy the exercises
or
conversions under its share-based compensation arrangements.
Effective
October 1, 2005, the Company adopted SFAS No. 123 (R), requiring compensation
costs related to share-based payment transactions to be recognized in the
financial statements. Compensation cost is measured based on the grant-date
fair
value of the equity or liability instrument issued. In addition, liability
awards are remeasured each reporting period. Compensation cost is recognized
over the period that the employee provides service in exchange for the award.
SFAS No. 123 (R) replaces SFAS No. 123 and supersedes APB Opinion No. 25.
The
Company applied the modified prospective method of adopting SFAS No. 123 (R),
which requires the new standard to be applied to unexercised SARs and unvested
performance shares as of October 1, 2005 and prospectively. The method requires
SFAS No. 123 (R) to be applied prospectively to the ESPP, new awards under
the
Plan and existing awards if modified, repurchased or cancelled.
Adoption
of SFAS No. 123 (R) resulted in the Company recognizing immaterial compensation
expense upon adoption and related primarily to the Company's unvested
performance shares and unexercised SARs.
Share-based
employee compensation expense relative to ESPP, performance shares, SARs, RSAs
and directors fees paid in stock included in reported net income for the fiscal
years ended September 30, 2006, 2005 and 2004 (prior years not restated for
adoption of SFAS No. 123 (R)) totaled $4.0 million, $2.0 million and $1.8
million, respectively (tax benefit of $1.6 million, $0.8 million and $0.7
million, respectively).
There
were 15,590, 12,228 and 13,244 shares sold through the ESPP for the fiscal
years
ended September 30, 2006, 2005 and 2004, respectively. Had compensation cost
for
shares issued under the ESPP been determined consistent with the requirements
under the prior SFAS No. 123, the pro forma effect on the Company's 2005 and
2004 net income and earnings per share would not be material.
Prior
to
the adoption of SFAS No. 123 (R), the Company’s SARs were recorded at intrinsic
value. As the Company's SARs meet the SFAS No. 123 (R) definition of a
share-based liability, the fair value of each SAR award is estimated on the
date
of grant and updated on a quarterly basis using the Black-Scholes-Merton
valuation model. Compensation expense for SARs is recognized over the vesting
period. The model uses the assumptions in
the
following table. The expected term of the SARs represents the period of time
the
granted SARs are expected to be outstanding based on historical experience,
subject to remaining contractual term. The risk-free rate for periods within
the
contractual life of the SARs is based on the U.S. Treasury yield curve in effect
at the time of the grant or subsequent quarter-end measurement
date.
|
For
the Fiscal Year Ended September 30, 2006
|
|
|
Expected
volatility
|
17%-19%
|
|
Weighted-average
volatility
|
17.76%
|
|
Expected
dividends
|
5.4%
|
|
Expected
term (in years)
|
0-5
|
|
Risk-free
rate
|
4.6%-4.9%
|
At
September 30, 2006, 134,075 total performance shares were outstanding and
remained unvested under the Plan for the 2004-2006, 2005-2007 and 2006-2008
performance cycles. As vesting and conversion of performance shares to Company
common stock depends upon achieving certain goals represented by a combination
of market and performance measures, the Company estimated the fair value of
such
awards based on historical input into a Monte Carlo simulation model, three
year
business plan data and grant date fair market value of the Company's common
stock. The calculated compensation cost is recognized as expense over each
of
the respective three-year cycles. In December 2006 it was determined that no
performance shares granted under the 2004-2006 cycle had vested.
A
summary
of share-based payment activity during fiscal 2006 is presented
below:
|
Weighted-Average
|
Aggregate
|
||||||||||||
|
Weighted-Average
|
Remaining
|
Intrinsic
Value
|
|||||||||||
|
Options
|
Shares
|
Exercise
Price
|
|
Contractual
Term
|
(000's)
|
||||||||
|
Outstanding
at September 30, 2005
|
593,400
|
$
|
38.37
|
||||||||||
|
Granted
|
-
|
-
|
|||||||||||
|
Exercised
|
(47,300
|
)
|
35.25
|
||||||||||
|
Forfeited
or expired
|
(11,200
|
)
|
37.69
|
||||||||||
|
Outstanding
at September 30, 2006
|
534,900
|
$
|
38.66
|
5.1
years
|
$
|
1,065
|
|||||||
|
Exercisable
at September 30, 2006
|
534,900
|
$
|
38.66
|
5.1
years
|
$
|
1,065
|
|||||||
|
Weighted-Average
|
Aggregate
|
||||||||||||
|
Weighted-Average
|
Remaining
|
Intrinsic
Value
|
|||||||||||
|
SARs
|
Shares
|
Exercise
Price
|
Contractual
Term
|
(000's)
|
|||||||||
|
Outstanding
at September 30, 2005
|
35,700
|
$
|
36.45
|
||||||||||
|
Granted
|
-
|
-
|
|||||||||||
|
Exercised
|
(7,800
|
)
|
36.84
|
||||||||||
|
Forfeited
or expired
|
(2,300
|
)
|
35.10
|
||||||||||
|
Outstanding
at September 30, 2006
|
25,600
|
$
|
36.46
|
2.7
years
|
$
|
107
|
|||||||
|
Exercisable
at September 30, 2006
|
25,600
|
$
|
36.46
|
2.7
years
|
$
|
107
|
|||||||
|
Weighted-Average
|
Aggregate
|
||||||||||||
|
Remaining
|
Intrinsic
Value
|
||||||||||||
|
RSAs
|
Shares
|
Contractual
Term
|
(000's)
|
||||||||||
|
Outstanding
at September 30, 2005
|
114,220
|
||||||||||||
|
Granted
|
65,550
|
||||||||||||
|
Converted
|
(33,715
|
)
|
|||||||||||
|
Forfeited
or expired
|
(5,125
|
)
|
|||||||||||
|
Outstanding
at September 30, 2006
|
140,930
|
3.0
years
|
$
|
5,729
|
|||||||||
|
Weighted-Average
|
Aggregate
|
||||||||||||
|
Remaining
|
Intrinsic
Value
|
||||||||||||
|
Performance
Shares
|
Shares
|
Contractual
Term
|
(000's)
|
|
|||||||||
|
Outstanding
at September 30, 2005
|
81,575
|
||||||||||||
|
Granted
|
55,900
|
||||||||||||
|
Converted
|
-
|
||||||||||||
|
Forfeited
or expired
|
(3,400
|
)
|
|||||||||||
|
Outstanding
at September 30, 2006
|
134,075
|
1.1
years
|
$
|
5,450
|
|||||||||
|
Aggregate
|
|||||
|
Intrinsic
Value
|
|||||
|
Director
Plans
|
Shares
|
(000's)
|
|||
|
Outstanding
at September 30, 2005
|
114,424
|
||||
|
Granted
|
27,972
|
||||
|
Converted
|
(6,659
|
)
|
|||
|
Forfeited
or expired
|
-
|
||||
|
Outstanding
at September 30, 2006
|
135,737
|
$
|
5,518
|
||
A
summary
of certain share-based payment activity during fiscal 2006, 2005 and 2004 is
presented below:
|
Non-Qualified
|
Performance
|
||||||||||||||
|
(In
Thousands, Except Per-Share Amounts)
|
Stock
Options
|
SARs
|
RSAs
|
Shares
|
Director
Plans
|
||||||||||
|
2006
|
|||||||||||||||
|
Weighted-average
grant-date fair value
of
options or shares granted
|
$
|
-
|
$
|
-
|
$
|
36.49
|
$
|
18.37
|
$
|
36.73
|
|||||
|
Total
intrinsic value of options exercised,
liabilities
paid or shares converted
|
266
|
28
|
1,295
|
-
|
1,027
|
||||||||||
|
Total
fair value of options or shares vested
|
-
|
-
|
1,310
|
-
|
-
|
||||||||||
|
Total
cash received from options exercised
or
shares converted
|
1,667
|
-
|
-
|
-
|
-
|
||||||||||
|
Total
cash used to settle equity instruments
granted
|
-
|
28
|
-
|
-
|
-
|
||||||||||
|
Actual
tax benefit realized from options
exercised
or shares converted
|
$
|
106
|
$
|
11
|
$
|
515
|
$
|
-
|
$
|
408
|
|||||
|
2005
|
|||||||||||||||
|
Weighted-average
grant-date fair value
of
options or shares granted
|
$
|
-
|
$
|
-
|
$
|
42.30
|
$
|
1.02
|
$
|
37.89
|
|||||
|
Total
intrinsic value of options exercised,
liabilities
paid or shares converted
|
817
|
499
|
1,221
|
-
|
983
|
||||||||||
|
Total
fair value of options or shares vested
|
-
|
-
|
1,067
|
-
|
-
|
||||||||||
|
Total
cash received from options exercised or
shares
converted
|
5,607
|
-
|
-
|
-
|
-
|
||||||||||
|
Total
cash used to settle equity instruments
granted
|
-
|
499
|
-
|
-
|
-
|
||||||||||
|
Actual
tax benefit realized from options
exercised
or shares converted
|
$
|
325
|
$
|
198
|
$
|
485
|
$
|
-
|
$
|
391
|
|||||
|
2004
|
|||||||||||||||
|
Weighted-average
grant-date fair value
of
options or shares granted
|
$
|
-
|
$
|
-
|
$
|
41.47
|
$
|
-
|
$
|
41.76
|
|||||
|
Total
intrinsic value of options exercised,
liabilities
paid or shares converted
|
2,810
|
743
|
1,094
|
-
|
837
|
||||||||||
|
Total
fair value of options or shares vested
|
-
|
-
|
922
|
-
|
-
|
||||||||||
|
Total
cash received from options exercised or
shares
converted
|
-
|
-
|
-
|
-
|
-
|
||||||||||
|
Total
cash used to settle equity instruments
granted
|
12,960
|
743
|
-
|
-
|
-
|
||||||||||
|
Actual
tax benefit realized from options
exercised
or shares converted
|
$
|
1,117
|
$
|
295
|
$
|
435
|
$
|
-
|
$
|
333
|
|||||
A
summary
of the status of the Company's nonvested shares as of September 30, 2006 is
presented below:
|
Performance
|
||||||||||||
|
RSA
|
Shares
|
|||||||||||
|
Weighted-Average
|
Weighted-Average
|
|||||||||||
|
RSA
|
Grant-Date
|
Performance
|
Grant-Date
|
|||||||||
|
Shares
|
Fair
Value
|
Shares
|
Fair
Value
|
|||||||||
|
Nonvested
at September 30, 2005
|
114,220
|
$
|
39.95
|
81,575
|
$
|
0.55
|
||||||
|
Granted
|
65,550
|
36.49
|
55,900
|
18.37
|
||||||||
|
Vested
|
(33,715
|
)
|
38.85
|
-
|
-
|
|||||||
|
Forfeited
|
(5,125
|
)
|
36.56
|
(3,400
|
)
|
6.22
|
||||||
|
Nonvested
at September 30, 2006
|
140,930
|
$
|
38.63
|
134,075
|
$
|
7.83
|
||||||
As
of
September 30, 2006, there was $4.6 million of total unrecognized compensation
cost related to non-vested share-based compensation arrangements granted under
the Plan, assuming no Company merger with WPS Resources. That cost would be
recognized over a period of 5 years.
The
Company’s long-term incentive compensation plans provide for accelerated vesting
of restricted stock awards and for accelerated vesting at target levels for
performance shares in the event of a change in control. When the merger with
WPS
Resources becomes probable of occurring, the Company will be required to
recognize compensation expense of approximately $5.2 million representing higher
levels for performance shares (including cumulative amounts for all outstanding
performance shares) and a shorter vesting period for restricted stock than
under
current expense recognition methods.
18:
QUARTERLY FINANCIAL DATA (UNAUDITED)
Quarterly
financial data does not always reveal the trend of the Company’s business
operations due to nonrecurring items and seasonal weather patterns which affect
earnings, and related components of net revenues and operating income.
In
the
third and fourth quarters of fiscal 2006, the Company recorded pre-tax
merger-related expenses of $1.9 million ($1.1 million or $0.03 per diluted
share
after taxes) and $7.0 million ($6.4 million or $0.16 per diluted share after
taxes), respectively.
In
the
first and second quarters of fiscal 2006, the Company recorded pre-tax charges
of $91.7 million ($55.2 million or $1.44 per diluted share after taxes) and
$15.7 million ($9.4 million or $0.25 per diluted share after taxes),
respectively, for settlement of utility gas charge proceedings for fiscal years
2001 through 2004, as well as related civil litigation. Of these amounts,
Peoples Gas recorded pre-tax charges of $74.7 million ($45.0 million after
taxes) and $28.4 million ($17.1 million after taxes) in the first and second
quarters of fiscal 2006, respectively. North Shore Gas recorded a pre-tax charge
of $17.0 million ($10.2 million after taxes) in the first quarter of fiscal
2006
and a pre-tax credit of $(12.7) million ($(7.7) million after taxes) in the
second quarter of fiscal 2006 reducing the accruals for the settlement made
in
earlier periods.
In
the
first quarter of fiscal 2005, the Company recorded pension-related restructuring
costs of $11.2 million, a portion of which related to Peoples Gas ($7.0 million)
and North Shore Gas ($0.5 million). See Note 4 for further discussion.
Quarterly
financial data for the Company was as follows:
|
First
|
Second
|
Third
|
Fourth
|
Fiscal
|
||||||||||||
|
Quarter
|
Quarter
|
Quarter
|
Quarter
|
Year
|
||||||||||||
|
Fiscal
2006
|
||||||||||||||||
|
Operating
revenue
|
$
|
1,052,386
|
$
|
1,180,028
|
$
|
400,445
|
$
|
385,111
|
$
|
3,017,970
|
||||||
|
Operating
income (loss)
|
(22,512
|
)
|
59,432
|
(6,359
|
)
|
(28,775
|
)
|
1,786
|
||||||||
|
Income
(loss) from continuing operations
|
(18,325
|
)
|
33,591
|
(13,714
|
)
|
(29,493
|
)
|
(27,941
|
)
|
|||||||
|
Income
(loss) from discontinued
|
||||||||||||||||
|
operations,
net of tax
|
(1,156
|
)
|
(421
|
)
|
3,603
|
8,279
|
10,305
|
|||||||||
|
Net
income (loss)
|
(19,481
|
)
|
33,170
|
(10,111
|
)
|
(21,214
|
)
|
(17,636
|
)
|
|||||||
|
Basic
EPS:
|
||||||||||||||||
|
Income
(loss) from continuing operations
|
$
|
(0.48
|
)
|
$
|
0.88
|
$
|
(0.35
|
)
|
$
|
(0.77
|
)
|
$
|
(0.73
|
)
|
||
|
Income
(loss) from discontinued
|
||||||||||||||||
|
operations,
net of tax
|
$
|
(0.03
|
)
|
$
|
(0.01
|
)
|
$
|
0.09
|
$
|
0.22
|
$
|
0.27
|
||||
|
Net
income (loss)
|
$
|
(0.51
|
)
|
$
|
0.87
|
$
|
(0.26
|
)
|
$
|
(0.55
|
)
|
$
|
(0.46
|
)
|
||
|
Diluted
EPS:
|
||||||||||||||||
|
Income
(loss) from continuing operations
|
$
|
(0.48
|
)
|
$
|
0.87
|
$
|
(0.35
|
)
|
$
|
(0.76
|
)
|
$
|
(0.73
|
)
|
||
|
Income
(loss) from discontinued
|
||||||||||||||||
|
operations,
net of tax
|
$
|
(0.03
|
)
|
$
|
(0.01
|
)
|
$
|
0.09
|
$
|
0.21
|
$
|
0.27
|
||||
|
Net
income (loss)
|
$
|
(0.51
|
)
|
$
|
0.86
|
$
|
(0.26
|
)
|
$
|
(0.55
|
)
|
$
|
(0.46
|
)
|
||
|
Dividends
declared per share
|
$
|
0.545
|
$
|
0.545
|
$
|
0.545
|
$
|
0.545
|
$
|
2.18
|
||||||
|
Common
stock prices (high-low)
|
$
|
39.90–$34.34
|
$
|
37.97–$35.11
|
$
|
38.66–$35.10
|
$
|
43.87–$35.71
|
$
|
43.87–$34.34
|
||||||
|
Fiscal
2005
|
||||||||||||||||
|
Operating
revenue
|
$
|
737,411
|
$
|
1,026,906
|
$
|
455,931
|
$
|
379,337
|
$
|
2,599,585
|
||||||
|
Operating
income (loss)
|
47,386
|
88,520
|
19,858
|
(6,347
|
)
|
149,417
|
||||||||||
|
Income
(loss) from continuing operations
|
23,062
|
49,831
|
4,835
|
(10,880
|
)
|
66,848
|
||||||||||
|
Income
(loss) from discontinued
|
||||||||||||||||
|
operations,
net of tax
|
(586
|
)
|
1,341
|
1,964
|
8,566
|
11,285
|
||||||||||
|
Net
income (loss)
|
22,476
|
51,172
|
6,799
|
(2,314
|
)
|
78,133
|
||||||||||
|
Basic
EPS:
|
||||||||||||||||
|
Income
(loss) from continuing operations
|
$
|
0.61
|
$
|
1.31
|
$
|
0.13
|
$
|
(0.29
|
)
|
$
|
1.76
|
|||||
|
Income
(loss) from discontinued
|
||||||||||||||||
|
operations,
net of tax
|
$
|
(0.02
|
)
|
$
|
0.04
|
$
|
0.05
|
$
|
0.23
|
$
|
0.30
|
|||||
|
Net
income (loss)
|
$
|
0.59
|
$
|
1.35
|
$
|
0.18
|
$
|
(0.06
|
)
|
$
|
2.06
|
|||||
|
Diluted
EPS:
|
||||||||||||||||
|
Income
(loss) from continuing operations
|
$
|
0.61
|
$
|
1.31
|
$
|
0.13
|
$
|
(0.28
|
)
|
$
|
1.75
|
|||||
|
Income
(loss) from discontinued
|
||||||||||||||||
|
operations,
net of tax
|
$
|
(0.02
|
)
|
$
|
0.03
|
$
|
0.05
|
$
|
0.22
|
$
|
0.30
|
|||||
|
Net
income (loss)
|
$
|
0.59
|
$
|
1.34
|
$
|
0.18
|
$
|
(0.06
|
)
|
$
|
2.05
|
|||||
|
Dividends
declared per share
|
$
|
0.54
|
$
|
0.545
|
$
|
0.545
|
$
|
0.545
|
$
|
2.175
|
||||||
|
Common
stock prices (high-low)
|
$
|
45.38–$41.05
|
$
|
45.10–$41.11
|
$
|
44.97–$38.72
|
$
|
45.52–$38.71
|
$
|
45.52–$38.71
|
Quarterly earnings-per-share amounts are based on the weighted-average common shares outstanding for each quarter and, therefore, the sum of each quarter may not equal the amount computed for the total year.
Quarterly
financial data for Peoples Gas was as follows:
|
First
|
|
|
Second
|
|
|
Third
|
|
|
Fourth
|
|
|
Fiscal
|
||||
|
Quarter
|
|
|
Quarter
|
|
|
Quarter
|
|
|
Quarter
|
|
|
Year
|
||||
|
Fiscal
2006
|
||||||||||||||||
|
Operating
revenue
|
$
|
613,525
|
$
|
694,163
|
$
|
190,587
|
$
|
124,016
|
$
|
1,622,291
|
||||||
|
Operating
income (loss)
|
(35,807
|
)
|
16,561
|
(1,371
|
)
|
(19,517
|
)
|
(40,134
|
)
|
|||||||
|
Net
income (loss)
|
(24,240
|
)
|
7,608
|
(3,374
|
)
|
(15,438
|
)
|
(35,444
|
)
|
|||||||
|
Fiscal
2005
|
||||||||||||||||
|
Operating
revenue
|
$
|
438,852
|
$
|
627,485
|
$
|
219,275
|
$
|
139,091
|
$
|
1,424,703
|
||||||
|
Operating
income (loss)
|
32,364
|
62,794
|
11,037
|
(10,636
|
)
|
95,559
|
||||||||||
|
Net
income (loss)
|
17,269
|
35,640
|
3,947
|
(7,523
|
)
|
49,333
|
Quarterly
financial data for North Shore Gas was as follows:
|
First
|
|
|
Second
|
|
|
Third
|
|
|
Fourth
|
|
|
Fiscal
|
||||
|
Quarter
|
|
|
Quarter
|
|
|
Quarter
|
|
|
Quarter
|
|
|
Year
|
||||
|
Fiscal
2006
|
||||||||||||||||
|
Operating
revenue
|
$
|
115,464
|
$
|
127,194
|
$
|
33,239
|
$
|
23,692
|
$
|
299,589
|
||||||
|
Operating
income (loss)
|
(8,791
|
)
|
23,276
|
464
|
(1,621
|
)
|
13,328
|
|||||||||
|
Net
income (loss)
|
(5,659
|
)
|
13,829
|
(20
|
)
|
(1,443
|
)
|
6,707
|
||||||||
|
Fiscal
2005
|
||||||||||||||||
|
Operating
revenue
|
$
|
80,096
|
$
|
115,147
|
$
|
38,957
|
$
|
26,261
|
$
|
260,461
|
||||||
|
Operating
income (loss)
|
7,354
|
12,346
|
2,601
|
(1,256
|
)
|
21,045
|
||||||||||
|
Net
income (loss)
|
4,093
|
7,125
|
1,195
|
(1,016
|
)
|
11,397
|
19:
SUPPLEMENTAL OIL AND GAS DISCLOSURES (UNAUDITED)
A.
Results of Operations for Exploration and Production
Activities
The
following table summarizes revenue and direct cost information relating to
the
Company’s oil and gas exploration and production activities. The Company has no
long-term agreements to purchase oil or gas production from foreign governments
or authorities.
|
For
Fiscal Years Ended September 30,
|
||||||||||
|
2006
|
2005
|
2004
|
||||||||
|
(In
Thousands)
|
||||||||||
|
Oil
and gas production revenues (1)
|
$
|
126,750
|
$
|
100,602
|
$
|
123,777
|
||||
|
Operating
costs:
|
||||||||||
|
DD &A
and impairments
|
52,049
|
45,485
|
47,078
|
|||||||
|
Lease
operating expenses
|
17,769
|
16,994
|
13,326
|
|||||||
|
Exploration
expense
|
1,072
|
403
|
5,479
|
|||||||
|
Production
taxes
|
14,133
|
12,064
|
9,565
|
|||||||
|
Income
tax
|
14,876
|
9,146
|
17,229
|
|||||||
|
99,899
|
84,092
|
92,677
|
||||||||
|
Results
of operations for producing activities
|
||||||||||
|
(excluding
corporate overhead, general
|
||||||||||
|
and
administrative costs and financing costs)
|
$
|
26,851
|
$
|
16,510
|
$
|
31,100
|
||||
|
Lease
operating expense per Mcfe
|
$
|
0.72
|
$
|
0.70
|
$
|
0.48
|
||||
|
Production
taxes per Mcfe
|
$
|
0.57
|
$
|
0.50
|
$
|
0.34
|
||||
|
Amortization
rate per Mcfe (2)
|
$
|
2.11
|
$
|
1.87
|
$
|
1.69
|
||||
| (1) |
Includes
hedge losses of $62.6 million, $65.9 million and $25.8 million for
fiscal
2006, 2005 and 2004, respectively.
|
| (2) |
Amortization
rate per Mcfe reflects only DD&A of capitalized costs of proved oil
and gas properties.
|
B.
Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development
Activities
The
following table summarizes capitalized costs incurred in oil and gas producing
activities.
|
For
Fiscal Years Ended September 30,
|
||||||||||
|
2006
|
2005
|
2004
|
||||||||
|
(In
Thousands)
|
||||||||||
|
Acquisition
of proved properties
|
$
|
103,794
|
$
|
2,451
|
$
|
32,288
|
||||
|
Acquisition
of unproved properties
|
37,975
|
3,890
|
10,700
|
|||||||
|
Exploration
|
797
|
681
|
6,439
|
|||||||
|
Development
|
93,840
|
66,992
|
52,615
|
|||||||
|
Total
|
$
|
236,406
|
$
|
74,014
|
$
|
102,042
|
||||
C.
Capitalized Costs Relating to Oil and Gas Producing
Activities
The
following table summarizes capitalized costs and associated accumulated
DD&A, including impairments, relating to the Company’s oil and gas
production, exploration and development activities.
|
For
Fiscal Years Ended
September
30,
|
||||||||||
|
2006
|
2005
|
2004
|
||||||||
|
(In
Thousands)
|
||||||||||
|
Proved
properties
|
$
|
738,432
|
$
|
537,995
|
$
|
471,008
|
||||
|
Unproved
properties
|
51,001
|
15,581
|
15,582
|
|||||||
|
Total
proved and unproved properties
|
789,433
|
553,576
|
486,590
|
|||||||
|
Accumulated
DD&A and impairments
|
(258,869
|
)
|
(206,820
|
)
|
(168,482
|
)
|
||||
|
Net
capitalized costs
|
$
|
530,564
|
$
|
346,756
|
$
|
318,108
|
||||
D.
Costs Not Being Amortized
Following
is a summary of costs excluded from the depletion base at September 30, 2006,
by
year incurred. The Company is unable to predict either the timing of the
inclusion of these costs and the related natural gas and oil reserves in its
depletion computation or their potential future impact on depletion
rates.
|
For
Fiscal Years Ended September 30,
|
||||||||||||||||
|
2006
|
2005
|
2004
|
Prior
Years
|
Total
|
||||||||||||
|
(In
Thousands)
|
||||||||||||||||
|
Property
acquisition costs
|
$
|
37,975
|
$
|
3,740
|
$
|
5,348
|
$
|
3,938
|
$
|
51,001
|
||||||
|
Exploration
and development
|
-
|
-
|
-
|
-
|
-
|
|||||||||||
|
Total
|
$
|
37,975
|
$
|
3,740
|
$
|
5,348
|
$
|
3,938
|
$
|
51,001
|
||||||
E.
Reserve Quantity Information
The
Company’s proved oil and gas reserve quantities are based on estimates prepared
by third-party independent engineering consulting firms in conjunction with
the
Company’s engineers, geologists and geophysicists in accordance with guidelines
established by the SEC. The Company’s estimates of proved reserve quantities of
its properties are prepared by Netherland, Sewell & Associates, Inc., Miller
and Lents, Ltd. and Prator Bett, L.L.C. Each year, Peoples Energy Production
files estimates of oil and gas reserves with the U.S. Department of Energy
on
Form EIA-23. These estimates are consistent with the reserve data reported
in
this Note 19, with the exception that Form EIA-23 includes only gross reserves
from properties operated by the Company.
Estimated
quantities of proved oil and natural gas reserves and changes in net quantities
of proved developed and undeveloped oil and natural gas reserves were as
follows:
|
Gas
|
|||||||
|
Gas
|
Oil
|
Equivalent
|
|||||
|
MMcf
|
MBbls
|
MMcfe
|
|||||
|
(In
Thousands)
|
|||||||
|
Ending
Reserves—September 30, 2003
|
167,101
|
2,393
|
181,457
|
||||
|
Extensions,
discoveries and other additions
|
14,952
|
218
|
16,260
|
||||
|
Production
|
(24,515
|
)
|
(556
|
)
|
(27,853
|
)
|
|
|
Purchases
of reserves in place
|
22,170
|
393
|
24,526
|
||||
|
Revisions
of previous estimates
|
(5,663
|
)
|
121
|
(4,931
|
)
|
||
|
Sales
of reserves in place
|
-
|
-
|
-
|
||||
|
Ending
Reserves—September 30, 2004
|
174,045
|
2,569
|
189,459
|
||||
|
Extensions,
discoveries and other additions
|
19,038
|
146
|
19,914
|
||||
|
Production
|
(22,115
|
)
|
(406
|
)
|
(24,551
|
)
|
|
|
Purchases
of reserves in place
|
812
|
103
|
1,430
|
||||
|
Revisions
of previous estimates
|
(3,235
|
)
|
(168
|
)
|
(4,243
|
)
|
|
|
Sales
of reserves in place
|
(129
|
)
|
(41
|
)
|
(375
|
)
|
|
|
Ending
Reserves—September 30, 2005
|
168,416
|
2,203
|
181,634
|
||||
|
Extensions,
discoveries and other additions
|
27,843
|
269
|
29,455
|
||||
|
Production
|
(22,599
|
)
|
(352
|
)
|
(24,713
|
)
|
|
|
Purchases
of reserves in place
|
60,009
|
558
|
63,356
|
||||
|
Revisions
of previous estimates (1)
|
(15,198
|
)
|
(283
|
)
|
(16,893
|
)
|
|
|
Sales
of reserves in place
|
-
|
-
|
-
|
||||
|
Ending
Reserves—September 30, 2006
|
218,471
|
2,395
|
232,839
|
||||
|
Proved
Developed Reserves
|
|||||||
|
End
of year—September 30, 2004
|
135,088
|
2,059
|
147,442
|
||||
|
End
of year—September 30, 2005
|
132,742
|
1,569
|
142,156
|
||||
|
End
of year—September 30, 2006
|
137,976
|
1,706
|
148,212
|
| (1) |
A
substantial portion of the revisions at year end 2006 are a function
of
the gas pricing on
September
30, 2006. The index cash price used as of September 30, 2006
was
$4.18/MMBtu as
compared
to $14.71/MMBtu at September 30, 2005. This decreased gas price
resulted
in a downward
revision
of approximately 13.0 Bcfe of gas and associated
liquids.
|
Oil
and
natural gas reserves cannot be measured exactly. Estimates of oil and natural
gas reserves require extensive judgments of geologic and reservoir engineering
data and are generally less precise than other estimates made in connection
with
financial disclosures.
Proved
reserves are those quantities which, upon analysis of geological and engineering
data, appear with reasonable certainty to be recoverable in the future from
known oil and natural gas reservoirs under existing economic and operating
conditions. Proved developed reserves are those reserves which can be expected
to be recovered through existing wells with existing equipment and operating
methods. Proved undeveloped reserves
are
those
reserves which are expected to be recovered from new wells on undrilled acreage
or from existing wells where a relatively major expenditure is
required.
Assigning
monetary values to such estimates, which require extensive judgment, does not
reduce the subjectivity and changing nature of such reserve estimates. The
uncertainties inherent in the disclosure of oil and gas reserves are compounded
by applying additional estimates of the rates and timing of production and
the
costs that will be incurred in developing and producing the reserves. The
information set forth herein is therefore subjective and, since judgments are
involved, may not be comparable to estimates submitted by other oil and natural
gas producers. In addition, since prices and costs do not remain static and
no
price or cost escalations or de-escalations have been considered, the results
are not necessarily indicative of the estimated fair market value of estimated
proved reserves nor of estimated future cash flows.
F.
Standardized Measure of Discounted Future Net Cash Flows and Changes Therein
Relating to Proved Oil and Gas Reserves
Future
cash inflows are based on year-end cash prices for oil and gas and do not
include the effects of hedges. Operating costs, production and ad valorem taxes
and future development costs are based on current costs with no
escalation.
The
following table summarizes unaudited information concerning future net cash
flows for oil and gas reserves, net of income tax expense. Income tax expense
has been computed using expected future tax rates and giving effects to tax
deductions and credits available, under current laws, and which relate to oil
and gas producing activities. This information does not purport to present
the
fair market value of the Company’s oil and gas assets, but does present a
standardized measure of value disclosure concerning possible future net cash
flows that would result under the assumptions used.
|
For
Fiscal Years Ended
September
30,
|
||||||||||
|
2006
|
2005
|
2004
|
||||||||
|
(In
Thousands)
|
||||||||||
|
Future
cash flows
|
$
|
965,716
|
$
|
2,081,286
|
$
|
1,169,106
|
||||
|
Future
production and development costs
|
492,145
|
483,653
|
346,920
|
|||||||
|
Future
income tax expense
|
169,027
|
568,625
|
292,388
|
|||||||
|
Future
net cash flows
|
304,544
|
1,029,008
|
529,798
|
|||||||
|
Ten
percent annual discount for estimated
|
||||||||||
|
timing
of cash flows
|
153,566
|
439,640
|
207,299
|
|||||||
|
Standardized
measure of discounted future net cash
|
||||||||||
|
flows
relating to proved oil and natural gas reserves
|
$
|
150,978
|
$
|
589,368
|
$
|
322,499
|
||||
The
future net cash flows before income taxes for fiscal 2006, 2005 and 2004 are
$473.6 million, $1,597.6 million and $822.2 million, respectively, and after
discounting at 10% are $240.5 million, $917.5 million, $502.4 million,
respectively.
In
the
foregoing determination of future cash inflows, sales revenues for gas and
oil
were based on cash prices at year-end. The year-end gas prices utilized for
fiscal 2006, 2005 and 2004 were $4.18, $14.71 and $6.24 per MMbtu, respectively.
Future costs of developing and producing the proved gas and oil reserves
reported at the end of each year shown were based on costs determined at each
such year-end, assuming the continuation of existing economic conditions. Future
income taxes were computed by applying the appropriate year-end or future
statutory tax rate to future pretax net cash flows, less the tax basis of the
properties involved, and giving effect to tax deductions and permanent
differences. Estimates of future liabilities and receivables applicable to
oil
and gas commodity hedges are not reflected in future cash flows from proved
reserves as of the date of the reserve report.
A
summary
of the changes in the standardized measure of discounted future net cash flows
applicable to proved oil, natural gas liquids and gas reserves
follows.
|
For
Fiscal Years Ended
September
30,
|
|||||||
|
2006
|
2005
|
||||||
|
(In
Thousands)
|
|||||||
|
Beginning
of year
|
$
|
589,368
|
$
|
322,499
|
|||
|
Revisions
of previous estimates
|
|||||||
|
Changes
in prices and costs
|
(594,122
|
)
|
426,833
|
||||
|
Changes
in quantities
|
(91,819
|
)
|
(25,294
|
)
|
|||
|
Additions
to proved reserves resulting from extensions,
|
|||||||
|
discoveries
and improved recovery, less related costs
|
27,341
|
90,106
|
|||||
|
Purchases
of reserves in place
|
35,455
|
6,727
|
|||||
|
Sales
of reserves in place
|
-
|
(1,713
|
)
|
||||
|
Previously
estimated development costs incurred
|
|||||||
|
during
the period
|
34,479
|
37,880
|
|||||
|
Changes
in estimated future development costs
|
(14,008
|
)
|
(25,933
|
)
|
|||
|
Accretion
of discount
|
91,750
|
50,245
|
|||||
|
Sales
of oil and gas, net of production costs
|
(158,808
|
)
|
(137,422
|
)
|
|||
|
Net
change in income taxes
|
238,597
|
(148,181
|
)
|
||||
|
Timing
and other
|
(7,255
|
)
|
(6,379
|
)
|
|||
|
Net
change
|
(438,390
|
)
|
266,869
|
||||
|
End
of year
|
$
|
150,978
|
$
|
589,368
|
|||
ITEM
9. Changes in and Disagreements with Accountants on Accounting and Financial
Disclosure
None.
ITEM
9A. Controls and Procedures
Disclosure
Controls and Procedures
In
accordance with Exchange Act Rules 13a-15 and 15d-15, the Company, Peoples
Gas
and North Shore Gas carried out an evaluation, under the supervision and with
the participation of management, including Thomas M. Patrick, our principal
executive officer, and Thomas A. Nardi, our principal financial officer, of
the
effectiveness of our disclosure controls and procedures as of the end of the
period covered by this report. Based on this evaluation, our principal executive
officer and our principal financial officer concluded that our disclosure
controls and procedures were effective as of September 30, 2006 to ensure that
information required to be disclosed and filed or submitted under the Exchange
Act is recorded, processed, summarized and reported within the time periods
specified in the SEC's rules and forms.
Management’s
Report on Internal Control Over Financial Reporting
The
Company’s management is responsible for establishing and maintaining adequate
internal control over financial reporting. The Company’s internal control system
is designed to provide reasonable assurance to our management and Board of
Directors regarding the preparation and fair presentation of published financial
statements.
All
internal control systems, no matter how well designed, have inherent
limitations. Therefore, even those systems determined to be effective can
provide only reasonable assurance with respect to financial statement
preparation and presentations. Also, the effectiveness of internal control
over
financial reporting may deteriorate in future periods due to either changes
in
conditions or declining levels of compliance with policies or
procedures.
The
Company's management assessed the effectiveness of the Company's internal
control over financial reporting as of September 30, 2006. In making this
assessment, management used criteria set forth in
Internal
Control—Integrated Framework
issued
by the Committee of Sponsoring Organizations of the Treadway Commission. Based
on this assessment, management believes that, as of September 30, 2006, the
Company's internal control over financial reporting was effective based on
such
criteria.
Deloitte
& Touche LLP, an independent registered accounting firm, issued an audit
report on management’s assessment of the Company’s internal control over
financial reporting. This report appears below.
Changes
In Internal Control Over Financial Reporting
There
were no changes in the Company’s internal control over financial reporting
during the quarter ended September 30, 2006 that have materially affected or
are
reasonably likely to materially affect the Company’s internal control over
financial reporting.
Report
of Independent Registered Public Accounting Firm
To
the
Board of Directors and Shareholders of
Peoples
Energy Corporation
Chicago,
Illinois
We
have
audited management's assessment, included in the accompanying Management's
Report on Internal Control Over Financial Reporting, that Peoples Energy
Corporation and subsidiary companies (the “Company”) maintained effective
internal control over financial reporting as of September 30, 2006, based on
criteria established in
Internal
Control—Integrated Framework
issued
by the Committee of Sponsoring Organizations of the Treadway Commission. The
Company's management is responsible for maintaining effective internal control
over financial reporting and for its assessment of the effectiveness of internal
control over financial reporting. Our responsibility is to express an opinion
on
management's assessment and an opinion on the effectiveness of the Company's
internal control over financial reporting based on our audit.
We
conducted our audit in accordance with the standards of the Public Company
Accounting Oversight Board (United States). Those standards require that we
plan
and perform the audit to obtain reasonable assurance about whether effective
internal control over financial reporting was maintained in all material
respects. Our audit included obtaining an understanding of internal control
over
financial reporting, evaluating management's assessment, testing and evaluating
the design and operating effectiveness of internal control, and performing
such
other procedures as we considered necessary in the circumstances. We believe
that our audit provides a reasonable basis for our opinions.
A
company's internal control over financial reporting is a process designed by,
or
under the supervision of, the company's principal executive and principal
financial officers, or persons performing similar functions, and effected by
the
company's board of directors, management, and other personnel to provide
reasonable assurance regarding the reliability of financial reporting and the
preparation of financial statements for external purposes in
accordance
with generally accepted accounting principles. A company's internal control
over
financial reporting includes those policies and procedures that (1) pertain
to
the maintenance of records that, in reasonable detail, accurately and fairly
reflect the transactions and dispositions of the assets of the company; (2)
provide reasonable assurance that transactions are recorded as necessary to
permit preparation of financial statements in accordance with generally accepted
accounting principles, and that receipts and expenditures of the company are
being made only in accordance with authorizations of management and directors
of
the company; and (3) provide reasonable assurance regarding prevention or timely
detection of unauthorized acquisition, use, or disposition of the company's
assets that could have a material effect on the financial
statements.
Because
of the inherent limitations of internal control over financial reporting,
including the possibility of collusion or improper management override of
controls, material misstatements due to error or fraud may not be prevented
or
detected on a timely basis. Also, projections of any evaluation of the
effectiveness of the internal control over financial reporting to future periods
are subject to the risk that the controls may become inadequate because of
changes in conditions, or that the degree of compliance with the policies or
procedures may deteriorate.
In
our
opinion, management's assessment that the Company maintained effective internal
control over financial reporting as of September 30, 2006, is fairly stated,
in
all material respects, based on the criteria established in
Internal
Control—Integrated Framework
issued
by the Committee of Sponsoring Organizations of the Treadway Commission. Also
in
our opinion, the Company maintained, in all material respects, effective
internal control over financial reporting as of September 30, 2006, based on
the
criteria established in
Internal
Control—Integrated Framework
issued
by the Committee of Sponsoring Organizations of the Treadway
Commission.
We
have
also audited, in accordance with the standards of the Public Company Accounting
Oversight Board (United States), the consolidated balance sheets and
consolidated capitalization statements of the Company as of September 30, 2006
and 2005, and the related consolidated statements of operations, stockholders'
equity and cash flows for each of the three years in the period ended September
30, 2006, and the financial statement schedules of the Company for each of
the
three years in the period ended September 30, 2006, and our report dated
December 14, 2006 expressed an unqualified opinion on those financial statements
and financial statement schedules and included an explanatory paragraph
regarding the Company’s adoption of FASB Interpretation No. 47,
"Conditional Asset Retirement Obligations".
/s/
DELOITTE & TOUCHE LLP
DELOITTE
& TOUCHE LLP
Chicago,
Illinois
December
14, 2006
ITEM
9B. Other Information
None.
PART
III
ITEM
10. Directors, Executive Officers and Corporate Governance
Certain
information required in Part III—Item 10 of this Form 10-K will be incorporated
by reference to the Company's definitive proxy statement to be filed with the
SEC, or filed with the SEC as an amendment to this Form 10-K, within 120 days
of
the end of the Company's fiscal year.
Information
relating to the executive officers of the Company is set forth in Part I of
this
report under the caption “Executive Officers of the Company.”
The
Company has disclosed its code of ethics on its Web site at
www.PeoplesEnergy.com
.
ITEM
11. Executive Compensation
The
information required in Part III—Item 11 of this Form 10-K will be incorporated
by reference to the Company's definitive proxy statement to be filed with the
SEC, or filed with the SEC as an amendment to this Form 10-K, within 120 days
of
the end of the Company's fiscal year.
ITEM
12. Security Ownership of Certain Beneficial Owners and Management and Related
Stockholder Matters
The
information required in Part III—Item 12 of this Form 10-K will be incorporated
by reference to the Company's definitive proxy statement to be filed with the
SEC, or filed with the SEC as an amendment to this Form 10-K, within 120 days
of
the end of the Company's fiscal year.
EQUITY
COMPENSATION PLAN INFORMATION
|
Plan
Category
|
(A)
Number
of Securities to be Issued Upon Exercise of Outstanding Options,
Warrants
and Rights
|
(B)
Weighted-Average
Exercise Price of Outstanding Options, Warrants and Rights
|
(C)
Number
of Securities Remaining Available for Future Issuance under Equity
Compensation Plans (Excluding Securities Reflected in Column A)
|
|
Equity
compensation plans approved by security holders
|
563,006
(1) (2)
|
$38.91
|
651,717
(3)
|
|
Equity
compensation plans not approved by security holders (4)
|
107,632
(4)
|
$36.89
|
82,468
|
|
Total
|
670,638
|
--
|
734,185
|
| (1) |
Excludes
25,600 SARs outstanding and exercisable under the Company's LTIC
Plan. The
grant of a 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 Company common stock on the date the SAR is exercised over
the
fair market value of one share on the date the SAR was granted. No
security is issued upon the exercise of a
SAR.
|
| (2) |
Includes
94,106 shares equivalent held for the account of participants in
the
Company's DDC Plan.
|
| (3) |
Includes
600,360 shares remaining available for issuance under the Company's
2004
Incentive Compensation Plan for awards of performance shares, restricted
stock and RSUs, of which no more than 250,900 shares may be used
for
awards of restricted stock or RSUs that vest solely upon continued
service. Includes 51,357 share equivalents remaining available for
future
issuance under the DDC Plan.
|
| (4) |
Includes
41,632 deferred shares held for the account of participants in the
Company's DSOP.
|
ITEM
13. Certain Relationships, Related Transactions, and Director
Independence
The
information required in Part III—Item 13 of this Form 10-K will be incorporated
by reference to the Company's definitive proxy statement to be filed with the
SEC, or filed with the SEC as an amendment to this Form 10-K, within 120 days
of
the end of the Company's fiscal year.
ITEM
14. Principal Accounting Fees and Services
The
information required in Part III—Item 14 of this Form 10-K will be incorporated
by reference to the Company's definitive proxy statement to be filed with the
SEC, or filed with the SEC as an amendment to this Form 10-K, within 120 days
of
the end of the Company's fiscal year.
PART
IV
ITEM
15. Exhibits and Financial Statement Schedules
|
Page
|
|||||||
|
(a)
|
1.
|
Financial
Statements:
|
|||||
|
See
Part II,
Item
8.
|
59
|
||||||
|
2.
|
Financial
Statement Schedules:
|
||||||
|
Schedule
|
|||||||
|
Number
|
|||||||
|
II
|
Valuation
and Qualifying Accounts
|
135
|
|||||
|
3.
|
Exhibits
|
||||||
|
See
Exhibit Index
|
139
|
||||||
|
Schedule
II
|
|||||||||||||
|
VALUATION
AND QUALIFYING ACCOUNTS
(In
Thousands)
|
|||||||||||||
|
Peoples
Energy Corporation and Subsidiary Companies
|
|||||||||||||
|
Column
A
|
Column
B
|
Column
C
|
Column
D
|
Column
E
|
|||||||||
|
Additions
|
Deductions
|
||||||||||||
|
|
|
|
|
|
|
Charges
for the
|
|
|
|||||
|
Balance
at
|
|
|
Charged
|
|
|
purpose
for which the
|
|
|
|||||
|
beginning
|
|
|
to
costs and
|
|
|
reserves
or deferred
|
|
|
Balance
at end
|
||||
|
Description
|
of
period
|
|
|
expenses
|
|
|
credits
were created
|
|
|
of
period
|
|||
|
Fiscal
Year Ended September 30, 2006
|
|||||||||||||
|
RESERVES
|
|||||||||||||
|
(deducted
from assets in balance sheet):
|
|||||||||||||
|
Reserve
for uncollectible accounts
|
$
|
34,954
|
$
|
48,574
|
$
|
39,557
|
$
|
43,971
|
|||||
|
Fiscal
Year Ended September 30, 2005
|
|||||||||||||
|
RESERVES
|
|||||||||||||
|
(deducted
from assets in balance sheet):
|
|||||||||||||
|
Reserve
for uncollectible accounts
|
$
|
29,138
|
$
|
37,110
|
$
|
31,294
|
$
|
34,954
|
|||||
|
Fiscal
Year Ended September 30, 2004
|
|||||||||||||
|
RESERVES
|
|||||||||||||
|
(deducted
from assets in balance sheet):
|
|||||||||||||
|
Reserve
for uncollectible accounts
|
$
|
33,124
|
$
|
37,274
|
$
|
41,260
|
$
|
29,138
|
|||||
|
The
Peoples Gas Light and Coke Company and Subsidiary
Companies
|
|||||||||||||
|
Column
A
|
Column
B
|
|
|
Column
C
|
|
|
Column
D
|
|
|
Column
E
|
|||
|
Additions
|
|
|
Deductions
|
||||||||||
|
Charges
for the
|
|||||||||||||
|
Balance
at
|
|
|
Charged
|
|
|
purpose
for which the
|
|||||||
|
beginning
|
|
|
to
costs and
|
|
|
reserves
or deferred
|
|
|
Balance
at end
|
||||
|
Description
|
of
period
|
|
|
expenses
|
|
|
credits
were created
|
|
|
of
period
|
|||
|
Fiscal
Year Ended September 30, 2006
|
|||||||||||||
|
RESERVES
|
|||||||||||||
|
(deducted
from assets in balance sheet):
|
|||||||||||||
|
Reserve
for uncollectible accounts
|
$
|
31,947
|
$
|
45,681
|
$
|
36,997
|
$
|
40,631
|
|||||
|
Fiscal
Year Ended September 30, 2005
|
|||||||||||||
|
RESERVES
|
|||||||||||||
|
(deducted
from assets in balance sheet):
|
|||||||||||||
|
Reserve
for uncollectible accounts
|
$
|
26,536
|
$
|
34,796
|
$
|
29,385
|
$
|
31,947
|
|||||
|
Fiscal
Year Ended September 30, 2004
|
|||||||||||||
|
RESERVES
|
|||||||||||||
|
(deducted
from assets in balance sheet):
|
|||||||||||||
|
Reserve
for uncollectible accounts
|
$
|
29,207
|
$
|
35,306
|
$
|
37,977
|
$
|
26,536
|
|||||
|
North
Shore Gas Company and Subsidiary Companies
|
|||||||||||||
|
Column
A
|
Column
B
|
|
|
Column
C
|
|
|
Column
D
|
|
|
Column
E
|
|||
|
Additions
|
|
|
Deductions
|
||||||||||
|
Charges
for the
|
|||||||||||||
|
Balance
at
|
|
|
Charged
|
|
|
purpose
for which the
|
|
||||||
|
beginning
|
|
|
to
costs and
|
|
|
reserves
or deferred
|
|
|
Balance
at end
|
||||
|
Description
|
of
period
|
|
|
expenses
|
|
|
credits
were created
|
|
|
of
period
|
|||
|
Fiscal
Year Ended September 30, 2006
|
|||||||||||||
|
RESERVES
|
|||||||||||||
|
(deducted
from assets in balance sheet):
|
|||||||||||||
|
Reserve
for uncollectible accounts
|
$
|
1,455
|
$
|
2,185
|
$
|
1,513
|
$
|
2,127
|
|||||
|
Fiscal
Year Ended September 30, 2005
|
|||||||||||||
|
RESERVES
|
|||||||||||||
|
(deducted
from assets in balance sheet):
|
|||||||||||||
|
Reserve
for uncollectible accounts
|
$
|
943
|
$
|
1,563
|
$
|
1,051
|
$
|
1,455
|
|||||
|
Fiscal
Year Ended September 30, 2004
|
|||||||||||||
|
RESERVES
|
|||||||||||||
|
(deducted
from assets in balance sheet):
|
|||||||||||||
|
Reserve
for uncollectible accounts
|
$
|
1,012
|
$
|
1,177
|
$
|
1,246
|
$
|
943
|
|||||
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.
|
PEOPLES
ENERGY CORPORATION
|
|||
|
Date:
December
14, 2006
|
By:
/s/
THOMAS M. PATRICK
|
||
|
Thomas
M. Patrick
|
|||
|
Chairman
of the Board, President 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
December 14, 2006.
|
/s/
THOMAS M. PATRICK
|
Chairman
of the Board, President and Chief Executive
|
|
Thomas
M. Patrick
|
Officer
and Director (Principal Executive Officer)
|
|
/s/
THOMAS A. NARDI
|
Executive
Vice President and Chief Financial Officer
|
|
Thomas
A. Nardi
|
(Principal
Financial Officer)
|
|
/s/
LINDA M. KALLAS
|
Vice
President and Controller
|
|
Linda
M. Kallas
|
(Principal
Accounting Officer)
|
|
/s/
KEITH E. BAILEY
|
Director
|
|
Keith
E. Bailey
|
|
|
/s/
JAMES R. BORIS
|
Director
|
|
James
R. Boris
|
|
|
/s/
WILLIAM J. BRODSKY
|
Director
|
|
William
J. Brodsky
|
|
|
/s/
PASTORA SAN JUAN CAFFERTY
|
Director
|
|
Pastora
San Juan Cafferty
|
|
|
/s/
DIANA S. FERGUSON
|
Director
|
|
Diana
S. Ferguson
|
|
|
/s/
JOHN W. HIGGINS
|
Director
|
|
John
W. Higgins
|
|
|
/s/
DIPAK C. JAIN
|
Director
|
|
Dipak
C. Jain
|
|
|
/s/
MICHAEL E. LAVIN
|
Director
|
|
Michael
E. Lavin
|
|
|
/s/
HOMER J. LIVINGSTON, JR.
|
Director
|
|
Homer
J. Livingston, Jr.
|
|
|
/s/
RICHARD P. TOFT
|
Director
|
|
Richard
P. Toft
|
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.
|
THE
PEOPLES GAS LIGHT AND COKE COMPANY
|
||
|
Date:
December
14, 2006
|
By:
/s/
THOMAS M. PATRICK
|
|
|
Thomas
M. Patrick
|
||
|
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
December 14, 2006.
|
/s/
THOMAS M. PATRICK
|
Chairman
of the Board and Chief Executive
|
|
Thomas
M. Patrick
|
Officer
and Director (Principal Executive Officer)
|
|
/s/
THOMAS A. NARDI
|
Executive
Vice President, Chief Financial Officer and Director
|
|
Thomas
A. Nardi
|
(Principal
Financial Officer)
|
|
/s/
LINDA M. KALLAS
|
Vice
President and Controller
|
|
Linda
M. Kallas
|
(Principal
Accounting Officer)
|
|
/s/
DESIREE G. ROGERS
|
Director
|
|
Desiree
G. Rogers
|
|
|
/s/
WILLIAM E. MORROW
|
Director
|
|
William
E. Morrow
|
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:
December
14, 2006
|
By:
/s/
THOMAS M. PATRICK
|
||
|
Thomas
M. Patrick
|
|||
|
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
December 14, 2006.
|
/s/
THOMAS M. PATRICK
|
Chairman
of the Board and Chief Executive
|
|
Thomas
M. Patrick
|
Officer
and Director (Principal Executive Officer)
|
|
/s/
THOMAS A. NARDI
|
Executive
Vice President, Chief Financial Officer and Director
|
|
Thomas
A. Nardi
|
(Principal
Financial Officer)
|
|
/s/
LINDA M. KALLAS
|
Vice
President and Controller
|
|
Linda
M. Kallas
|
(Principal
Accounting Officer)
|
|
/s/
DESIREE G. ROGERS
|
Director
|
|
Desiree
G. Rogers
|
|
|
/s/
WILLIAM E. MORROW
|
Director
|
|
William
E. Morrow
|
Peoples
Energy Corporation 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)
|
Employment
and Retention Agreement dated August 31, 2006 between the Company
and
Thomas M. Patrick.
|
||
|
10(b)
|
Seasonal
Credit Agreement dated as of October 20, 2006 between the Company
and ABN
AMRO Bank N.V.
|
||
|
10(c)
|
Seasonal
Credit Agreement dated as of October 20, 2006 between the Company
and Bank
of America, N.A.
|
||
|
10(d)
|
Seasonal
Credit Agreement dated as of October 20, 2006 between the Company
and
JPMorgan Chase Bank.
|
||
|
10(e)
|
Amendment
Number One to the Amended and Restated Trust under the Company's
Directors
Deferred Compensation Plan, Directors Stock and Option Plan, Executive
Deferred Compensation Plan and Supplemental Retirement Benefit Plan,
dated
as of July 24, 2006.
|
||
|
12
|
Statement
re: Computation of Ratio of Earnings to Fixed charges for the Company,
Peoples Gas and North Shore Gas.
|
||
|
21
|
Subsidiaries
of the Company.
|
||
|
23(a)
|
Consent
of Deloitte & Touche LLP to incorporate by reference in Registration
Statement File Nos. 333-84594, 333-70702, 2-82760, 33-6369, 33-63193,
333-62070, 333-113204, 333-116192, and 333-17701.
|
||
|
23(b)
|
Consent
of Netherland, Sewell and Associates, Inc. to incorporate by reference
in
Registration Statement File Nos. 333-84594, 333-70702, 2-82760, 33-6369,
033-63193, 333-62070, 333-113204, 333-116192, and
333-17701.
|
||
|
23(c)
|
Consent
of Miller and Lents, Ltd. to incorporate by reference in Registration
Statement File Nos. 333-84594, 333-70702, 2-82760, 33-6369, 033-63193,
333-62070, 333-113204, 333-116192, and 333-17701.
|
||
|
23(d)
|
Prator
Bett, L.L.C. consent to incorporate by reference in Registration
Statement
File Nos. 333-84594, 333-70702, 2-82760, 33-6369, 033-63193, 333-62070,
333-113204, 333-116192, and 333-17701.
|
||
|
31(a)
|
Certification
of Thomas M. Patrick on behalf of the Company, Peoples Gas and North
Shore
Gas pursuant to 17 CFR 240.13a-14(a) or 17 CFR 240.15d-14(a), as
adopted
pursuant to Section 302 of the Sarbanes-Oxley Act of
2002.
|
||
|
31(b)
|
Certification
of Thomas A. Nardi on behalf of the Company, Peoples Gas and North
Shore
Gas pursuant to 17 CFR 240.13a-14(a) or 17 CFR 240.15d-14(a), as
adopted
pursuant to Section 302 of the Sarbanes-Oxley Act of
2002.
|
||
|
32(a)
|
Certification
of Thomas M. Patrick on behalf of the Company, Peoples Gas and North
Shore
Gas pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section
906
of the Sarbanes-Oxley Act of 2002.
|
||
|
32(b)
|
Certification
of Thomas A. Nardi on behalf of the Company, Peoples Gas and North
Shore
Gas pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section
906
of the Sarbanes-Oxley Act of 2002.
|
||
|
99
|
Form
11-K for the Employee Stock Purchase Plan of the Company for the
fiscal
year ended September 30, 2006.
|
||
Peoples
Energy Corporation and Subsidiary Companies
EXHIBIT
INDEX
(Continued)
|
Exhibit
Number
|
Description
of Document
|
||||
|
(b)
|
Exhibits
listed below have been filed heretofore with the SEC 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(a)
|
Articles
of Incorporation of the Company, as amended on March 3, 1995 (The
Company—Form 10-K for the fiscal year ended September 30, 1995, Exhibit
3(b)).
|
||||
|
3(b)
|
Articles
of Incorporation of Peoples Gas, as amended on April 24, 1995 (Peoples
Gas—Form 10-K for fiscal year ended 1995, Exhibit
3(b)).
|
||||
|
3(c)
|
Articles
of Incorporation of North Shore Gas, as amended on April 24, 1995
(North
Shore Gas—Form 10-K for fiscal year ended 1995, Exhibit
3(b)).
|
||||
|
3(d)
|
By-Laws
of the Company, as amended December 2, 2005 (The Company—Form 10-Q for the
quarter ended March 31, 2006, Exhibit 3).
|
||||
|
3(e)
|
By-Laws
of Peoples Gas, as amended August 10, 2004, (Peoples Gas—Form 10-K for the
fiscal year ended 2004, Exhibit 3(b)).
|
||||
|
3(f)
|
By-Laws
of North Shore Gas, as amended August 10, 2004, (North Shore Gas—Form 10-K
for the fiscal year ended 2004, Exhibit 3(d)).
|
||||
|
4(a)
|
Indenture
dated as of January 18, 2001, from the Company to Bank One Trust
Company
National Association (The Company—Form 10-Q for the quarter ended March
31, 2001, Exhibit 4(a)).
|
||||
|
4(b)
|
The
Peoples Gas Light and Coke Company First and Refunding Mortgage,
dated
January 2, 1926, from Chicago By-Product Coke Company to Illinois
Merchants Trust Company, Trustee, assumed by The Peoples Gas Light
and
Coke Company (Peoples Gas) by Indenture dated March 1, 1928 (Peoples
Gas—May 17, 1935, Exhibit B-6a, Exhibit B-6b A-2 File No. 2-2151, 1936);
Supplemental Indenture dated as of May 20, 1936, (Peoples Gas—Form
8-K for the year 1936, Exhibit B-6f); Supplemental Indenture dated
as of
March 10, 1950 (Peoples Gas—Form 8-K for the month of March 1950, Exhibit
B-6i); Supplemental Indenture dated as of June 1, 1951 (Peoples Gas—File
No. 2-8989, Post-Effective, Exhibit 7-4(b)); Supplemental Indenture
dated
as of August 15, 1967 (Peoples Gas—File No. 2-26983, Post-Effective,
Exhibit 2-4); Supplemental Indenture dated as of
September 15, 1970 (Peoples Gas—File No. 2-38168, Post-Effective
Exhibit 2-2); Supplemental Indenture dated June 1, 1995 (Peoples
Gas—Form
10-K for fiscal year ended September 30, 1995); Supplemental Indenture,
First and Refunding Mortgage Multi-Modal Bonds, Series HH of Peoples
Gas,
effective March 1, 2000 (Peoples Gas—Form 10-K for fiscal year ended
September 30, 2000, Exhibit 4(b)); Supplemental Indenture dated as
of
February 1, 2003, First and Refunding Mortgage 5% Bonds, Series KK
(The
Company and Peoples Gas—Form 10-Q for the quarter ended March 31, 2003,
Exhibit 4(a)); Supplemental Indenture dated as of February 1, 2003,
First
and Refunding Mortgage Multi-Modal Bonds, Series LL (The Company
and
Peoples Gas—Form 10-Q for the quarter ended March 31, 2003, Exhibit 4(b));
Supplemental Indenture dated as of
|
||||
Peoples
Energy Corporation and Subsidiary Companies
EXHIBIT
INDEX
(Continued)
|
Exhibit
Number
|
Description
of Document
|
|||
|
February
15, 2003, First and Refunding Mortgage 4.00% Bonds, Series MM-1 and
Series
MM-2 (The Company and Peoples Gas—Form 10-Q for the quarter ended March
31, 2003, Exhibit 4(c)); Supplemental Indenture dated as of April
15,
2003, First and Refunding Mortgage 4.625% Bonds, Series NN-1 and
Series
NN-2 (The Company and Peoples Gas—Form 10-Q for the quarter ended March
31, 2003, Exhibit 4(e)); Supplemental Indenture dated as of October
1,
2003, First and Refunding Mortgage Bonds, Series OO (The Company
and
Peoples Gas—Form 10-Q for the quarter ended December 31, 2003, Exhibit
4(a)); Peoples Gas Supplemental Indenture dated as of October 1,
2003,
First and Refunding Mortgage Bonds, Series PP (The Company and Peoples
Gas—Form 10-Q for the quarter ended December 31, 2003, Exhibit 4(b));
Peoples Gas Supplemental Indenture dated as of November 1, 2003,
First and
Refunding Mortgage Multi-Modal Bonds, Series QQ (The Company and
Peoples
Gas—Form 10-Q for the quarter ended December 31, 2003, Exhibit 4(c));
Peoples Gas Supplemental Indenture dated as of January 1, 2005, First
and
Refunding Mortgage Bonds, Series RR (The Company and Peoples Gas—Form 10-Q
for the quarter ended December 31, 2004, Exhibit 4(b)); Loan Agreement
between Peoples Gas and Illinois Development Finance Authority dated
October 1, 2003, Gas Supply Refunding Revenue Bonds, Series 2003C
(The
Company and Peoples Gas—Form 10-Q for the quarter ended December 31, 2003,
Exhibit 4(d)); Loan Agreement between Peoples Gas and Illinois Development
Finance Authority dated October 1, 2003, Gas Supply Refunding Revenue
Bonds, Series 2003D (The Company and Peoples Gas—Form 10-Q for the quarter
ended December 31, 2003, Exhibit 4(e)); Loan Agreement between Peoples
Gas
and Illinois Development Finance Authority dated November 1, 2003,
Gas
Supply Refunding Revenue Bonds, Series 2003E (The Company and Peoples
Gas—Form 10-Q for the quarter ended December 31, 2003, Exhibit 4(f));
Loan
Agreement between Peoples Gas and Illinois Finance Authority dated
as of
January 1, 2005 (The Company and Peoples Gas—Form 10-Q for the quarter
ended December 31, 2004, Exhibit 4(a)).
|
||||
|
4(c)
|
North
Shore Gas Company (North Shore) Indenture, dated as of
April 1, 1955, from North Shore 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); Fourth
Supplemental Indenture, dated as of May 1 1964 (North Shore—File No.
2-35965, Exhibit 4-1); Fifth Supplemental Indenture dated as of
February 1, 1970 (North Shore—File No. 2-35965, Exhibit 4-2);
Ninth Supplemental Indenture dated as of December 1, 1987 (North
Shore—Form 10-K for the fiscal year ended September 30, 1987, Exhibit 4);
Thirteenth Supplemental Indenture dated December 1, 1998 (North Shore
Gas—Form 10-Q for the quarter ended March 31, 1999, Exhibit 4); Fourteenth
Supplemental Indenture dated as of April 15, 2003, First Mortgage
4.625%
Bonds, Series N-1 and Series N-2 (The Company and North Shore Gas—Form
10-Q for the quarter ended March 31, 2003, Exhibit
4(g)).
|
|||
|
10(f)
|
Lease
dated October 20, 1993, between Prudential Plaza Associates, as
Landlord, and Peoples Gas, as Tenant (Peoples Gas—Form 10-Q for the
quarterly period ended December 31, 1993, Exhibit 10); Peoples
Gas fourth Amendment to Lease (for headquarters office space) between
SIP
North Stetson Venture, LLC and Peoples Gas dated August 13, 2003
(Peoples
Gas—Form 10-K for fiscal year ended September 30, 2003, Exhibit
10(h)).
|
|||
Peoples
Energy Corporation and Subsidiary Companies
EXHIBIT
INDEX
(Continued)
|
Exhibit
Number
|
Description
of Document
|
|||
|
10(g)
|
Credit
Agreement dated as of June 13, 2006, by and among Peoples Gas, the
financial institutions party hereto, and Bank of America, N.A., JPMorgan
Chase Bank, N.A., ABN AMRO Incorporated, US Bank National Association,
and
The Bank of Tokyo-Mitsubishi, Ltd. Chicago Branch, as agents (The
Company—Form 10-Q for the quarter ended June 30, 2006, Exhibit
10(a).
|
|||
|
10(h)
|
Insurance
Agreement between Peoples Gas and Ambac dated as of January 1, 2005
(The
Company and Peoples Gas—Form 10-Q for the quarter ended December 31, 2004,
Exhibit 10(b)).
|
|||
|
10(i)
|
Employee
Stock Purchase Plan, as amended, dated August 6, 1997 (The Company—Form
10-K for the fiscal year ended September 30, 1997, Exhibit
3(d)).
|
|||
|
10(j)
|
Executive
Deferred Compensation Plan, amended as of December 4, 2002 (The
Company—Form 10-Q for the quarter ended December 31, 2002, Exhibit
10(c)).
|
|||
|
10(k)
|
Directors
Stock and Option Plan as amended December 4, 2002 (The Company—Form 10-Q
for the quarterly period ended December 31, 2002, Exhibit
10(g)).
|
|||
|
10(l)
|
Amended
and Restated Trust under the Company's Directors Deferred Compensation
Plan, Directors Stock and Option Plan, Executive Deferred Compensation
Plan and Supplemental Retirement Benefit Plan, dated as of August
13, 2003
(The Company—Form 10-K for fiscal year ended September 30, 2003, Exhibit
10(a)).
|
|||
|
10(m)
|
Directors
Deferred Compensation Plan, as amended, dated April 7, 2004 (The
Company—Form 10-Q for the quarter ended June 30, 2004, Exhibit
10(a)).
|
|||
|
10(n)
|
The
Company's 2004 Incentive Compensation Plan, effective February 27,
2004
(The Company—Form 10-Q for the quarter ended March 31, 2004, Exhibit
10(a)).
|
|||
|
10(o)
|
The
Company’s Long-Term Incentive Compensation Plan, as amended December 4,
2002 (The Company—Form 10-Q for the quarter ended December 31, 2002,
Exhibit 10(d)).
|
|||
|
10(p)
|
Percentage
Interest Award granted to Steven W. Nance, dated December 17, 2001
(The
Company—Form 10-K for fiscal year ended September 30, 2003, Exhibit
10(b)).
|
|||
|
10(q)
|
Equity
Interest Award granted to Steven W. Nance, dated December 17, 2001
(The
Company—Form 10-K for fiscal year ended September 30, 2003, Exhibit
10(c)).
|
|||
Peoples
Energy Corporation and Subsidiary Companies
EXHIBIT
INDEX
(Continued)
|
Exhibit
Number
|
Description
of Document
|
|||
|
10(r)
|
Severance
Agreement between the Company and Desiree G. Rogers dated as of April
22,
2005 (The Company—Form 10-Q for the quarter ended June 30, 2005, Exhibit
10(a)); Severance Agreement between the Company and Steven W. Nance
dated
as of June 2, 2004 (The Company—Form 10-K for fiscal year ended September
30, 2004, Exhibit 10(e)); Severance Agreement between the Company
and
William E. Morrow dated as of June 2, 2004 (The Company—Form 10-K for
fiscal year ended September 30, 2004, Exhibit 10(f)); Severance Agreement
between the Company and Thomas A. Nardi dated as of June 2, 2004
(The
Company—Form 10-K for fiscal year ended September 30, 2004, Exhibit
10(g)).
|
|||
|
10(s)
|
Retainer
Agreement between the Company and Theodore R. Tetzlaff dated as of
June
30, 2005 (The Company—Form 10-Q for the quarter ended June 30, 2005,
Exhibit 10(b)).
|
|||
|
10(t)
|
Summary
Sheet for Officer Perquisites (The Company—Form 10-K for fiscal year ended
September 30, 2005, Exhibit 10(b)).
|
|||
|
10(u)
|
Order
of the Illinois Commerce Commission in Docket No. 01-0706 for North
Shore
Gas (the Company (The Company—Form 10-Q for the quarter ended March 31,
2006, Exhibit 10.1).
|
|||
|
10(v)
|
Order
of the Illinois Commerce Commission in Docket No. 02-0726 for North
Shore
Gas (The Company—Form 10-Q for the quarter ended March 31, 2006, Exhibit
10.2).
|
|||
|
10(w)
|
Order
of the Illinois Commerce Commission in Docket No. 02-0727 for Peoples
Gas
(The Company—Form 10-Q for the quarter ended March 31, 2006, Exhibit
10.3).
|
|||
|
10(x)
|
Order
of the Illinois Commerce Commission in Docket No. 03-0704 for North
Shore
Gas (The Company—Form 10-Q for the quarter ended March 31, 2006, Exhibit
10.4).
|
|||
|
10(y)
|
Order
of the Illinois Commerce Commission in Docket No. 03-0705 for Peoples
Gas
(The Company—Form 10-Q for the quarter ended March 31, 2006, Exhibit
10.5).
|
|||
|
10(z)
|
Order
of the Illinois Commerce Commission in Docket No. 04-0682 for North
Shore
Gas (The Company—Form 10-Q for the quarter ended March 31, 2006, Exhibit
10.6).
|
|||
|
10(aa)
|
Order
of the Illinois Commerce Commission in Docket No. 04-0683 for Peoples
Gas
(The Company—Form 10-Q for the quarter ended March 31, 2006, Exhibit
10.7).
|
|||