e10vk
UNITED STATES SECURITIES AND
EXCHANGE COMMISSION
Washington, D.C.
20549
Form 10-K
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ANNUAL REPORT PURSUANT TO
SECTION 13 or 15(d)
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OF THE SECURITIES EXCHANGE ACT
OF 1934
For the Fiscal Year Ended September 30, 2006
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TRANSITION REPORT PURSUANT TO
SECTION 13 OR 15(d)
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OF THE SECURITIES EXCHANGE ACT
OF 1934
For the Transition Period
from
to
Commission File Number 1-3880
National Fuel Gas
Company
(Exact name of registrant as
specified in its charter)
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New Jersey
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13-1086010
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(State or other jurisdiction
of
incorporation or organization)
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(I.R.S. Employer
Identification No.)
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6363 Main Street
Williamsville, New York
(Address of principal
executive offices)
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14221
(Zip Code)
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(716) 857-7000
Registrants telephone number, including area code
Securities registered pursuant to Section 12(b) of the
Act:
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Name of
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Each Exchange
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on Which
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Title of Each Class
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Registered
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Common Stock, $1 Par Value,
and
Common Stock Purchase Rights
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New York Stock Exchange
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Securities registered pursuant to Section 12(g) of the
Act:
None
Indicate by check mark if the registrant is a well-known
seasoned issuer, as defined in Rule 405 of the Securities
Act. Yes þ No o
Indicate by check mark if the registrant is not required to file
reports pursuant to Section 13 or Section 15
(d) of the
Act. Yes o No þ
Indicate by check mark whether the registrant (1) has filed
all reports required to be filed by Section 13 or 15(d) of
the Securities Exchange Act of 1934 during the preceding
12 months and (2) has been subject to such filing
requirements for the past
90 days. Yes þ No o
Indicate by check mark if disclosure of delinquent filers
pursuant to Item 405 of
Regulation S-K
is not contained herein, and will not be contained, to the best
of the registrants 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. o
Indicate by check mark whether the registrant is a large
accelerated filer, an accelerated filer, or a non-accelerated
filer. See definition of accelerated filer and large
accelerated filer in
Rule 12b-2
of the Exchange Act.
Large Accelerated
Filer þ Accelerated
Filer o Non-Accelerated
Filer o
Indicate by check mark whether the registrant is a shell company
(as defined in
Rule 12b-2
of the
Act). Yes o No þ
The aggregate market value of the voting stock held by
nonaffiliates of the registrant amounted to $2,715,600,700 as of
March 31, 2006.
Common Stock, $1 Par Value, outstanding as of
November 30, 2006: 82,385,144 shares.
DOCUMENTS
INCORPORATED BY REFERENCE
Portions of the registrants definitive Proxy Statement for
the Annual Meeting of Shareholders to be held February 15,
2007 are incorporated by reference into Part III of this
report.
Glossary
of Terms
Frequently used abbreviations,
acronyms, or terms used in this report:
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National
Fuel Gas Companies
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Company
The Registrant, the Registrant and its subsidiaries or the
Registrants subsidiaries as appropriate in the context of
the disclosure
Data-Track
Data-Track Account Services, Inc.
Distribution
Corporation National
Fuel Gas Distribution Corporation
Empire
Empire State Pipeline
ESNE
Energy Systems North East, LLC
Highland
Highland Forest
Resources, Inc.
Horizon
Horizon Energy
Development, Inc.
Horizon B.V.
Horizon Energy
Development B.V.
Horizon LFG
Horizon LFG, Inc.
Horizon Power
Horizon Power, Inc.
Leidy Hub
Leidy Hub, Inc.
Model City
Model City Energy, LLC
National Fuel
National Fuel Gas Company
NFR
National Fuel Resources,
Inc.
Registrant
National Fuel Gas Company
SECI
Seneca Energy Canada Inc.
Seneca
Seneca Resources
Corporation
Seneca Energy
Seneca Energy II,
LLC
Supply Corporation
National Fuel Gas Supply
Corporation
Toro
Toro Partners, LP
U.E.
United Energy, a.s.
EPA
United States
Environmental Protection Agency
FASB
Financial Accounting
Standards Board
FERC
Federal Energy
Regulatory Commission
NYPSC
State of New York Public
Service Commission
PaPUC
Pennsylvania Public
Utility Commission
SEC
Securities and Exchange
Commission
NTSB
National Transportation
Safety Board
APB 18
Accounting Principles
Board Opinion No. 18, The Equity Method of Accounting for
Investments in Common Stock
APB 20
Accounting Principles
Board Opinion No. 20, Accounting Changes
APB 25
Accounting Principles
Board Opinion No. 25, Accounting for Stock Issued to
Employees
Bbl
Barrel (of oil)
Bcf
Billion cubic feet (of
natural gas)
Bcf (or Mcf) Equivalent
The total heat value
(Btu) of natural gas and oil expressed as a volume of natural
gas. National Fuel uses a conversion formula of 1 barrel of
oil = 6 Mcf of natural gas.
Board foot
A measure of lumber
and/or
timber equal to 12 inches in length by 12 inches in
width by one inch in thickness.
Btu
British thermal unit;
the amount of heat needed to raise the temperature of one pound
of water one degree Fahrenheit.
Capital expenditure
Represents additions to
property, plant, and equipment, or the amount of money a company
spends to buy capital assets or upgrade its existing capital
assets.
Cashout revenues
A cash resolution of a
gas imbalance whereby a customer pays Supply Corporation for gas
the customer receives in excess of amounts delivered into Supply
Corporations system by the customers shipper.
CTA
Cumulative Foreign
Currency Translation Adjustment
Degree day
A measure of the
coldness of the weather experienced, based on the extent to
which the daily average temperature falls below a reference
temperature, usually 65 degrees Fahrenheit.
Derivative
A financial instrument
or other contract, the terms of which include an underlying
variable (a price, interest rate, index rate, exchange rate, or
other variable) and a notional amount (number of units, barrels,
cubic feet, etc.). The terms also permit for the instrument or
contract to be settled net, and no initial net investment is
required to enter into the financial instrument or contract.
Examples include futures contracts, options, no cost collars and
swaps.
Development costs
Costs incurred to obtain
access to proved reserves and to provide facilities for
extracting, treating, gathering and storing the oil and gas.
Development well
A well drilled to a
known producing formation in a previously discovered field.
Dth
Decatherm; one Dth of
natural gas has a heating value of 1,000,000 British thermal
units, approximately equal to the heating value of 1 Mcf of
natural gas.
Energy Policy Act
Energy Policy Act of 2005
Exchange Act
Securities Exchange Act
of 1934, as amended
Expenditures for long-lived
assets Includes capital
expenditures, stock acquisitions
and/or
investments in partnerships.
Exploration costs
Costs incurred in
identifying areas that may warrant examination, as well as costs
incurred in examining specific areas, including drilling
exploratory wells.
Exploratory well
A well drilled in
unproven or semi-proven territory for the purpose of
ascertaining the presence underground of a commercial
hydrocarbon deposit.
FIN
FASB Interpretation
Number
FIN 47
FASB Interpretation
No. 47, Accounting for Conditional Asset Retirement
Obligations an interpretation of SFAS 143.
FIN 48
FASB Interpretation
No. 48, Accounting for Uncertainty in Income
Taxes an interpretation of SFAS 109.
Firm transportation
and/or
storage The
transportation
and/or
storage service that a supplier of such service is obligated by
contract to provide and for which the customer is obligated to
pay whether or not the service is utilized.
GAAP
Accounting principles
generally accepted in the United States of America
Goodwill
An intangible asset
representing the difference between the fair value of a company
and the price at which a company is purchased.
Grid
The layout of the
electrical transmission system or a synchronized transmission
network.
Heavy oil
A type of crude
petroleum that usually is not economically recoverable in its
natural state without being heated or diluted.
Hedging
A method of minimizing
the impact of price, interest rate,
and/or
foreign currency exchange rate changes, often times through the
use of derivative financial instruments.
Hub
Location where pipelines
intersect enabling the trading, transportation, storage,
exchange, lending and borrowing of natural gas.
Interruptible transportation
and/or
storage The
transportation
and/or
storage service that, in accordance with contractual
arrangements, can be interrupted by the supplier of such
service, and for which the customer does not pay unless utilized.
LIBOR
London InterBank Offered
Rate
LIFO
Last-in,
first-out
Mbbl
Thousand barrels (of oil)
Mcf
Thousand cubic feet (of
natural gas)
MD&A
Managements
Discussion and Analysis of Financial Condition and Results of
Operations
MDth
Thousand decatherms (of
natural gas)
MMcf
Million cubic feet (of
natural gas)
MMcfe
Million cubic feet
equivalent
NYMEX
New York Mercantile
Exchange. An exchange which maintains a futures market for crude
oil and natural gas.
Order 636
An order issued by FERC
entitled Pipeline Service Obligations and Revisions to
Regulations Governing Self-Implementing Transportation Under
Part 284 of the Commissions Regulations.
Order
667-A
An order issued by FERC
to clarify Order 667 entitled Repeal of the Public Utility
Holding Company Act of 1935 and Enactment of the Public Utility
Holding Company Act of 2005.
Precedent Agreement
An agreement between a
pipeline company and a potential customer to sign a service
agreement after specified events (called conditions
precedent) happen, usually within a specified time.
Proved developed reserves
Reserves that can be
expected to be recovered through existing wells with existing
equipment and operating methods.
Proved undeveloped reserves
Reserves that are
expected to be recovered from new wells on undrilled acreage, or
from existing wells where a relatively major expenditure is
required to make these reserves productive.
PRP
Potentially responsible
party
PUHCA 1935
Public Utility Holding
Company Act of 1935
PUHCA 2005
Public Utility Holding
Company Act of 2005
Reserves
The unproduced but
recoverable oil
and/or gas
in place in a formation which has been proven by production.
Restructuring
Generally referring to
partial deregulation of the utility industry by
statutory or regulatory process. Restructuring of federally
regulated natural gas pipelines resulted in the separation (or
unbundled) of gas commodity service from
transportation service for wholesale and large- volume retail
markets. State restructuring programs attempt to extend the same
process to retail mass markets.
SFAS
Statement of Financial
Accounting Standards
SFAS 3
Statement of Financial
Accounting Standards No. 3, Reporting Accounting Changes in
Interim Financial Statements
SFAS 69
Statement of Financial
Accounting Standards No. 69, Disclosures about Oil and Gas
Producing Activities
SFAS 71
Statement of Financial
Accounting Standards No. 71, Accounting for the Effects of
Certain Types of Regulation
SFAS 87
Statement of Financial
Accounting Standards No. 87, Employers Accounting for
Pensions
SFAS 88
Statement of Financial
Accounting Standards No. 88, Employers Accounting for
Settlements and Curtailments of Defined Benefit Pension Plans
and for Termination Benefits
SFAS 106
Statement of Financial
Accounting Standards No. 106, Employers Accounting
for Postretirement Benefits Other Than Pensions.
SFAS 109
Statement of Financial
Accounting Standards No. 109, Accounting for Income Taxes
SFAS 123
Statement of Financial
Accounting Standards No. 123, Accounting for Stock-Based
Compensation
SFAS 123R
Statement of Financial
Accounting Standards No. 123R, Share-Based Payment
SFAS 132R
Statement of Financial
Accounting Standards No. 132R, Employers Disclosures
about Pensions and Other Postretirement Benefits
SFAS 133
Statement of Financial
Accounting Standards No. 133, Accounting for Derivative
Instruments and Hedging Activities
SFAS 142
Statement of Financial
Accounting Standards No. 142, Goodwill and Other Intangible
Assets
SFAS 143
Statement of Financial
Accounting Standards No. 143, Accounting for Asset
Retirement Obligations
SFAS 154
Statement of Financial
Accounting Standards No. 154, Accounting Changes and Error
Corrections
SFAS 157
Statement of Financial
Accounting Standards No. 157, Fair Value Measurements
SFAS 158
Statement of Financial
Accounting Standards No. 158, Employers Accounting
for Defined Benefit Pension and Other Postretirement Plans, an
amendment of SFAS 87, 88, 106, and 132R
Spot gas purchases
The purchase of natural
gas on a short-term basis.
Stock acquisitions
Investments in
corporations.
Unbundled service
A service that has been
separated from other services, with rates charged that reflect
only the cost of the separated service.
VEBA
Voluntary
Employees Beneficiary Association
WNC
Weather normalization
clause; a clause in utility rates which adjusts customer rates
to allow a utility to recover its normal operating costs
calculated at normal temperatures. If temperatures during the
measured period are warmer than normal, customer rates are
adjusted upward in order to recover projected operating costs.
If temperatures during the measured period are colder than
normal, customer rates are adjusted downward so that only the
projected operating costs will be recovered.
For the
Fiscal Year Ended September 30, 2006
CONTENTS
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This
Form 10-K
contains forward-looking statements as defined by
the Private Securities Litigation Reform Act of 1995.
Forward-looking statements should be read with the cautionary
statements included in this
Form 10-K
at item 7, MD&A, under the heading Safe Harbor
for Forward-Looking Statements. Forward-looking statements
are all statements other than statements of historical fact,
including, without limitation, those statements that are
designated with an asterisk (*) following the
statement, as well as those statements that are identified by
the use of the words anticipates,
estimates, expects, intends,
plans, predicts, projects,
and similar expressions.
PART I
The
Company and its Subsidiaries
National Fuel Gas Company (the Registrant), incorporated in
1902, is a holding company organized under the laws of the State
of New Jersey. Except as otherwise indicated below, the
Registrant owns directly or indirectly all of the outstanding
securities of its subsidiaries. Reference to the
Company in this report means the Registrant, the
Registrant and its subsidiaries or the Registrants
subsidiaries as appropriate in the context of the disclosure.
Also, all references to a certain year in this report relate to
the Companys fiscal year ended September 30 of that
year unless otherwise noted.
The Company is a diversified energy company consisting of five
reportable business segments.
1. The Utility segment operations are carried out by
National Fuel Gas Distribution Corporation (Distribution
Corporation), a New York corporation. Distribution Corporation
sells natural gas or provides natural gas transportation
services to approximately 727,000 customers through a local
distribution system located in western New York and northwestern
Pennsylvania. The principal metropolitan areas served by
Distribution Corporation include Buffalo, Niagara Falls and
Jamestown, New York and Erie and Sharon, Pennsylvania.
2. The Pipeline and Storage segment operations are carried
out by National Fuel Gas Supply Corporation (Supply
Corporation), a Pennsylvania corporation, and Empire State
Pipeline (Empire), a New York joint venture between two
wholly-owned subsidiaries of the Company. Supply Corporation
provides interstate natural gas transportation and storage
services for affiliated and nonaffiliated companies through
(i) an integrated gas pipeline system extending from
southwestern Pennsylvania to the New York-Canadian border at the
Niagara River and eastward to Ellisburg and Leidy, Pennsylvania,
and (ii) 28 underground natural gas storage fields owned
and operated by Supply Corporation as well as four other
underground natural gas storage fields owned and operated
jointly with various other interstate gas pipeline companies.
Empire, an intrastate pipeline company, transports natural gas
for Distribution Corporation and for other utilities, large
industrial customers and power producers in New York State.
Empire owns a
157-mile
pipeline that extends from the United States/Canadian border at
the Niagara River near Buffalo, New York to near Syracuse, New
York. The Company acquired Empire in February 2003.
3. The Exploration and Production segment operations are
carried out by Seneca Resources Corporation (Seneca), a
Pennsylvania corporation. Seneca is engaged in the exploration
for, and the development and purchase of, natural gas and oil
reserves in California, in the Appalachian region of the United
States, and in the Gulf Coast region of Texas, Louisiana, and
Alabama, including offshore areas in federal waters and some
state waters. Also, Exploration and Production operations are
conducted in the provinces of Alberta, Saskatchewan and British
Columbia in Canada by Seneca Energy Canada Inc. (SECI), an
Alberta, Canada corporation and a subsidiary of Seneca. At
September 30, 2006, the Company had U.S. and Canadian
reserves of 58,018 Mbbl of oil and 232,575 MMcf of natural
gas.
4. The Energy Marketing segment operations are carried out
by National Fuel Resources, Inc. (NFR), a New York corporation,
which markets natural gas to industrial, commercial, public
authority and residential end-users in western and central New
York and northwestern Pennsylvania, offering competitively
priced energy and energy management services for its customers.
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5. The Timber segment operations are carried out by
Highland Forest Resources, Inc. (Highland), a New York
corporation, and by a division of Seneca known as its Northeast
Division. This segment markets timber from its New York and
Pennsylvania land holdings, owns two sawmill operations in
northwestern Pennsylvania and processes timber consisting
primarily of high quality hardwoods. At September 30, 2006,
the Company owned approximately 100,000 acres of timber
property and managed an additional 4,000 acres of timber
rights.
Financial information about each of the Companys business
segments can be found in Item 7, MD&A and also in
Item 8 at Note J Business Segment
Information.
The Companys other direct wholly-owned subsidiaries are
not included in any of the five reportable business segments and
consist of the following:
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Horizon Energy Development, Inc. (Horizon), a New York
corporation formed to engage in foreign and domestic energy
projects through investments as a sole or substantial owner in
various business entities. These entities include Horizons
wholly-owned subsidiary, Horizon Energy Holdings, Inc., a New
York corporation, which owns 100% of Horizon Energy Development
B.V. (Horizon B.V.). Horizon B.V. is a Dutch company that is in
the process of winding up or selling certain power development
projects in Europe;
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Horizon LFG, Inc. (Horizon LFG), a New York corporation engaged
through subsidiaries in the purchase, sale and transportation of
landfill gas in Ohio, Michigan, Kentucky, Missouri, Maryland and
Indiana. Horizon LFG and one of its wholly owned subsidiaries
own all of the partnership interests in Toro Partners, LP
(Toro), a limited partnership which owns and operates
short-distance landfill gas pipeline companies. The Company
acquired Toro in June 2003;
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Leidy Hub, Inc. (Leidy Hub), a New York corporation formed to
provide various natural gas hub services to customers in the
eastern United States;
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Data-Track Account Services, Inc. (Data-Track), a New York
corporation formed to provide collection services principally
for the Companys subsidiaries;
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Horizon Power, Inc. (Horizon Power), a New York corporation
which is an exempt wholesale generator under PUHCA
2005 and is developing or operating mid-range independent power
production facilities and landfill gas electric generation
facilities; and
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Empire Pipeline, Inc., a New York corporation formed in 2005 to
be the surviving corporation of a planned future merger with
Empire, which is expected to occur after construction of the
Empire Connector project (described below under the heading
Rates and Regulation and under Item 7, MD&A
under the headings Investing Cash Flow and
Rate and Regulatory Matters).*
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No single customer, or group of customers under common control,
accounted for more than 10% of the Companys consolidated
revenues in 2006.
Rates and
Regulation
The Registrant is a holding company as defined under PUHCA 2005.
PUHCA 2005 repealed PUHCA 1935, to which the Company was
formerly subject, and granted the FERC and state public utility
commissions access to certain books and records of companies in
holding company systems. Pursuant to the FERCs regulations
under PUHCA 2005, the Company and its subsidiaries are exempt
from the FERCs books and records regulations under PUHCA
2005.
The Utility segments rates, services and other matters are
regulated by the NYPSC with respect to services provided within
New York and by the PaPUC with respect to services provided
within Pennsylvania. For additional discussion of the Utility
segments rates and regulation, see Item 7, MD&A
under the heading Rate and Regulatory Matters and
Item 8 at
Note C-Regulatory
Matters.
The Pipeline and Storage segments rates, services and
other matters are currently regulated by the FERC with respect
to Supply Corporation and by the NYPSC with respect to Empire.
On October 11, 2005, Empire
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filed an application with the FERC for the authority to build
and operate an extension of its natural gas pipeline (the Empire
Connector). If the FERC grants that application and the Company
builds and commences operations of the Empire Connector, Empire
will at that time become a FERC-regulated pipeline company.* For
additional discussion of the Pipeline and Storage segments
rates and regulation, see Item 7, MD&A under the
heading Rate and Regulatory Matters and Item 8
at
Note C-Regulatory
Matters. For further discussion of the Empire Connector project,
refer to Item 7, MD&A under the headings
Investing Cash Flow and Rate and Regulatory
Matters.
The discussion under Item 8 at
Note C-Regulatory
Matters includes a description of the regulatory assets and
liabilities reflected on the Companys Consolidated Balance
Sheets in accordance with applicable accounting standards. To
the extent that the criteria set forth in such accounting
standards are not met by the operations of the Utility segment
or the Pipeline and Storage segment, as the case may be, the
related regulatory assets and liabilities would be eliminated
from the Companys Consolidated Balance Sheets and such
accounting treatment would be discontinued.
In addition, the Company and its subsidiaries are subject to the
same federal, state and local (including foreign) regulations on
various subjects, including environmental matters, to which
other companies doing similar business in the same locations are
subject.
The
Utility Segment
The Utility segment contributed approximately 36.1% of the
Companys 2006 net income available for common stock.
Additional discussion of the Utility segment appears below in
this Item 1 under the headings Sources and
Availability of Raw Materials, Competition: The
Utility Segment and Seasonality, in
Item 7, MD&A and in Item 8, Financial Statements
and Supplementary Data.
The
Pipeline and Storage Segment
The Pipeline and Storage segment contributed approximately 40.3%
of the Companys 2006 net income available for common
stock.
Supply Corporation has service agreements for all of its firm
storage capacity, which totals approximately 68,408 MDth. The
Utility segment has contracted for 27,865 MDth or 40.7% of the
total firm storage capacity, and the Energy Marketing segment
accounts for another 3,888 MDth or 5.7% of the total firm
storage capacity. Nonaffiliated customers have contracted for
the remaining 36,655 MDth or 53.6% of the total firm storage
capacity. Following an industry trend, most of Supply
Corporations storage and transportation services are
performed under contracts that allow Supply Corporation or the
shipper to terminate the contract upon six or twelve
months notice effective at the end of the contract term.
The contracts also typically include evergreen
language designed to allow the contracts to extend
year-to-year
at the end of the primary term. At the beginning of 2007, 95.9%
of Supply Corporations total firm storage capacity was
committed under contracts that, subject to 2006 shipper or
Supply Corporation notifications, could have been terminated
effective in 2007. Supply Corporation neither issued nor
received any contract termination notices in 2006, however, so
it does not expect any storage contract terminations effective
in 2007.* In 2006, the increased value of market-area storage
afforded Supply Corporation the opportunity to eliminate a
significant number of monetary rate discounts and to sign
certain multi-year primary term extensions.
Supply Corporations firm transportation capacity is not a
fixed quantity, due to the diverse weblike nature of its
pipeline system, and is subject to change as the market
identifies different transportation paths and receipt/delivery
point combinations. Supply Corporation currently has firm
transportation service agreements for approximately 1,995 MDth
per day (contracted transportation capacity). The Utility
segment accounts for approximately 1,092 MDth per day or 54.7%
of contracted transportation capacity, and the Energy Marketing
segment represents another 99 MDth per day or 5.0% of contracted
transportation capacity. The remaining 804 MDth or 40.3% of
contracted transportation capacity is subject to firm contracts
with nonaffiliated customers.
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At the beginning of 2007, 56.9% of Supply Corporations
contracted transportation capacity was committed under affiliate
contracts that were scheduled to expire in 2007 or, subject to
2006 shipper or Supply Corporation notifications, could have
been terminated effective in 2007. Based on contract expirations
and termination notices received in 2006 for 2007 termination,
and taking into account any known contract additions, contracted
transportation capacity with affiliates is expected to decrease
0.8% in 2007.* Similarly, 28.4% of contracted transportation
capacity was committed under unaffiliated shipper contracts that
were scheduled to expire in 2007 or, subject to 2006 shipper or
Supply Corporation notifications, could have been terminated
effective in 2007. Based on contract expirations and termination
notices received in 2006 for 2007 termination, and taking into
account any known contract additions, contracted transportation
capacity with unaffiliated shippers is expected to decrease 2.4%
in 2007.* Supply Corporation previously has been successful in
marketing and obtaining executed contracts for available
transportation capacity (at discounted rates when necessary),
and expects its success to continue.*
Empire has service agreements for the
2006-2007
winter period for all of its firm transportation capacity, which
totals approximately 575 MDth per day. Empire provides service
under both annual (12 months per year) and seasonal (winter
or summer only) contracts. Approximately 88.7% of Empires
firm contracted capacity is on an annual long-term basis. Annual
long-term agreements representing 0.5% of Empires firm
contracted capacity expire in 2007. Approximately 3.4% of
Empires firm contracted capacity is under multi-year
seasonal contracts, none of which expire in 2007. The remaining
capacity, which represents 7.9% of Empires firm contracted
capacity, is under single season or annual contracts which will
expire before the end of 2007. Empire expects that all of this
expiring capacity will be re-contracted under seasonal
and/or
annual arrangements for future contracting periods.* The Utility
segment accounts for approximately 8.6% of Empires firm
contracted capacity, and the Energy Marketing segment accounts
for approximately 1.7% of Empires firm contracted
capacity, with the remaining 89.7% of Empires firm
contracted transportation capacity subject to contracts with
nonaffiliated customers.
Additional discussion of the Pipeline and Storage segment
appears below under the headings Sources and Availability
of Raw Materials, Competition: The Pipeline and
Storage Segment and Seasonality, in
Item 7, MD&A and in Item 8, Financial Statements
and Supplementary Data.
The
Exploration and Production Segment
The Exploration and Production segment contributed approximately
15.2% of the Companys 2006 net income available for
common stock.
Additional discussion of the Exploration and Production segment
appears below under the headings Sources and Availability
of Raw Materials and Competition: The Exploration
and Production Segment, in Item 7, MD&A and in
Item 8, Financial Statements and Supplementary Data.
The
Energy Marketing Segment
The Energy Marketing segment contributed approximately 4.2% of
the Companys 2006 net income available for common
stock.
Additional discussion of the Energy Marketing segment appears
below under the headings Sources and Availability of Raw
Materials, Competition: The Energy Marketing
Segment and Seasonality, in Item 7,
MD&A and in Item 8, Financial Statements and
Supplementary Data.
The
Timber Segment
The Timber segment contributed approximately 4.1% of the
Companys 2006 net income available for common stock.
Additional discussion of the Timber segment appears below under
the headings Sources and Availability of Raw
Materials, Competition: The Timber Segment and
Seasonality, in Item 7, MD&A and in
Item 8, Financial Statements and Supplementary Data.
6
All Other
Category and Corporate Operations
The All Other category and Corporate operations contributed less
than 1% of the Companys 2006 net income available for
common stock.
Additional discussion of the All Other category and Corporate
operations appears below in Item 7, MD&A and in
Item 8, Financial Statements and Supplementary Data.
Discontinued
Operations
In July 2005, Horizon B.V. sold its entire 85.16% interest in
United Energy, a.s. (U.E.), a district heating and electric
generation business in the Czech Republic. United Energys
operations are presented in the Companys financial
statements as discontinued operations.
Additional discussion of the Companys discontinued
operations appears in Item 7, MD&A and in Item 8,
Financial Statements and Supplementary Data.
Sources
and Availability of Raw Materials
Natural gas is the principal raw material for the Utility
segment. In 2006, the Utility segment purchased 74.5 Bcf of
gas for core market demand. Gas purchased from producers and
suppliers in the southwestern United States and Canada under
firm contracts (seasonal and longer) accounted for 82% of these
purchases. Purchases of gas on the spot market (contracts for
one month or less) accounted for 18% of the Utility
segments 2006 purchases. Purchases from Chevron Natural
Gas (16%), ConocoPhillips Company (15%), Total Gas &
Power North America Inc. (11%) and Anadarko Energy Services
Company (11%) accounted for 53% of the Utilitys 2006 gas
purchases. No other producer or supplier provided the Utility
segment with more than 10% of its gas requirements in 2006.
Supply Corporation transports and stores gas owned by its
customers, whose gas originates in the southwestern,
mid-continent and Appalachian regions of the United States as
well as in Canada. Empire transports gas owned by its customers,
whose gas originates in the southwestern and mid-continent
regions of the United States as well as in Canada. Additional
discussion of proposed pipeline projects appears below under
Competition: The Pipeline and Storage Segment and in
Item 7, MD&A.
The Exploration and Production segment seeks to discover and
produce raw materials (natural gas, oil and hydrocarbon liquids)
as further described in this report in Item 7, MD&A and
Item 8 at
Note J-Business
Segment Information and
Note O-Supplementary
Information for Oil and Gas Producing Activities.
With respect to the Timber segment, Highland requires an
adequate supply of timber to process in its sawmill and kiln
operations. Fifty-five percent of the timber processed during
2006 in Highlands sawmill operations came from land owned
by the Companys subsidiaries, and 45% came from outside
sources. In addition, Highland purchased approximately eight
million board feet of green lumber to augment lumber supply for
its kiln operations.
The Energy Marketing segment depends on an adequate supply of
natural gas to deliver to its customers. In 2006, this segment
purchased 47 Bcf of natural gas, of which 45 Bcf
served core market demands. The remaining 2 Bcf largely
represents gas used in operations. The gas purchased by the
Energy Marketing segment originates in either the Appalachian or
mid-continent regions of the United States or in Canada.
Competition
Competition in the natural gas industry exists among providers
of natural gas, as well as between natural gas and other sources
of energy. The natural gas industry has gone through various
stages of regulation. Apart from environmental and state utility
commission regulation, the natural gas industry has experienced
considerable deregulation. This has enhanced the competitive
position of natural gas relative to other energy sources, such
as fuel oil or electricity, since some of the historical
regulatory impediments to adding customers and responding to
market forces have been removed. In addition, management
believes that the environmental advantages of natural gas have
enhanced its competitive position relative to other fuels.
7
The electric industry has been moving toward a more competitive
environment as a result of changes in federal law in 1992 and
initiatives undertaken by the FERC and various states. It
remains unclear what the impact of any further restructuring in
response to legislation or other events may be.*
The Company competes on the basis of price, service and
reliability, product performance and other factors. Sources and
providers of energy, other than those described under this
Competition heading, do not compete with the Company
to any significant extent.*
Competition:
The Utility Segment
The changes precipitated by the FERCs restructuring of the
natural gas industry in Order No. 636, which was issued in
1992, continue to reshape the roles of the gas utility industry
and the state regulatory commissions. In both New York and
Pennsylvania, Distribution Corporation has retained substantial
numbers of residential and small commercial customers as sales
customers. However, for many years almost all the industrial and
a substantial number of commercial customers have purchased
their gas supplies from marketers and utilized Distribution
Corporations gas transportation services. Regulators in
both New York and Pennsylvania have adopted retail competition
programs for natural gas supply purchases by the remaining
utility sales customers. To date, the Utility segments
traditional distribution function remains largely unchanged;
however, the NYPSC has stepped up its efforts to encourage
customer choice at the retail residential level. In New York,
the Utility segment has instituted a number of programs to
accommodate more widespread customer choice. In Pennsylvania,
the PaPUC issued a report in October 2005 that concluded
effective competition does not exist in the retail
natural gas supply market statewide. In 2006, the PaPUC
reconvened a stakeholder group to explore ways to increase the
participation of retail customers in choice programs. The
findings of the stakeholder group are expected to be presented
to the PaPUC during 2007.
Competition for large-volume customers continues with local
producers or pipeline companies attempting to sell or transport
gas directly to end-users located within the Utility
segments service territories without use of the
utilitys facilities (i.e., bypass). In addition,
competition continues with fuel oil suppliers and may increase
with electric utilities making retail energy sales.*
The Utility segment competes, through its unbundled flexible
services, in its most vulnerable markets (the large commercial
and industrial markets).* The Utility segment continues to
(i) develop or promote new sources and uses of natural gas
or new services, rates and contracts and (ii) emphasize and
provide high quality service to its customers.
Competition:
The Pipeline and Storage Segment
Supply Corporation competes for market growth in the natural gas
market with other pipeline companies transporting gas in the
northeast United States and with other companies providing gas
storage services. Supply Corporation has some unique
characteristics which enhance its competitive position. Its
facilities are located adjacent to Canada and the northeastern
United States and provide part of the link between gas-consuming
regions of the eastern United States and gas-producing regions
of Canada and the southwestern, southern and other continental
regions of the United States. This location offers the
opportunity for increased transportation and storage services in
the future.*
Empire competes for market growth in the natural gas market with
other pipeline companies transporting gas in the northeast
United States and upstate New York in particular. Empire is
particularly well situated to provide transportation from
Canadian sourced gas, and its facilities are readily expandable.
These characteristics provide Empire the opportunity to compete
for an increased share of the gas transportation markets. As
noted above, Empire is pursuing the Empire Connector project,
which would expand its natural gas pipeline to serve new markets
in New York and elsewhere in the Northeast.* For further
discussion of this project, refer to Item 7, MD&A under
the headings Investing Cash Flow and Rate and
Regulatory Matters.
8
Competition:
The Exploration and Production Segment
The Exploration and Production segment competes with other oil
and natural gas producers and marketers with respect to sales of
oil and natural gas. The Exploration and Production segment also
competes, by competitive bidding and otherwise, with other oil
and natural gas producers with respect to exploration and
development prospects.
To compete in this environment, each of Seneca and SECI
originates and acts as operator on certain of its prospects,
seeks to minimize the risk of exploratory efforts through
partnership-type arrangements, utilizes technology for both
exploratory studies and drilling operations, and seeks market
niches based on size, operating expertise and financial criteria.
Competition:
The Energy Marketing Segment
The Energy Marketing segment competes with other marketers of
natural gas and with other providers of energy management
services. Competition in this area is well developed with regard
to price and services from local, regional and, more recently,
national marketers.
Competition:
The Timber Segment
With respect to the Timber segment, Highland competes with other
sawmill operations and with other suppliers of timber, logs and
lumber. These competitors may be local, regional, national or
international in scope. This competition, however, is primarily
limited to those entities which either process or supply high
quality hardwoods species such as cherry, oak and maple as
veneer logs, saw logs, export logs or lumber ultimately used in
the production of high-end furniture, cabinetry and flooring.
The Timber segment sells its products in domestic and
international markets.
Seasonality
Variations in weather conditions can materially affect the
volume of gas delivered by the Utility segment, as virtually all
of its residential and commercial customers use gas for space
heating. The effect that this has on Utility segment margins in
New York is mitigated by a WNC, which covers the eight-month
period from October through May. Weather that is more than 2.2%
warmer than normal results in a surcharge being added to
customers current bills, while weather that is more than
2.2% colder than normal results in a refund being credited to
customers current bills.
Volumes transported and stored by Supply Corporation may vary
materially depending on weather, without materially affecting
its revenues. Supply Corporations allowed rates are based
on a straight fixed-variable rate design which allows recovery
of fixed costs in fixed monthly reservation charges. Variable
charges based on volumes are designed to recover only the
variable costs associated with actual transportation or storage
of gas.
Volumes transported by Empire may vary materially depending on
weather, and can have a moderate effect on its revenues.
Empires allowed rates are based on a modified
fixed-variable rate design, which allows recovery of most fixed
costs in fixed monthly reservation charges. Variable charges
based on volumes are designed to recover variable costs
associated with actual transportation of gas, to recover return
on equity, and to recover income taxes.
Variations in weather conditions can materially affect the
volume of gas consumed by customers of the Energy Marketing
segment. Volume variations can have a corresponding impact on
revenues within this segment.
The activities of the Timber segment vary on a seasonal basis
and are subject to weather constraints. Traditionally, the
timber harvesting season occurs when timber growth is dormant
and runs from approximately September to March. The operations
conducted in the summer months typically focus on pulpwood and
on thinning out lower-grade or lower value trees from the timber
stands to encourage the growth of higher-grade or higher value
trees.
9
Capital
Expenditures
A discussion of capital expenditures by business segment is
included in Item 7, MD&A under the heading
Investing Cash Flow.
Environmental
Matters
A discussion of material environmental matters involving the
Company is included in Item 7, MD&A under the heading
Environmental Matters and in Item 8,
Note H Commitments and Contingencies.
Miscellaneous
The Company and its wholly-owned or majority-owned subsidiaries
had a total of 1,993 full-time employees at
September 30, 2006, with 1,970 employees in all of its
U.S. operations and 23 employees in its Canadian operations
at SECI. This is a decrease of 2.5% from the 2,044 total
employed at September 30, 2005.
Agreements covering employees in collective bargaining units in
New York are scheduled to expire in February 2008. Certain
agreements covering employees in collective bargaining units in
Pennsylvania are scheduled to expire in April 2009, and other
agreements covering employees in collective bargaining units in
Pennsylvania are scheduled to expire in May 2009.
The Utility segment has numerous municipal franchises under
which it uses public roads and certain other
rights-of-way
and public property for the location of facilities. When
necessary, the Utility segment renews such franchises.
The Company makes its annual report on
Form 10-K,
quarterly reports on
Form 10-Q,
current reports on
Form 8-K,
and any amendments to those reports, available free of charge on
the Companys internet website, www.nationalfuelgas.com, as
soon as reasonably practicable after they are electronically
filed with or furnished to the SEC. The information available at
the Companys internet website is not part of this
Form 10-K
or any other report filed with or furnished to the SEC.
Executive
Officers of the Company as of November 15, 2006 (except as
otherwise noted)(1)
|
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Current Company
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Positions and
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Other Material
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Business Experience
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Name and Age (as of
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During Past
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November 15, 2006)
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Five Years
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Philip C. Ackerman
(62)
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Chairman of the Board of Directors
since January 2002; Chief Executive Officer since October 2001;
and President of Horizon since September 1995. Mr. Ackerman has
served as a Director of the Company since March 1994, and
previously served as President of the Company from July 1999
through January 2006.
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David F. Smith
(53)
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President of the Company since
February 2006; Chief Operating Officer of the Company since
February 2006; President of Supply Corporation since April 2005;
President of Empire since April 2005. Mr. Smith previously
served as Vice President of the Company from April 2005 through
January 2006; President of Distribution Corporation from July
1999 to April 2005; and Senior Vice President of Supply
Corporation from July 2000 to April 2005.
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10
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Current Company
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Positions and
|
|
|
Other Material
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|
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Business Experience
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Name and Age (as of
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During Past
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November 15, 2006)
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Five Years
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Ronald J. Tanski
(54)
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Treasurer and Principal Financial
Officer of the Company since April 2004; President of
Distribution Corporation since February 2006; Treasurer of
Distribution Corporation since April 2004; Secretary and
Treasurer of Supply Corporation since April 2004; Secretary and
Treasurer of Horizon since February 1997. Mr. Tanski
previously served as Controller of the Company from February
2003 through March 2004; Senior Vice President of Distribution
Corporation from July 2001 through January 2006; and Controller
of Distribution Corporation from February 1997 through March
2004.
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Matthew D. Cabell
(48)
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President of Seneca effective
December 11, 2006. Mr. Cabell previously served as
Executive Vice President and General Manager of Marubeni
Oil & Gas (USA) Inc., an exploration and production
company with assets of over $1,000,000,000, as Vice President of
Randall & Dewey, Inc., a major oil and gas transaction
advisory firm, as an independent consultant assisting oil
companies in upstream acquisition and divestment transactions as
well as Gulf of Mexico entry strategy, and as Vice President,
Gulf of Mexico Exploration for Texaco Corporation.
Mr. Cabells prior employers are not subsidiaries or
affiliates of the Company.
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Karen M. Camiolo
(47)
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Controller and Principal
Accounting Officer of the Company since April 2004; Controller
of Distribution Corporation and Supply Corporation since April
2004; and Chief Auditor of the Company from July 1994 through
March 2004.
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Anna Marie Cellino
(53)
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Secretary of the Company since
October 1995; Senior Vice President of Distribution Corporation
since July 2001.
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Paula M. Ciprich
(46)
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General Counsel of the Company
since January 2005; Assistant Secretary and General Counsel of
Distribution Corporation since February 1997.
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Donna L. DeCarolis
(47)
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President of NFR since January
2005; Secretary of NFR since March 2002; Vice President of NFR
from May 2001 to January 2005.
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John R. Pustulka
(54)
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Senior Vice President of Supply
Corporation since July 2001.
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James D. Ramsdell
(51)
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Senior Vice President of
Distribution Corporation since July 2001.
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(1) |
|
The executive officers serve at the pleasure of the Board of
Directors. The information provided relates to the Company and
its principal subsidiaries. Many of the executive officers also
have served or currently serve as officers or directors of other
subsidiaries of the Company. |
11
Item 1A Risk
Factors
As a
holding company, National Fuel depends on its operating
subsidiaries to meet its financial obligations.
National Fuel is a holding company with no significant assets
other than the stock of its operating subsidiaries. In order to
meet its financial needs, National Fuel relies exclusively on
repayments of principal and interest on intercompany loans made
by National Fuel to its operating subsidiaries and income from
dividends and other cash flow from the subsidiaries. Such
operating subsidiaries may not generate sufficient net income to
pay upstream dividends or generate sufficient cash flow to make
payments of principal or interest on such intercompany loans.
National
Fuel is dependent on bank credit facilities and continued access
to capital markets to successfully execute its operating
strategies.
In addition to its longer term debt that is issued to the public
under its indentures, National Fuel has relied, and continues to
rely, upon shorter term bank borrowings and commercial paper to
finance the execution of a portion of its operating strategies.
National Fuel is dependent on these capital sources to provide
capital to its subsidiaries to allow them to acquire and develop
their properties. The availability and cost of these credit
sources is cyclical and these capital sources may not remain
available to National Fuel or National Fuel may not be able to
obtain money at a reasonable cost in the future. National
Fuels ability to borrow under its credit facilities and
commercial paper agreements depends on National Fuels
compliance with its obligations under the facilities and
agreements. In addition, all of National Fuels short-term
bank loans are in the form of floating rate debt or debt that
may have rates fixed for very short periods of time. At present,
National Fuel has no active interest rate hedges in place to
protect against interest rate fluctuations on short-term bank
debt. National Fuel has no active interest rate hedges in place
with respect to other debt except at the project level of
Empire, where there is an interest rate collar on the
approximate $22.8 million of project debt (at
September 30, 2006). In addition, the interest rates on
National Fuels short-term bank loans and the ability of
National Fuel to issue commercial paper are affected by its debt
credit ratings published by Standard & Poors
Ratings Service, Moodys Investors Service and Fitch
Ratings Service. A ratings downgrade could increase the interest
cost of this debt and decrease future availability of money from
banks, commercial paper purchasers and other sources. National
Fuel believes it is important to maintain investment grade
credit ratings to conduct its business.
National
Fuels credit ratings may not reflect all the risks of an
investment in its securities.
National Fuels credit ratings are an independent
assessment of its ability to pay its obligations. Consequently,
real or anticipated changes in the Companys credit ratings
will generally affect the market value of the specific debt
instruments that are rated, as well as the market value of the
Companys common stock. National Fuels credit
ratings, however, may not reflect the potential impact on the
value of its common stock of risks related to structural, market
or other factors discussed in this
Form 10-K.
National
Fuels need to comply with comprehensive, complex, and
sometimes unpredictable government regulations may increase its
costs and limit its revenue growth, which may result in reduced
earnings.
While National Fuel generally refers to its Utility segment and
its Pipeline and Storage segment as its regulated
segments, there are many governmental regulations that
have an impact on almost every aspect of National Fuels
businesses. Existing statutes and regulations may be revised or
reinterpreted and new laws and regulations may be adopted or
become applicable to the Company, which may affect its business
in ways that the Company cannot predict.
In its Utility segment, the operations of Distribution
Corporation are subject to the jurisdiction of the NYPSC and the
PaPUC. The NYPSC and the PaPUC, among other things, approve the
rates that Distribution Corporation may charge to its utility
customers. Those approved rates also impact the returns that
Distribution Corporation may earn on the assets that are
dedicated to those operations. If Distribution Corporation is
required in a rate proceeding to reduce the rates it charges its
utility customers, or if Distribution Corporation is unable to
obtain approval for rate increases from these regulators,
particularly when necessary to cover
12
increased costs (including costs that may be incurred in
connection with governmental investigations or proceedings or
mandated infrastructure inspection, maintenance or replacement
programs), earnings may decrease.
In addition to their historical methods of utility regulation,
both the PaPUC and NYPSC have sought to establish competitive
markets in which customers may purchase supplies of gas from
marketers, rather than from utility companies. In June 1999, the
Governor of Pennsylvania signed into law the Natural Gas Choice
and Competition Act. The Act revised the Public Utility Code
relating to the restructuring of the natural gas industry. The
purpose of the law was to permit consumer choice of natural gas
suppliers. To a certain degree, the early programs instituted to
comply with the Act have not been overly successful, and many
residential customers currently continue to purchase natural gas
from the utility companies. In October 2005 the PaPUC concluded
that effective competition does not exist in the
retail natural gas supply market statewide. The PaPUC has
reconvened a stakeholder group to explore ways to increase the
participation of retail customers in choice programs. In New
York, in August 2004, the NYPSC issued its Statement of Policy
on Further Steps Toward Competition in Retail Energy Markets.
This policy statement has a similar goal of encouraging customer
choice of alternative natural gas providers. In 2005, the NYPSC
stepped up its efforts to encourage customer choice at the
retail residential level. These new forms of regulation may
increase Distribution Corporations cost of doing business,
put an additional portion of its business at regulatory risk,
and create uncertainty for the future, all of which may make it
more difficult to manage Distribution Corporations
business profitably.
In its Pipeline and Storage segment, National Fuel is subject to
the jurisdiction of the FERC with respect to Supply Corporation,
and to the jurisdiction of the NYPSC with respect to Empire. (On
October 11, 2005, Empire filed an application with the FERC
for the authority to build and operate an extension of its
natural gas pipeline (the Empire Connector). If the FERC grants
that application and the Company builds and commences operations
of the Empire Connector, Empire will at that time become a
FERC-regulated pipeline company.) The FERC and the NYPSC, among
other things, approve the rates that Supply Corporation and
Empire, respectively, may charge to their natural gas
transportation
and/or
storage customers. Those approved rates also impact the returns
that Supply Corporation and Empire may earn on the assets that
are dedicated to those operations. State commissions can also
petition the FERC to investigate whether Supply
Corporations rates are still just and reasonable, and if
not, to reduce those rates prospectively. If Supply Corporation
or Empire is required in a rate proceeding to reduce the rates
it charges its natural gas transportation
and/or
storage customers, or if Supply Corporation or Empire is unable
to obtain approval for rate increases, particularly when
necessary to cover increased costs, Supply Corporations or
Empires earnings may decrease.
National
Fuels liquidity, and in certain circumstances, its
earnings, could be adversely affected by the cost of purchasing
natural gas during periods in which natural gas prices are
rising significantly.
Tariff rate schedules in each of the Utility segments
service territories contain purchased gas adjustment clauses
which permit Distribution Corporation to file with state
regulators for rate adjustments to recover increases in the cost
of purchased gas. Assuming those rate adjustments are granted,
increases in the cost of purchased gas have no direct impact on
profit margins. Nevertheless, increases in the cost of purchased
gas affect cash flows and can therefore impact the amount or
availability of National Fuels capital resources. National
Fuel has issued commercial paper and used short-term borrowings
in the past to temporarily finance storage inventories and
purchased gas costs, and National Fuel expects to do so in the
future.* Distribution Corporation is required to file an
accounting reconciliation with the regulators in each of the
Utility segments service territories regarding the costs
of purchased gas. Due to the nature of the regulatory process,
there is a risk of a disallowance of full recovery of these
costs during any period in which there has been a substantial
upward spike in these costs. Any material disallowance of
purchased gas costs could have a material adverse effect on cash
flow and earnings. In addition, even when Distribution
Corporation is allowed full recovery of these purchased gas
costs, during periods when natural gas prices are significantly
higher than historical levels, customers may have trouble paying
the resulting higher bills, and Distribution Corporations
bad debt expenses may increase and ultimately reduce earnings.
13
Uncertain
economic conditions may affect National Fuels ability to
finance capital expenditures and to refinance maturing
debt.
National Fuels ability to finance capital expenditures and
to refinance maturing debt will depend upon general economic
conditions in the capital markets. The direction in which
interest rates may move is uncertain. Declining interest rates
have generally been believed to be favorable to utilities, while
rising interest rates are generally believed to be unfavorable,
because of the levels of debt that utilities may have
outstanding. In addition, National Fuels authorized rate
of return in its regulated businesses is based upon certain
assumptions regarding interest rates. If interest rates are
lower than assumed rates, National Fuels authorized rate
of return could be reduced. If interest rates are higher than
assumed rates, National Fuels ability to earn its
authorized rate of return may be adversely impacted.
Decreased
oil and natural gas prices could adversely affect revenues, cash
flows and profitability.
National Fuels exploration and production operations are
materially dependent on prices received for its oil and natural
gas production. Both short-term and long-term price trends
affect the economics of exploring for, developing, producing,
gathering and processing oil and natural gas. Oil and natural
gas prices can be volatile and can be affected by: weather
conditions, including natural disasters; the supply and price of
foreign oil and natural gas; the level of consumer product
demand; national and worldwide economic conditions, including
economic disruptions caused by terrorist activities, acts of war
or major accidents; political conditions in foreign countries;
the price and availability of alternative fuels; the proximity
to, and availability of capacity on, transportation facilities;
regional levels of supply and demand; energy conservation
measures; and government regulations, such as regulation of
natural gas transportation, royalties, and price controls.
National Fuel sells most of its oil and natural gas at current
market prices rather than through fixed-price contracts,
although as discussed below, National Fuel frequently hedges the
price of a significant portion of its future production in the
financial markets. The prices National Fuel receives depend upon
factors beyond National Fuels control, including the
factors affecting price mentioned above. National Fuel believes
that any prolonged reduction in oil and natural gas prices would
restrict its ability to continue the level of activity National
Fuel otherwise would pursue, which could have a material adverse
effect on its revenues, cash flows and results of operations.*
National
Fuel has significant transactions involving price hedging of its
oil and natural gas production.
In order to protect itself to some extent against unusual price
volatility and to lock in fixed pricing on oil and natural gas
production for certain periods of time, National Fuel
periodically enters into commodity price derivatives contracts
(hedging arrangements) with respect to a portion of its expected
production. These contracts may at any time cover as much as
approximately 70% of National Fuels expected energy
production during the upcoming 12 month period. These
contracts reduce exposure to subsequent price drops but can also
limit National Fuels ability to benefit from increases in
commodity prices.
In addition, under the applicable accounting rules, such hedging
arrangements are subject to quarterly effectiveness tests.
Inherent within those effectiveness tests are assumptions
concerning the long-term price differential between different
types of crude oil, assumptions concerning the difference
between published natural gas price indexes established by
pipelines in which hedged natural gas production is delivered
and the reference price established in the hedging arrangements,
and assumptions regarding the levels of production that will be
achieved. Depending on market conditions for natural gas and
crude oil and the levels of production actually achieved, it is
possible that certain of those assumptions may change in the
future, and, depending on the magnitude of any such changes, it
is possible that a portion of the Companys hedges may no
longer be considered highly effective. In that case, gains or
losses from the ineffective derivative financial instruments
would be
marked-to-market
on the income statement without regard to an underlying physical
transaction. Gains would occur to the extent that hedge prices
exceed market prices, and losses would occur to the extent that
market prices exceed hedge prices.
Use of energy commodity price hedges also exposes National Fuel
to the risk of non-performance by a contract counterparty.
National Fuel carefully evaluates the financial strength of all
contract counterparties, but these parties might not be able to
perform their obligations under the hedge arrangements.
14
It is National Fuels policy that the use of commodity
derivatives contracts be strictly confined to the price hedging
of existing and forecast production, and National Fuel maintains
a system of internal controls to monitor compliance with its
policy. However, unauthorized speculative trades could occur
that may expose National Fuel to substantial losses to cover
positions in these contracts. In addition, in the event actual
production falls short of hedged forecast production, the
Company may incur substantial losses to cover its hedges.
You
should not place undue reliance on reserve information because
such information represents estimates.
This
Form 10-K
contains estimates of National Fuels proved oil and
natural gas reserves and the future net cash flows from those
reserves that were prepared by National Fuels petroleum
engineers and audited by independent petroleum engineers.
Petroleum engineers consider many factors and make assumptions
in estimating National Fuels oil and natural gas reserves
and future net cash flows. These factors include: historical
production from the area compared with production from other
producing areas; the assumed effect of governmental regulation;
and assumptions concerning oil and natural gas prices,
production and development costs, severance and excise taxes,
and capital expenditures. Lower oil and natural gas prices
generally cause estimates of proved reserves to be lower.
Estimates of reserves and expected future cash flows prepared by
different engineers, or by the same engineers at different
times, may differ substantially. Ultimately, actual production,
revenues and expenditures relating to National Fuels
reserves will vary from any estimates, and these variations may
be material. Accordingly, the accuracy of National Fuels
reserve estimates is a function of the quality of available data
and of engineering and geological interpretation and judgment.
If conditions remain constant, then National Fuel is reasonably
certain that its reserve estimates represent economically
recoverable oil and natural gas reserves and future net cash
flows. If conditions change in the future, then subsequent
reserve estimates may be revised accordingly. You should not
assume that the present value of future net cash flows from
National Fuels proved reserves is the current market value
of National Fuels estimated oil and natural gas reserves.
In accordance with SEC requirements, National Fuel bases the
estimated discounted future net cash flows from its proved
reserves on prices and costs as of the date of the estimate.
Actual future prices and costs may differ materially from those
used in the net present value estimate. Any significant price
changes will have a material effect on the present value of
National Fuels reserves.
Petroleum engineering is a subjective process of estimating
underground accumulations of natural gas and other hydrocarbons
that cannot be measured in an exact manner. The process of
estimating oil and natural gas reserves is complex. The process
involves significant decisions and assumptions in the evaluation
of available geological, geophysical, engineering and economic
data for each reservoir. Future economic and operating
conditions are uncertain, and changes in those conditions could
cause a revision to National Fuels future reserve
estimates. Estimates of economically recoverable oil and natural
gas reserves and of future net cash flows depend upon a number
of variable factors and assumptions, including historical
production from the area compared with production from other
comparable producing areas, and the assumed effects of
regulations by governmental agencies. Because all reserve
estimates are to some degree subjective, each of the following
items may differ materially from those assumed in estimating
reserves: the quantities of oil and natural gas that are
ultimately recovered, the timing of the recovery of oil and
natural gas reserves, the production and operating costs
incurred, the amount and timing of future development
expenditures, and the price received for the production.
The
amount and timing of actual future oil and natural gas
production and the cost of drilling are difficult to predict and
may vary significantly from reserves and production estimates,
which may reduce National Fuels earnings.
There are many risks in developing oil and natural gas,
including numerous uncertainties inherent in estimating
quantities of proved oil and natural gas reserves and in
projecting future rates of production and timing of development
expenditures. The future success of National Fuels
Exploration and Production segment depends on its ability to
develop additional oil and natural gas reserves that are
economically recoverable, and its failure to do so may reduce
National Fuels earnings. The total and timing of actual
future production may
15
vary significantly from reserves and production estimates.
National Fuels drilling of development wells can involve
significant risks, including those related to timing, success
rates, and cost overruns, and these risks can be affected by
lease and rig availability, geology, and other factors. Drilling
for natural gas can be unprofitable, not only from dry wells,
but from productive wells that do not produce sufficient
revenues to return a profit. Also, title problems, weather
conditions, governmental requirements, and shortages or delays
in the delivery of equipment and services can delay drilling
operations or result in their cancellation. The cost of
drilling, completing, and operating wells is often uncertain,
and new wells may not be productive or National Fuel may not
recover all or any portion of its investment. Without continued
successful exploitation or acquisition activities, National
Fuels reserves and revenues will decline as a result of
its current reserves being depleted by production. National Fuel
cannot assure you that it will be able to find or acquire
additional reserves at acceptable costs.
Financial
accounting requirements regarding exploration and production
activities may affect National Fuels
profitability.
National Fuel accounts for its exploration and production
activities under the full cost method of accounting. Each
quarter, on a
country-by-country
basis, National Fuel must compare the level of its unamortized
investment in oil and natural gas properties to the present
value of the future net revenue projected to be recovered from
those properties according to methods prescribed by the SEC. In
determining present value, the Company uses quarter-end spot
prices for oil and natural gas. If, at the end of any quarter,
the amount of the unamortized investment exceeds the net present
value of the projected future revenues, such investment may be
considered to be impaired, and the full cost
accounting rules require that the investment must be written
down to the calculated net present value. Such an instance would
require National Fuel to recognize an immediate expense in that
quarter, and its earnings would be reduced. The event that had
the most significant impact in 2006, and the main reason for the
significant earnings decrease over 2005, was the Exploration and
Production segment recording after-tax impairment charges
totaling $68.6 million related to its Canadian oil and gas
assets during 2006 under the full cost method of accounting.
Because of the variability in National Fuels investment in
oil and natural gas properties and the volatile nature of
commodity prices, National Fuel cannot predict when in the
future it may again be affected by such an impairment
calculation.
Environmental
regulation significantly affects National Fuels
business.
National Fuels business operations are subject to federal,
state, and local laws and regulations (including those of
Canada) relating to environmental protection. These laws and
regulations concern the generation, storage, transportation,
disposal or discharge of contaminants into the environment and
the general protection of public health, natural resources,
wildlife and the environment. Costs of compliance and
liabilities could negatively affect National Fuels results
of operations, financial condition and cash flows. In addition,
compliance with environmental laws and regulations could require
unexpected capital expenditures at National Fuels
facilities. Because the costs of complying with environmental
regulations are significant, additional regulation could
negatively affect National Fuels business. Although
National Fuel cannot predict the impact of the interpretation or
enforcement of EPA standards or other federal, state and local
regulations, National Fuels costs could increase if
environmental laws and regulations become more strict.
The
nature of National Fuels operations presents inherent
risks of loss that could adversely affect its results of
operations, financial condition and cash flows.
National Fuels operations are subject to inherent hazards
and risks such as: fires; natural disasters; explosions;
formations with abnormal pressures; blowouts; collapses of
wellbore casing or other tubulars; pipeline ruptures; spills;
and other hazards and risks that may cause personal injury,
death, property damage, environmental damage or business
interruption losses. Additionally, National Fuels
facilities, machinery, and equipment may be subject to sabotage.
Any of these events could cause a loss of hydrocarbons,
environmental pollution, claims for personal injury, death,
property damage or business interruption, or governmental
investigations, recommendations, claims, fines or penalties. As
protection against operational hazards, National Fuel maintains
insurance coverage against some, but not all, potential losses.
In addition, many of the
16
agreements that National Fuel executes with contractors provide
for the division of responsibilities between the contractor and
National Fuel, and National Fuel seeks to obtain an
indemnification from the contractor for certain of these risks.
National Fuel is not always able, however, to secure written
agreements with its contractors that contain indemnification,
and sometimes National Fuel is required to indemnify others.
Insurance or indemnification agreements when obtained may not
adequately protect National Fuel against liability from all of
the consequences of the hazards described above. The occurrence
of an event not fully insured or indemnified against, the
imposition of fines, penalties or mandated programs by
governmental authorities, the failure of a contractor to meet
its indemnification obligations, or the failure of an insurance
company to pay valid claims could result in substantial losses
to National Fuel. In addition, insurance may not be available,
or if available may not be adequate, to cover any or all of
these risks. It is also possible that insurance premiums or
other costs may rise significantly in the future, so as to make
such insurance prohibitively expensive.
Due to large insurance losses caused by Hurricanes Katrina and
Rita in 2005, the insurance industry has significantly increased
premiums for insurance on Gulf of Mexico properties, and has
reduced the limits typically available for windstorm damage. As
a result, National Fuel has determined that it is not economical
to purchase insurance to fully cover its exposures in the Gulf
of Mexico in the event of a named windstorm. National Fuel has
procured named windstorm coverage in an amount equal to
approximately three times the estimated physical damage loss
sustained by National Fuel as a result of named windstorms
during the 2005 hurricane season, subject to a deductible of
$2 million per occurrence. No assurance can be given,
however, that such amount will be sufficient to cover losses
that may occur in the future.
Hazards and risks faced by National Fuel, and insurance and
indemnification obtained or provided by National Fuel, may
subject National Fuel to litigation or administrative
proceedings from time to time. Such litigation or proceedings
could result in substantial monetary judgments, fines or
penalties against National Fuel or be resolved on unfavorable
terms, the result of which could have a material adverse effect
on National Fuels results of operations, financial
condition and cash flows.
National
Fuel may be adversely affected by economic
conditions.
Periods of slowed economic activity generally result in
decreased energy consumption, particularly by industrial and
large commercial companies. As a consequence, national or
regional recessions or other downturns in economic activity
could adversely affect National Fuels revenues and cash
flows or restrict its future growth. Economic conditions in
National Fuels utility service territories also impact its
collections of accounts receivable.
|
|
Item 1B
|
Unresolved
Staff Comments
|
None
General
Information on Facilities
The investment of the Company in net property, plant and
equipment was $2.9 billion at September 30, 2006.
Approximately 61% of this investment was in the Utility and
Pipeline and Storage segments, which are primarily located in
western and central New York and northwestern Pennsylvania. The
Exploration and Production segment, which has the next largest
investment in net property, plant and equipment (35%), is
primarily located in California, in the Appalachian region of
the United States, in Wyoming, in the Gulf Coast region of
Texas, Louisiana, and Alabama and in the provinces of Alberta,
Saskatchewan and British Columbia in Canada. The remaining
investment in net property, plant and equipment consisted
primarily of the Timber segment (3%) which is located primarily
in northwestern Pennsylvania, and All Other and Corporate
operations (1%). During the past five years, the Company has
made additions to property, plant and equipment in order to
expand and improve transmission and distribution facilities for
both retail and transportation customers. Net property, plant
and equipment has increased $97.0 million, or 3.5%, since
2001. During 2005, the Company
17
sold its majority interest in U.E., a district heating and
electric generation business in the Czech Republic. The net
property, plant and equipment of U.E. at the date of sale was
$223.9 million.
The Utility segment had a net investment in property, plant and
equipment of $1.1 billion at September 30, 2006. The
net investment in its gas distribution network (including
14,809 miles of distribution pipeline) and its service
connections to customers represent approximately 53% and 33%,
respectively, of the Utility segments net investment in
property, plant and equipment at September 30, 2006.
The Pipeline and Storage segment had a net investment of
$674.2 million in property, plant and equipment at
September 30, 2006. Transmission pipeline represents 36% of
this segments total net investment and includes
2,528 miles of pipeline required to move large volumes of
gas throughout its service area. Storage facilities represent
24% of this segments total net investment and consist of
32 storage fields, four of which are jointly owned and operated
with certain pipeline suppliers, and 439 miles of pipeline.
Net investment in storage facilities includes $93.8 million
of gas stored underground-noncurrent, representing the cost of
the gas required to maintain pressure levels for normal
operating purposes as well as gas maintained for system
balancing and other purposes, including that needed for
no-notice transportation service. The Pipeline and Storage
segment has 28 compressor stations with 75,361 installed
compressor horsepower that represent 13% of this segments
total net investment in property, plant and equipment.
The Exploration and Production segment had a net investment in
property, plant and equipment of $1.0 billion at
September 30, 2006. Of this amount, $914.2 million
relates to properties located in the United States. The
remaining net investment of $88.0 million relates to
properties located in Canada.
The Timber segment had a net investment in property, plant and
equipment of $90.9 million at September 30, 2006.
Located primarily in northwestern Pennsylvania, the net
investment includes two sawmills, approximately 100,000 acres of
land and timber, and approximately 4,000 acres of timber
rights.
The Utility and Pipeline and Storage segments facilities
provided the capacity to meet the Companys 2006 peak day
sendout, including transportation service, of 1,542.4 MMcf,
which occurred on February 18, 2006. Withdrawals from
storage of 545.2 MMcf provided approximately 35.3% of the
requirements on that day.
Company maps are included in exhibit 99.3 of this
Form 10-K
and are incorporated herein by reference.
Exploration
and Production Activities
The Company is engaged in the exploration for, and the
development and purchase of, natural gas and oil reserves in
California, in the Appalachian region of the United States, and
in the Gulf Coast region of Texas, Louisiana, and Alabama. Also,
Exploration and Production operations are conducted in the
provinces of Alberta, Saskatchewan and British Columbia in
Canada. Further discussion of oil and gas producing activities
is included in Item 8,
Note O-Supplementary
Information for Oil and Gas Producing Activities. Note O
sets forth proved developed and undeveloped reserve information
for Seneca. Senecas proved developed and undeveloped
natural gas reserves decreased from 238 Bcf at
September 30, 2005 to 233 Bcf at September 30,
2006. This decrease can be attributed primarily to production
and downward reserve revisions related primarily to the Canadian
properties. These decreases were partially offset by extensions
and discoveries. The downward reserve revisions were largely a
function of a significant decrease in gas prices during the
fourth quarter of 2006. Senecas proved developed and
undeveloped oil reserves decreased from 60,257 Mbbl at
September 30, 2005 to 58,018 Mbbl at
September 30, 2006. This decrease can be attributed mostly
to production. Senecas proved developed and undeveloped
natural gas reserves increased from 225 Bcf at
September 30, 2004 to 238 Bcf at September 30,
2005. This increase can be attributed to the fact that net
extensions and discoveries outpaced production. However,
Senecas proved developed and undeveloped oil reserves
decreased from 65,213 Mbbl at September 30, 2004 to 60,257
Mbbl at September 30, 2005. This decrease can be attributed
to the fact that production outpaced net extensions and
discoveries.
Senecas oil and gas reserves reported in Note O as of
September 30, 2006 were estimated by Senecas
geologists and engineers and were audited by independent
petroleum engineers from Ralph E. Davis Associates, Inc. Seneca
reports its oil and gas reserve information on an annual basis
to the Energy Information Administration (EIA), a
18
statistical agency of the U.S. Department of Energy. The
basis of reporting Senecas reserves to the EIA is
identical to that reported in Note O.
The following is a summary of certain oil and gas information
taken from Senecas records. All monetary amounts are
expressed in U.S. dollars.
Production
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Year Ended September 30
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
United States
|
|
|
|
|
|
|
|
|
|
|
|
|
Gulf Coast Region
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Sales Price per Mcf of Gas
|
|
$
|
8.01
|
|
|
$
|
7.05
|
|
|
$
|
5.61
|
|
Average Sales Price per Barrel of
Oil
|
|
$
|
64.10
|
|
|
$
|
49.78
|
|
|
$
|
35.31
|
|
Average Sales Price per Mcf of Gas
(after hedging)
|
|
$
|
5.89
|
|
|
$
|
6.01
|
|
|
$
|
4.82
|
|
Average Sales Price per Barrel of
Oil (after hedging)
|
|
$
|
47.46
|
|
|
$
|
35.03
|
|
|
$
|
31.51
|
|
Average Production (Lifting) Cost
per Mcf Equivalent of Gas and Oil Produced
|
|
$
|
0.86
|
|
|
$
|
0.71
|
|
|
$
|
0.60
|
|
Average Production per Day (in
MMcf Equivalent of Gas and Oil Produced)
|
|
|
36
|
|
|
|
50
|
|
|
|
73
|
|
West Coast Region
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Sales Price per Mcf of Gas
|
|
$
|
7.93
|
|
|
$
|
6.85
|
|
|
$
|
5.54
|
|
Average Sales Price per Barrel of
Oil
|
|
$
|
56.80
|
|
|
$
|
42.91
|
|
|
$
|
31.89
|
|
Average Sales Price per Mcf of Gas
(after hedging)
|
|
$
|
7.19
|
|
|
$
|
6.15
|
|
|
$
|
5.72
|
|
Average Sales Price per Barrel of
Oil (after hedging)
|
|
$
|
37.69
|
|
|
$
|
23.01
|
|
|
$
|
22.86
|
|
Average Production (Lifting) Cost
per Mcf Equivalent of Gas and Oil Produced
|
|
$
|
1.35
|
|
|
$
|
1.15
|
|
|
$
|
1.05
|
|
Average Production per Day (in
MMcf Equivalent of Gas and Oil Produced)
|
|
|
53
|
|
|
|
53
|
|
|
|
55
|
|
Appalachian Region
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Sales Price per Mcf of Gas
|
|
$
|
9.53
|
|
|
$
|
7.60
|
|
|
$
|
5.91
|
|
Average Sales Price per Barrel of
Oil
|
|
$
|
65.28
|
|
|
$
|
48.28
|
|
|
$
|
31.30
|
|
Average Sales Price per Mcf of Gas
(after hedging)
|
|
$
|
8.90
|
|
|
$
|
7.01
|
|
|
$
|
5.72
|
|
Average Sales Price per Barrel of
Oil (after hedging)
|
|
$
|
65.28
|
|
|
$
|
48.28
|
|
|
$
|
31.30
|
|
Average Production (Lifting) Cost
per Mcf Equivalent of Gas and Oil Produced
|
|
$
|
0.69
|
|
|
$
|
0.63
|
|
|
$
|
0.54
|
|
Average Production per Day (in
MMcf Equivalent of Gas and Oil Produced)
|
|
|
15
|
|
|
|
13
|
|
|
|
14
|
|
Total United States
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Sales Price per Mcf of Gas
|
|
$
|
8.42
|
|
|
$
|
7.13
|
|
|
$
|
5.66
|
|
Average Sales Price per Barrel of
Oil
|
|
$
|
58.47
|
|
|
$
|
44.87
|
|
|
$
|
33.13
|
|
Average Sales Price per Mcf of Gas
(after hedging)
|
|
$
|
7.02
|
|
|
$
|
6.26
|
|
|
$
|
5.13
|
|
Average Sales Price per Barrel of
Oil (after hedging)
|
|
$
|
40.26
|
|
|
$
|
26.59
|
|
|
$
|
26.06
|
|
Average Production (Lifting) Cost
per Mcf Equivalent of Gas and Oil Produced
|
|
$
|
1.09
|
|
|
$
|
0.90
|
|
|
$
|
0.76
|
|
Average Production per Day (in
MMcf Equivalent of Gas and Oil Produced)
|
|
|
104
|
|
|
|
117
|
|
|
|
142
|
|
19
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Year Ended September 30
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
Canada
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Sales Price per Mcf of Gas
|
|
$
|
7.14
|
|
|
$
|
6.15
|
|
|
$
|
4.87
|
|
Average Sales Price per Barrel of
Oil
|
|
$
|
51.40
|
|
|
$
|
42.97
|
|
|
$
|
30.94
|
|
Average Sales Price per Mcf of Gas
(after hedging)
|
|
$
|
7.47
|
|
|
$
|
6.14
|
|
|
$
|
4.79
|
|
Average Sales Price per Barrel of
Oil (after hedging)
|
|
$
|
51.40
|
|
|
$
|
42.97
|
|
|
$
|
30.94
|
|
Average Production (Lifting) Cost
per Mcf Equivalent of Gas and Oil Produced
|
|
$
|
1.57
|
|
|
$
|
1.29
|
|
|
$
|
1.00
|
|
Average Production per Day (in
MMcf Equivalent of Gas and Oil Produced)
|
|
|
26
|
|
|
|
27
|
|
|
|
22
|
|
Total Company
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Sales Price per Mcf of Gas
|
|
$
|
8.04
|
|
|
$
|
6.86
|
|
|
$
|
5.51
|
|
Average Sales Price per Barrel of
Oil
|
|
$
|
57.94
|
|
|
$
|
44.72
|
|
|
$
|
32.98
|
|
Average Sales Price per Mcf of Gas
(after hedging)
|
|
$
|
7.15
|
|
|
$
|
6.23
|
|
|
$
|
5.06
|
|
Average Sales Price per Barrel of
Oil (after hedging)
|
|
$
|
41.10
|
|
|
$
|
27.86
|
|
|
$
|
26.40
|
|
Average Production (Lifting) Cost
per Mcf Equivalent of Gas and Oil Produced
|
|
$
|
1.18
|
|
|
$
|
0.98
|
|
|
$
|
0.80
|
|
Average Production per Day (in
MMcf Equivalent of Gas and Oil Produced)
|
|
|
130
|
|
|
|
144
|
|
|
|
164
|
|
Productive
Wells
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
United States
|
|
|
|
|
|
|
|
|
|
Gulf Coast
|
|
|
West Coast
|
|
|
Appalachian
|
|
|
|
|
|
|
Region
|
|
|
Region
|
|
|
Region
|
|
|
Total U.S.
|
|
At September 30, 2006
|
|
Gas
|
|
|
Oil
|
|
|
Gas
|
|
|
Oil
|
|
|
Gas
|
|
|
Oil
|
|
|
Gas
|
|
|
Oil
|
|
|
Productive Wells Gross
|
|
|
34
|
|
|
|
30
|
|
|
|
|
|
|
|
1,274
|
|
|
|
2,138
|
|
|
|
31
|
|
|
|
2,172
|
|
|
|
1,335
|
|
Productive Wells Net
|
|
|
21
|
|
|
|
14
|
|
|
|
|
|
|
|
1,266
|
|
|
|
2,052
|
|
|
|
25
|
|
|
|
2,073
|
|
|
|
1,305
|
|
Productive
Wells
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canada
|
|
|
Total Company
|
|
At September 30, 2006
|
|
Gas
|
|
|
Oil
|
|
|
Gas
|
|
|
Oil
|
|
|
Productive Wells Gross
|
|
|
217
|
|
|
|
53
|
|
|
|
2,389
|
|
|
|
1,388
|
|
Productive Wells Net
|
|
|
155
|
|
|
|
36
|
|
|
|
2,228
|
|
|
|
1,341
|
|
Developed
and Undeveloped Acreage
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
United States
|
|
|
|
|
|
|
|
|
|
Golf
|
|
|
West
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Coast
|
|
|
Coast
|
|
|
Appalachian
|
|
|
Total
|
|
|
|
|
|
Total
|
|
At September 30, 2006
|
|
Region
|
|
|
Region
|
|
|
Region
|
|
|
U.S.
|
|
|
Canada
|
|
|
Company
|
|
|
Developed Acreage
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross
|
|
|
144,610
|
|
|
|
10,479
|
|
|
|
514,222
|
|
|
|
669,311
|
|
|
|
117,955
|
|
|
|
787,266
|
|
Net
|
|
|
104,173
|
|
|
|
10,109
|
|
|
|
487,384
|
|
|
|
601,666
|
|
|
|
84,182
|
|
|
|
685,848
|
|
Undeveloped Acreage
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross
|
|
|
174,503
|
|
|
|
|
|
|
|
475,909
|
|
|
|
650,412
|
|
|
|
393,169
|
|
|
|
1,043,581
|
|
Net
|
|
|
85,117
|
|
|
|
|
|
|
|
451,733
|
|
|
|
536,850
|
|
|
|
243,287
|
|
|
|
780,137
|
|
As of September 30, 2006, the aggregate amount of gross
undeveloped acreage expiring in the next three years and
thereafter are as follows: 191,159 acres in 2007
(128,900 net acres), 112,156 acres in 2008
(65,174 net acres), 83,246 acres in 2009
(57,538 net acres), and 657,020 acres thereafter
(528,525 net acres).
20
Drilling
Activity
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive
|
|
|
Dry
|
|
For the Year Ended September 30
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
United States
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gulf Coast Region
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Wells Completed
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploratory
|
|
|
2.94
|
|
|
|
1.30
|
|
|
|
|
|
|
|
0.85
|
|
|
|
0.47
|
|
|
|
0.50
|
|
Development
|
|
|
0.78
|
|
|
|
0.23
|
|
|
|
0.65
|
|
|
|
|
|
|
|
|
|
|
|
|
|
West Coast Region Net Wells
Completed
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploratory
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Development
|
|
|
92.98
|
|
|
|
116.97
|
|
|
|
49.00
|
|
|
|
1.00
|
|
|
|
|
|
|
|
|
|
Appalachian Region Net Wells
Completed
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploratory
|
|
|
3.88
|
|
|
|
3.00
|
|
|
|
|
|
|
|
|
|
|
|
4.00
|
|
|
|
3.00
|
|
Development
|
|
|
140.58
|
|
|
|
45.00
|
|
|
|
41.00
|
|
|
|
1.75
|
|
|
|
1.00
|
|
|
|
|
|
Total United States Net Wells
Completed
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploratory
|
|
|
6.82
|
|
|
|
4.30
|
|
|
|
|
|
|
|
0.85
|
|
|
|
4.47
|
|
|
|
3.50
|
|
Development
|
|
|
234.34
|
|
|
|
162.20
|
|
|
|
90.65
|
|
|
|
2.75
|
|
|
|
1.00
|
|
|
|
|
|
Canada
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Wells Completed
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploratory
|
|
|
12.60
|
|
|
|
21.14
|
|
|
|
52.85
|
|
|
|
1.35
|
|
|
|
2.00
|
|
|
|
6.08
|
|
Development
|
|
|
2.50
|
|
|
|
3.50
|
|
|
|
10.50
|
|
|
|
1.00
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Wells Completed
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploratory
|
|
|
19.42
|
|
|
|
25.44
|
|
|
|
52.85
|
|
|
|
2.20
|
|
|
|
6.47
|
|
|
|
9.58
|
|
Development
|
|
|
236.84
|
|
|
|
165.70
|
|
|
|
101.15
|
|
|
|
3.75
|
|
|
|
1.00
|
|
|
|
|
|
Present
Activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
United States
|
|
|
|
|
|
|
|
|
|
Gulf
|
|
|
West
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Coast
|
|
|
Coast
|
|
|
Appalachian
|
|
|
Total
|
|
|
|
|
|
Total
|
|
At September 30, 2006
|
|
Region
|
|
|
Region
|
|
|
Region
|
|
|
U.S.
|
|
|
Canada
|
|
|
Company
|
|
|
Wells in Process of Drilling(1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross
|
|
|
5.00
|
|
|
|
6.00
|
|
|
|
54.00
|
|
|
|
65.00
|
|
|
|
5.00
|
|
|
|
70.00
|
|
Net
|
|
|
2.69
|
|
|
|
5.50
|
|
|
|
54.00
|
|
|
|
62.19
|
|
|
|
2.13
|
|
|
|
64.32
|
|
|
|
|
(1) |
|
Includes wells awaiting completion. |
In an action instituted in the New York State Supreme Court,
Kings County on February 18, 2003 against Distribution
Corporation and Paul J. Hissin, an unaffiliated third party,
plaintiff Donna Fordham-Coleman, as administratrix of the estate
of Velma Arlene Fordham, alleges that Distribution
Corporations denial of natural gas service in November
2000 to the plaintiffs decedent, Velma Arlene Fordham,
caused the decedents death in February 2001. The plaintiff
sought damages for wrongful death and pain and suffering, plus
punitive damages. Distribution Corporation denied
plaintiffs material allegations, asserted seven
affirmative defenses and asserted a cross-claim against the
co-defendant. Distribution Corporation believes, and has
vigorously asserted, that plaintiffs allegations lack
merit. The Court changed venue of the action to New York State
Supreme Court, Erie County. Discovery closed in October 2005,
and Distribution Corporation filed a motion for summary judgment
in November 2005. On February 24, 2006, the Court granted
Distribution Corporations motion for summary
21
judgment dismissing plaintiffs claims for wrongful death
and punitive damages. The Court denied Distribution
Corporations motion for summary judgment to dismiss
plaintiffs negligence claim seeking recovery for conscious
pain and suffering. On March 15, 2006, the plaintiff
appealed the Courts decision to the New York State Supreme
Court, Appellate Division, Fourth Department. On March 29,
2006, Distribution Corporation filed a cross-appeal. A trial
date is scheduled for October 15, 2007 (although it is
possible that the Court may change that date or that a trial may
become unnecessary, based on the progress or outcome of the
pending appeals).
On April 7, 2006, the NYPSC, PaPUC and Pennsylvania Office
of Consumer Advocate filed a complaint and a motion for summary
disposition against Supply Corporation with the FERC under
Sections 5(a) and 13 of the Natural Gas Act. For a
discussion of these matters, refer to Part II,
Item 7 MD&A of this report under the
heading Other Matters Rate and Regulatory
Matters.
On June 8, 2006, the NTSB issued safety recommendations to
Distribution Corporation, the PaPUC and certain others as a
result of its investigation of a natural gas explosion that
occurred on Distribution Corporations system in Dubois,
Pennsylvania in August 2004. For a discussion of this matter,
refer to Part II, Item 7 MD&A of this
report under the heading Other Matters Rate
and Regulatory Matters.
The Company believes, based on the information presently known,
that the ultimate resolution of the above matters will not be
material to the consolidated financial condition, results of
operations, or cash flow of the Company.* No assurances can be
given, however, as to the ultimate outcome of these matters, and
it is possible that the outcome could be material to results of
operations or cash flow for a particular quarter or annual
period.*
For a discussion of various environmental and other matters,
refer to Item 7, MD&A and Item 8 at
Note H Commitments and Contingencies.
In addition to the matters disclosed above, the Company is
involved in other litigation and regulatory matters arising in
the normal course of business. These other matters may include,
for example, negligence claims and tax, regulatory or other
governmental audits, inspections, investigations or other
proceedings. These matters may involve state and federal taxes,
safety, compliance with regulations, rate base, cost of service,
and purchased gas cost issues, among other things. While these
normal-course matters could have a material effect on earnings
and cash flows in the quarterly and annual period in which they
are resolved, they are not expected to change materially the
Companys present liquidity position, nor to have a
material adverse effect on the financial condition of the
Company.*
|
|
Item 4
|
Submission
of Matters to a Vote of Security Holders
|
No matter was submitted to a vote of security holders during the
quarter ended September 30, 2006.
PART II
|
|
Item 5
|
Market
for the Registrants Common Equity, Related Stockholder
Matters and Issuer Purchases of Equity Securities
|
Information regarding the market for the Companys common
equity and related stockholder matters appears under
Item 12 at Security Ownership of Certain Beneficial Owners
and Management and Related Stockholder Matters, Item 8 at
Note E-Capitalization
and Short-Term Borrowings and
Note N-Market
for Common Stock and Related Shareholder Matters (unaudited).
On July 1, 2006, the Company issued a total of 2,100
unregistered shares of Company common stock to the seven
non-employee directors of the Company serving on the Board of
Directors, 300 shares to each such director. All of these
unregistered shares were issued as partial consideration for
such directors services during the quarter ended
September 30, 2006, pursuant to the Companys Retainer
Policy for Non-Employee Directors. These transactions were
exempt from registration under Section 4(2) of the
Securities Act of 1933, as transactions not involving a public
offering.
22
Issuer
Purchases of Equity Securities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Number
|
|
|
Maximum Number
|
|
|
|
|
|
|
|
|
|
of Shares
|
|
|
of Shares
|
|
|
|
|
|
|
|
|
|
Purchased as
|
|
|
that May
|
|
|
|
|
|
|
|
|
|
Part of
|
|
|
Yet Be
|
|
|
|
|
|
|
|
|
|
Publicly Announced
|
|
|
Purchased Under
|
|
|
|
Total Number
|
|
|
Average Price
|
|
|
Share Repurchase
|
|
|
Share Repurchase
|
|
|
|
of Shares
|
|
|
Paid per
|
|
|
Plans or
|
|
|
Plans or
|
|
Period
|
|
Purchased(a)
|
|
|
Share
|
|
|
Programs
|
|
|
Programs(b)
|
|
|
July 1-31, 2006
|
|
|
444,198
|
|
|
$
|
36.32
|
|
|
|
94,400
|
|
|
|
5,621,250
|
|
Aug. 1-31, 2006
|
|
|
47,155
|
|
|
$
|
37.91
|
|
|
|
|
|
|
|
5,621,250
|
|
Sept. 1-30, 2006
|
|
|
192,702
|
|
|
$
|
36.46
|
|
|
|
147,800
|
|
|
|
5,473,450
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
684,055
|
|
|
$
|
36.47
|
|
|
|
242,200
|
|
|
|
5,473,450
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) |
|
Represents (i) shares of common stock of the Company
purchased on the open market with Company matching
contributions for the accounts of participants in the
Companys 401(k) plans, (ii) shares of common stock of
the Company tendered to the Company by holders of stock options
or shares of restricted stock for the payment of option exercise
prices or applicable withholding taxes, and (iii) shares of
common stock of the Company purchased on the open market
pursuant to the Companys publicly announced share
repurchase program. Shares purchased other than through a
publicly announced share repurchase program totaled 349,798 in
July 2006, 47,155 in August 2006 and 44,902 in September 2006 (a
three month total of 441,855). Of those shares, 27,499 were
purchased for the Companys 401(k) plans and 414,356 were
purchased as a result of shares tendered to the Company by
holders of stock options or shares of restricted stock. |
|
(b) |
|
On December 8, 2005, the Companys Board of Directors
authorized the repurchase of up to eight million shares of the
Companys common stock. Repurchases may be made from time
to time in the open market or through private transactions. |
|
|
Item 6
|
Selected
Financial Data(1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended September 30
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
2003
|
|
|
2002
|
|
|
|
(Thousands)
|
|
|
Summary of Operations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Revenues
|
|
$
|
2,311,659
|
|
|
$
|
1,923,549
|
|
|
$
|
1,907,968
|
|
|
$
|
1,921,573
|
|
|
$
|
1,369,869
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchased Gas
|
|
|
1,267,562
|
|
|
|
959,827
|
|
|
|
949,452
|
|
|
|
963,567
|
|
|
|
462,857
|
|
Operation and Maintenance
|
|
|
413,726
|
|
|
|
404,517
|
|
|
|
385,519
|
|
|
|
361,898
|
|
|
|
372,063
|
|
Property, Franchise and Other Taxes
|
|
|
69,942
|
|
|
|
69,076
|
|
|
|
68,978
|
|
|
|
79,692
|
|
|
|
69,837
|
|
Depreciation, Depletion and
Amortization
|
|
|
179,615
|
|
|
|
179,767
|
|
|
|
174,289
|
|
|
|
181,329
|
|
|
|
168,745
|
|
Impairment of Oil and Gas
Producing Properties
|
|
|
104,739
|
|
|
|
|
|
|
|
|
|
|
|
42,774
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,035,584
|
|
|
|
1,613,187
|
|
|
|
1,578,238
|
|
|
|
1,629,260
|
|
|
|
1,073,502
|
|
Gain (Loss) on Sale of Timber
Properties
|
|
|
|
|
|
|
|
|
|
|
(1,252
|
)
|
|
|
168,787
|
|
|
|
|
|
Gain (Loss) on Sale of Oil and Gas
Producing Properties
|
|
|
|
|
|
|
|
|
|
|
4,645
|
|
|
|
(58,472
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Income
|
|
|
276,075
|
|
|
|
310,362
|
|
|
|
333,123
|
|
|
|
402,628
|
|
|
|
296,367
|
|
23
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended September 30
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
2003
|
|
|
2002
|
|
|
|
(Thousands)
|
|
|
Other Income (Expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from Unconsolidated
Subsidiaries
|
|
|
3,583
|
|
|
|
3,362
|
|
|
|
805
|
|
|
|
535
|
|
|
|
224
|
|
Impairment of Investment in
Partnership
|
|
|
|
|
|
|
(4,158
|
)
|
|
|
|
|
|
|
|
|
|
|
(15,167
|
)
|
Interest Income
|
|
|
10,275
|
|
|
|
6,496
|
|
|
|
1,771
|
|
|
|
2,204
|
|
|
|
2,593
|
|
Other Income
|
|
|
2,825
|
|
|
|
12,744
|
|
|
|
2,908
|
|
|
|
2,427
|
|
|
|
3,184
|
|
Interest Expense on Long-Term Debt
|
|
|
(72,629
|
)
|
|
|
(73,244
|
)
|
|
|
(82,989
|
)
|
|
|
(91,381
|
)
|
|
|
(88,646
|
)
|
Other Interest Expense
|
|
|
(5,952
|
)
|
|
|
(9,069
|
)
|
|
|
(6,763
|
)
|
|
|
(11,196
|
)
|
|
|
(15,109
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from Continuing Operations
Before Income Taxes
|
|
|
214,177
|
|
|
|
246,493
|
|
|
|
248,855
|
|
|
|
305,217
|
|
|
|
183,446
|
|
Income Tax Expense
|
|
|
76,086
|
|
|
|
92,978
|
|
|
|
94,590
|
|
|
|
124,150
|
|
|
|
69,944
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from Continuing Operations
|
|
|
138,091
|
|
|
|
153,515
|
|
|
|
154,265
|
|
|
|
181,067
|
|
|
|
113,502
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Discontinued Operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from Operations, Net of Tax
|
|
|
|
|
|
|
10,199
|
|
|
|
12,321
|
|
|
|
6,769
|
|
|
|
4,180
|
|
Gain on Disposal, Net of Tax
|
|
|
|
|
|
|
25,774
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from Discontinued
Operations, Net of Tax
|
|
|
|
|
|
|
35,973
|
|
|
|
12,321
|
|
|
|
6,769
|
|
|
|
4,180
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income Before Cumulative Effect of
Changes in Accounting
|
|
|
138,091
|
|
|
|
189,488
|
|
|
|
166,586
|
|
|
|
187,836
|
|
|
|
117,682
|
|
Cumulative Effect of Changes in
Accounting
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(8,892
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income Available for Common
Stock
|
|
$
|
138,091
|
|
|
$
|
189,488
|
|
|
$
|
166,586
|
|
|
$
|
178,944
|
|
|
$
|
117,682
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Per Common Share
Data
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic Earnings from Continuing
Operations per Common Share
|
|
$
|
1.64
|
|
|
$
|
1.84
|
|
|
$
|
1.88
|
|
|
$
|
2.24
|
|
|
$
|
1.42
|
|
Diluted Earnings from Continuing
Operations per Common Share
|
|
$
|
1.61
|
|
|
$
|
1.81
|
|
|
$
|
1.86
|
|
|
$
|
2.23
|
|
|
$
|
1.41
|
|
Basic Earnings per Common Share(2)
|
|
$
|
1.64
|
|
|
$
|
2.27
|
|
|
$
|
2.03
|
|
|
$
|
2.21
|
|
|
$
|
1.47
|
|
Diluted Earnings per Common
Share(2)
|
|
$
|
1.61
|
|
|
$
|
2.23
|
|
|
$
|
2.01
|
|
|
$
|
2.20
|
|
|
$
|
1.46
|
|
Dividends Declared
|
|
$
|
1.18
|
|
|
$
|
1.14
|
|
|
$
|
1.10
|
|
|
$
|
1.06
|
|
|
$
|
1.03
|
|
Dividends Paid
|
|
$
|
1.17
|
|
|
$
|
1.13
|
|
|
$
|
1.09
|
|
|
$
|
1.05
|
|
|
$
|
1.02
|
|
Dividend Rate at Year-End
|
|
$
|
1.20
|
|
|
$
|
1.16
|
|
|
$
|
1.12
|
|
|
$
|
1.08
|
|
|
$
|
1.04
|
|
At September 30:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Number of Registered
Shareholders
|
|
|
17,767
|
|
|
|
18,369
|
|
|
|
19,063
|
|
|
|
19,217
|
|
|
|
20,004
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
24
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended September 30
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
2003
|
|
|
2002
|
|
|
|
(Thousands)
|
|
|
Net Property, Plant and
Equipment
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Utility
|
|
$
|
1,084,080
|
|
|
$
|
1,064,588
|
|
|
$
|
1,048,428
|
|
|
$
|
1,028,393
|
|
|
$
|
960,015
|
|
Pipeline and Storage
|
|
|
674,175
|
|
|
|
680,574
|
|
|
|
696,487
|
|
|
|
705,927
|
|
|
|
487,793
|
|
Exploration and Production
|
|
|
1,002,265
|
|
|
|
974,806
|
|
|
|
923,730
|
|
|
|
925,833
|
|
|
|
1,072,200
|
|
Energy Marketing
|
|
|
59
|
|
|
|
97
|
|
|
|
80
|
|
|
|
171
|
|
|
|
125
|
|
Timber
|
|
|
90,939
|
|
|
|
94,826
|
|
|
|
82,838
|
|
|
|
87,600
|
|
|
|
110,624
|
|
All Other
|
|
|
17,394
|
|
|
|
18,098
|
|
|
|
21,172
|
|
|
|
22,042
|
|
|
|
6,797
|
|
Corporate(3)
|
|
|
8,814
|
|
|
|
6,311
|
|
|
|
234,029
|
|
|
|
221,082
|
|
|
|
207,191
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Net Plant
|
|
$
|
2,877,726
|
|
|
$
|
2,839,300
|
|
|
$
|
3,006,764
|
|
|
$
|
2,991,048
|
|
|
$
|
2,844,745
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Assets
|
|
$
|
3,734,331
|
|
|
$
|
3,725,282
|
|
|
$
|
3,717,603
|
|
|
$
|
3,725,414
|
|
|
$
|
3,429,163
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capitalization
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive Shareholders
Equity
|
|
$
|
1,443,562
|
|
|
$
|
1,229,583
|
|
|
$
|
1,253,701
|
|
|
$
|
1,137,390
|
|
|
$
|
1,006,858
|
|
Long-Term Debt, Net of Current
Portion
|
|
|
1,095,675
|
|
|
|
1,119,012
|
|
|
|
1,133,317
|
|
|
|
1,147,779
|
|
|
|
1,145,341
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Capitalization
|
|
$
|
2,539,237
|
|
|
$
|
2,348,595
|
|
|
$
|
2,387,018
|
|
|
$
|
2,285,169
|
|
|
$
|
2,152,199
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Certain prior year amounts have been reclassified to conform
with current year presentation. |
|
(2) |
|
Includes discontinued operations and cumulative effect of
changes in accounting. |
|
(3) |
|
Includes net plant of the former international segment as
follows: $27 for 2006, $20 for 2005, $227,905 for 2004, $219,199
for 2003, and $207,191 for 2002. |
|
|
Item 7
|
Managements
Discussion and Analysis of Financial Condition and Results of
Operations
|
OVERVIEW
The Company is a diversified energy company consisting of five
reportable business segments. Refer to Item I, Business,
for a more detailed description of each of the segments. This
Item 7, MD&A, provides information concerning:
1. The critical accounting estimates of the Company;
2. Changes in revenues and earnings of the Company under
the heading, Results of Operations;
3. Operating, investing and financing cash flows under the
heading Capital Resources and Liquidity;
4. Off-Balance Sheet Arrangements;
5. Contractual Obligations; and
|
|
|
|
6.
|
Other Matters, including: a.) 2006 and 2007 funding to the
Companys defined benefit retirement plan and
post-retirement benefit plan, b.) realizability of deferred tax
assets, c.) disclosures and tables concerning market risk
sensitive instruments, d.) rate and regulatory matters in the
Companys New York, Pennsylvania and FERC regulated
jurisdictions, e.) environmental matters, and f.) new accounting
pronouncements.
|
The information in MD&A should be read in conjunction with
the Companys financial statements in Item 8 of this
report.
25
The event that had the most significant earnings impact in 2006,
and the main reason for the significant earnings decrease over
2005, was the Exploration and Production segment recording
after-tax impairment charges totaling $68.6 million related
to its Canadian oil and gas assets during 2006 under the full
cost method of accounting, which is discussed below under
Critical Accounting Estimates. In addition, the Companys
earnings for 2006 as compared to 2005 are impacted by the
Companys 2005 sale of its entire 85.16% interest in U.E.,
a district heating and electric generation business in the Czech
Republic. This sale resulted in a $25.8 million gain in
2005, net of tax. As a result of the decision to sell its
majority interest in U.E., the Company began presenting the
Czech Republic operations as discontinued operations in June
2005. With this change in presentation, the Company discontinued
all reporting for an International segment. Any remaining
international activity has been included in corporate operations
for all periods presented below. The Companys earnings are
discussed further in the Results of Operations section that
follows.
From a capital resources and liquidity perspective, the Company
spent $294.2 million on capital expenditures during 2006,
with approximately 71% being spent in the Exploration and
Production segment. This is in line with the Companys
expectations. In November 2006, the Company announced that it
had selected EOG Resources, Inc. (EOG) to jointly explore
approximately 770,000 acres of the Companys mineral
holdings and 130,000 acres of EOGs mineral holdings
in Pennsylvania and New York. EOG will be the operator and the
primary exploration targets are the Devonian black shales, which
have similar characteristics to the prolific Barnett Shale that
is actively producing natural gas in the Fort Worth Basin.
Exploratory drilling is expected to begin in 2007; however, the
Company does not share in the initial exploratory costs and no
capital expenditures have been forecasted for 2007 related to
this joint venture.* Earliest production estimates have
production starting no sooner than 2008.*
The Company is still pursuing its Empire Connector project to
expand its natural gas pipeline operations. In July 2006, Empire
revised the planned in-service date for the Empire Connector to
extend beyond November 2007, as originally reported. The new
targeted in-service date is November 2008, or sooner if
feasible.* On July 20, 2006, FERC issued a Preliminary
Determination regarding the rate and non-environmental aspects
of Empires application for FERC approval. Empire then made
a compliance filing on September 18, 2006 regarding certain
non-environmental issues, which is discussed further in the
Capital Resources and Liquidity section that follows. On
October 13, 2006, FERC subsequently issued a final
environmental impact statement on the Empire Connector project
and the other related downstream projects, indicating that FERC
has not identified any environmental reasons why those projects
could not be built. There are no other significant changes in
the status of the project and the Company continues to await
final FERC approval to build and operate the project.
The Company also began repurchasing outstanding shares of common
stock during the quarter ended March 31, 2006 under a share
repurchase program authorized by the Companys Board of
Directors. The program authorizes the Company to repurchase up
to an aggregate amount of 8 million shares. Through
September 30, 2006, the Company had repurchased
2,526,550 shares. These matters are discussed further in
the Capital Resources and Liquidity section that follows.
From a rate and regulatory matters perspective, management is
concerned with declining usage per customer in the Utility
segment. It has been one of the items leading to the filing of
rate cases in New York and Pennsylvania. In Pennsylvania, the
Company filed a rate case in June 2006 that included a revenue
decoupling mechanism, or a conservation tracker. A settlement
for this rate case was reached in October 2006, and while the
revenue decoupling mechanism was withdrawn in order to achieve
the settlement, the PaPUC instituted a generic proceeding to
look at rate mechanisms such as revenue decoupling across the
state. In New York, there is currently a proceeding going on to
examine revenue decoupling mechanisms.
Lastly, on April 7, 2006, the NYPSC, PaPUC and Pennsylvania
Office of Consumer Advocate filed a complaint and motion for
summary disposition against Supply Corporation with the FERC.
The complainants alleged that Supply Corporations rates
were unjust and unreasonable, and that Supply Corporation was
permitted to retain more gas from shippers than it needed for
fuel and loss. It also asked FERC to determine whether Supply
Corporation had the authority to make sales of gas retained from
shippers (which are referred to under Results of
Operations as unbundled pipeline sales). On
September 26, 2006, the active parties
26
reached a settlement in principle. On November 17, 2006,
Supply Corporation filed a motion asking FERC to approve an
uncontested settlement of the proceeding. The proposed
settlement would be implemented when and if FERC approves the
settlement, but if approved would be effective as of
December 1, 2006. This matter, including the primary
elements of the settlement, is discussed more fully in the Rate
and Regulatory Matters section that follows.
CRITICAL
ACCOUNTING ESTIMATES
The Company has prepared its consolidated financial statements
in conformity with GAAP. The preparation of these financial
statements requires management to make estimates and assumptions
that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of
the financial statements and the reported amounts of revenues
and expenses during the reporting period. Actual results could
differ from those estimates. In the event estimates or
assumptions prove to be different from actual results,
adjustments are made in subsequent periods to reflect more
current information. The following is a summary of the
Companys most critical accounting estimates, which are
defined as those estimates whereby judgments or uncertainties
could affect the application of accounting policies and
materially different amounts could be reported under different
conditions or using different assumptions. For a complete
discussion of the Companys significant accounting
policies, refer to Item 8 at Note A
Summary of Significant Accounting Policies.
Oil and Gas Exploration and Development
Costs. In the Companys Exploration and
Production segment, oil and gas property acquisition,
exploration and development costs are capitalized under the full
cost method of accounting. Under this accounting methodology,
all costs associated with property acquisition, exploration and
development activities are capitalized, including internal costs
directly identified with acquisition, exploration and
development activities. The internal costs that are capitalized
do not include any costs related to production, general
corporate overhead, or similar activities.
The Company believes that determining the amount of the
Companys proved reserves is a critical accounting
estimate. Proved reserves are estimated quantities of reserves
that, based on geologic and engineering data, appear with
reasonable certainty to be producible under existing economic
and operating conditions. Such estimates of proved reserves are
inherently imprecise and may be subject to substantial revisions
as a result of numerous factors including, but not limited to,
additional development activity, evolving production history and
continual reassessment of the viability of production under
varying economic conditions. The estimates involved in
determining proved reserves are critical accounting estimates
because they serve as the basis over which capitalized costs are
depleted under the full cost method of accounting (on a
units-of-production
basis). Unevaluated properties are excluded from the depletion
calculation until they are evaluated. Once they are evaluated,
costs associated with these properties are transferred to the
pool of costs being depleted.
In addition to depletion under the
units-of-production
method, proved reserves are a major component in the SEC full
cost ceiling test. The full cost ceiling test is an impairment
test prescribed by SEC
Regulation S-X
Rule 4-10.
The ceiling test is performed on a
country-by-country
basis and determines a limit, or ceiling, to the amount of
property acquisition, exploration and development costs that can
be capitalized. The ceiling under this test represents
(a) the present value of estimated future net revenues
using a discount factor of 10%, which is computed by applying
current market prices of oil and gas (as adjusted for hedging)
to estimated future production of proved oil and gas reserves as
of the date of the latest balance sheet, less estimated future
expenditures, plus (b) the cost of unevaluated properties
not being depleted, less (c) income taxes. The estimates of
future production and future expenditures are based on internal
budgets that reflect planned production from current wells and
expenditures necessary to sustain such future production. The
amount of the ceiling can fluctuate significantly from period to
period because of additions or subtractions to proved reserves
and significant fluctuations in oil and gas prices. The ceiling
is then compared to the capitalized cost of oil and gas
properties less accumulated depletion and related deferred
income taxes. If the capitalized costs of oil and gas properties
less accumulated depletion and related deferred taxes exceeds
the ceiling at the end of any fiscal quarter, a non-cash
impairment must be recorded to write down the book value of the
reserves to their present
27
value. This non-cash impairment cannot be reversed at a later
date if the ceiling increases. It should also be noted that a
non-cash impairment to write down the book value of the reserves
to their present value in any given period causes a reduction in
future depletion expense. Because of the decline in the price of
natural gas during the third and fourth quarters of 2006, the
book value of the Companys Canadian oil and gas properties
exceeded the ceiling at both June 30, 2006 and
September 30, 2006. Consequently, SECI recorded impairment
charges of $62.4 million ($39.5 million after-tax) in
the third quarter of 2006 and $42.3 million
($29.1 million after-tax) in the fourth quarter of 2006.
Further decreases in the price of natural gas, absent the
addition of new reserves, could result in future impairments.*
It is difficult to predict what factors could lead to future
impairments under the SECs full cost ceiling test. As
discussed above, fluctuations or subtractions to proved reserves
and significant fluctuations in oil and gas prices have an
impact on the amount of the ceiling at any point in time.
Regulation. The Company is subject to
regulation by certain state and federal authorities. The
Company, in its Utility and Pipeline and Storage segments, has
accounting policies which conform to SFAS 71, and which are
in accordance with the accounting requirements and ratemaking
practices of the regulatory authorities. The application of
these accounting policies allows the Company to defer expenses
and income on the balance sheet as regulatory assets and
liabilities when it is probable that those expenses and income
will be allowed in the ratesetting process in a period different
from the period in which they would have been reflected in the
income statement by an unregulated company. These deferred
regulatory assets and liabilities are then flowed through the
income statement in the period in which the same amounts are
reflected in rates. Managements assessment of the
probability of recovery or pass through of regulatory assets and
liabilities requires judgment and interpretation of laws and
regulatory commission orders. If, for any reason, the Company
ceases to meet the criteria for application of regulatory
accounting treatment for all or part of its operations, the
regulatory assets and liabilities related to those portions
ceasing to meet such criteria would be eliminated from the
balance sheet and included in the income statement for the
period in which the discontinuance of regulatory accounting
treatment occurs. Such amounts would be classified as an
extraordinary item. For further discussion of the Companys
regulatory assets and liabilities, refer to Item 8 at
Note C Regulatory Matters.
Accounting for Derivative Financial
Instruments. The Company, in its Exploration and
Production segment, Energy Marketing segment, Pipeline and
Storage segment and All Other category, uses a variety of
derivative financial instruments to manage a portion of the
market risk associated with fluctuations in the price of natural
gas and crude oil. These instruments are categorized as price
swap agreements, no cost collars, options and futures contracts.
The Company, in its Pipeline and Storage segment, uses an
interest rate collar to limit interest rate fluctuations on
certain variable rate debt. In accordance with the provisions of
SFAS 133, the Company accounts for these instruments as
effective cash flow hedges or fair value hedges. As such, gains
or losses associated with the derivative financial instruments
are matched with gains or losses resulting from the underlying
physical transaction that is being hedged. To the extent that
the derivative financial instruments would ever be deemed to be
ineffective based on the effectiveness testing,
mark-to-market
gains or losses from the derivative financial instruments would
be recognized in the income statement without regard to an
underlying physical transaction. As discussed below, the Company
was required to discontinue hedge accounting for a portion of
its derivative financial instruments, resulting in a charge to
earnings in 2005.
The Company uses both exchange-traded and non exchange-traded
derivative financial instruments. The fair value of the non
exchange-traded derivative financial instruments are based on
valuations determined by the counterparties. Refer to the
Market Risk Sensitive Instruments section below for
further discussion of the Companys derivative financial
instruments.
Pension and Other Post-Retirement
Benefits. The amounts reported in the
Companys financial statements related to its pension and
other post-retirement benefits are determined on an actuarial
basis, which uses many assumptions in the calculation of such
amounts. These assumptions include the discount rate, the
expected return on plan assets, the rate of compensation
increase and, for other post-retirement benefits, the expected
annual rate of increase in per capita cost of covered medical
and prescription benefits. The discount rate used by the Company
is equal to the Moodys Aa Long-Term Corporate Bond index,
rounded to the nearest 25 basis points. The duration of the
securities underlying that index (approximately 13 years)
reasonably matches the
28
expected timing of anticipated future benefit payments
(approximately 12 years). The expected return on plan
assets assumption used by the Company reflects the anticipated
long-term rate of return on the plans current and future
assets. The Company utilizes historical investment data,
projected capital market conditions, and the plans target
asset class and investment manager allocations to set the
assumption regarding the expected return on plan assets. Changes
in actuarial assumptions and actuarial experience could have a
material impact on the amount of pension and post-retirement
benefit costs and funding requirements experienced by the
Company.* However, the Company expects to recover substantially
all of its net periodic pension and other post-retirement
benefit costs attributable to employees in its Utility and
Pipeline and Storage segments in accordance with the applicable
regulatory commission authorization.* For financial reporting
purposes, the difference between the amounts of pension cost and
post-retirement benefit cost recoverable in rates and the
amounts of such costs as determined under applicable accounting
principles is recorded as either a regulatory asset or
liability, as appropriate, as discussed above under
Regulation. Pension and post-retirement benefit
costs for the Utility and Pipeline and Storage segments
represented 96% and 97%, respectively, of the Companys
total pension and post-retirement benefit costs as determined
under SFAS 87 and SFAS 106 for the years ended
September 30, 2006 and September 30, 2005.
Changes in actuarial assumptions and actuarial experience could
also have an impact on the benefit obligation and the funded
status related to the Companys pension and post-retirement
benefit plans and could impact the Companys equity. For
example, the discount rate used to determine benefit obligations
was changed from 5.0% in 2005 to 6.25% in 2006. The change in
the discount rate reduced the pension plan projected benefit
obligation by $113.1 million and the accumulated
post-retirement benefit obligation by $77.5 million. As a
result of the discount rate change, the Company no longer had to
record a minimum pension liability adjustment at
September 30, 2006, resulting in an increase to other
comprehensive income of $107.8 million, as shown in the
Consolidated Statement of Comprehensive Income. Other examples
include actual versus expected return on plan assets, which has
an impact on the funded status of the plans, and actual versus
expected benefit payments, which has an impact on the pension
plan projected benefit obligations and the accumulated
post-retirement benefit obligation for the Post-Retirement Plan.
For 2006, actual versus expected return on plan assets resulted
in an increase to the funded status of the Retirement Plan and
the Post-Retirement Plan of $18.7 million and
$12.5 million, respectively. The actual versus expected
benefit payments for 2006 caused a decrease of $1.0 million
and $0.3 million to the projected benefit obligation and
accumulated post-retirement benefit obligation, respectively. In
calculating the projected benefit obligation for the Retirement
Plan and the accumulated post-retirement obligation for the
Post-Retirement Plan, the actuary takes into account the average
remaining service life of active participants. The average
remaining service life of active participants in the Retirement
Plan is 10 years. The average remaining service life of
active participants in the Post-Retirement Plan is 9 years.
For further discussion of the Companys pension and other
post-retirement benefits, refer to Other Matters in this
Item 7 and to Item 8 at Note G
Retirement Plan and Other Post Retirement Benefits.
RESULTS
OF OPERATIONS
EARNINGS
2006
Compared with 2005
The Companys earnings were $138.1 million in 2006
compared with earnings of $189.5 million in 2005. As
previously discussed, the Company presented its Czech Republic
operations as discontinued operations in conjunction with the
sale of U.E. The Companys earnings from continuing
operations were $138.1 million in 2006 compared with
$153.5 million in 2005. The Companys earnings from
discontinued operations were zero in 2006 compared with
$36.0 million in 2005. The decrease in earnings from
continuing operations of $15.4 million is primarily the
result of lower earnings in the Exploration and Production and
Pipeline and Storage segments offset somewhat by higher earnings
in the Utility segment, Energy Marketing segment, Timber
segment, and All Other category and a lower loss in the
Corporate category, as shown in the table below. The decrease in
earnings from discontinued operations reflects the
non-recurrence of the gain on the sale of U.E. recognized in
2005. In the discussion that follows, note that all amounts used
in the earnings discussions are
29
after tax amounts. Earnings from continuing operations and
discontinued operations were impacted by several events in 2006
and 2005, including:
|
|
|
|
|
$68.6 million of impairment charges related to the
Exploration and Production segments Canadian oil and gas
assets under the full cost method of accounting using natural
gas pricing at June 30, 2006 and September 30, 2006;
|
|
|
|
An $11.2 million benefit to earnings in the Exploration and
Production segment related to income tax adjustments recognized
during 2006; and
|
|
|
|
A $2.6 million benefit to earnings in the Utility segment
related to the correction of a regulatory mechanism calculation.
|
|
|
|
|
|
A $25.8 million gain on the sale of U.E., which was
completed in July 2005. This amount is included in earnings from
discontinued operations;
|
|
|
|
A $2.6 million gain in the Pipeline and Storage segment
associated with a FERC approved sale of base gas;
|
|
|
|
A $3.9 million gain in the Pipeline and Storage segment
associated with insurance proceeds received in prior years for
which a contingency was resolved during 2005;
|
|
|
|
A $3.3 million loss related to certain derivative financial
instruments that no longer qualified as effective hedges;
|
|
|
|
A $2.7 million impairment in the value of the
Companys 50% investment in ESNE (recorded in the All Other
category), a limited liability company that owns an 80-megawatt,
combined cycle, natural gas-fired power plant in the town of
North East, Pennsylvania; and
|
|
|
|
A $1.8 million impairment of a gas-powered turbine in the
All Other category that the Company had planned to use in the
development of a co-generation plant.
|
2005
Compared with 2004
The Companys earnings were $189.5 million in 2005
compared with earnings of $166.6 million in 2004. As
previously discussed, the Company has presented its Czech
Republic operations as discontinued operations. The
Companys earnings from continuing operations were
$153.5 million in 2005 compared with $154.3 million in
2004. The Companys earnings from discontinued operations
were $36.0 million in 2005 compared with $12.3 million
in 2004. Earnings from continuing operations did not change
significantly as higher earnings in the Pipeline and Storage
segment were largely offset by lower earnings in the Utility and
Exploration and Production segments and a higher loss in the All
Other category. The increase in earnings from discontinued
operations resulted from the gain on the sale of U.E. in 2005.
Earnings from continuing operations and discontinued operations
were impacted by the 2005 events discussed above and the
following 2004 events:
2004
Events
|
|
|
|
|
A $5.2 million reduction to deferred income tax expense
resulting from a change in the statutory income tax rate in the
Czech Republic. This amount is included in earnings from
discontinued operations;
|
|
|
|
Settlement of a pension obligation which resulted in the
recording of additional expense amounting to $6.4 million,
allocated among the segments as follows: $2.2 million to
the Utility segment ($1.2 million in the New York
jurisdiction and $1.0 million in the Pennsylvania
jurisdiction), $2.0 million to the Pipeline and Storage
segment ($1.8 million to Supply Corporation and
$0.2 million to Empire State Pipeline), $0.9 million
to the Exploration and Production segment, $0.3 million to
the Energy Marketing segment and $1.0 million to the
Corporate and All Other categories;
|
30
|
|
|
|
|
An adjustment to the 2003 sale of the Companys Southeast
Saskatchewan oil and gas properties in the Exploration and
Production segment which increased 2004 earnings by
$4.6 million; and
|
|
|
|
An adjustment to the Companys 2003 sale of its timber
properties in the Timber segment, which reduced 2004 earnings by
$0.8 million.
|
Additional discussion of earnings in each of the business
segments can be found in the business segment information that
follows.
Earnings
(Loss) by Segment
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended September 30
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
|
(Thousands)
|
|
|
Utility
|
|
$
|
49,815
|
|
|
$
|
39,197
|
|
|
$
|
46,718
|
|
Pipeline and Storage
|
|
|
55,633
|
|
|
|
60,454
|
|
|
|
47,726
|
|
Exploration and Production
|
|
|
20,971
|
|
|
|
50,659
|
|
|
|
54,344
|
|
Energy Marketing
|
|
|
5,798
|
|
|
|
5,077
|
|
|
|
5,535
|
|
Timber
|
|
|
5,704
|
|
|
|
5,032
|
|
|
|
5,637
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Reportable Segments
|
|
|
137,921
|
|
|
|
160,419
|
|
|
|
159,960
|
|
All Other
|
|
|
359
|
|
|
|
(2,616
|
)
|
|
|
1,530
|
|
Corporate(1)
|
|
|
(189
|
)
|
|
|
(4,288
|
)
|
|
|
(7,225
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Earnings from Continuing
Operations
|
|
$
|
138,091
|
|
|
$
|
153,515
|
|
|
$
|
154,265
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings from Discontinued
Operations
|
|
|
|
|
|
|
35,973
|
|
|
|
12,321
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Consolidated
|
|
$
|
138,091
|
|
|
$
|
189,488
|
|
|
$
|
166,586
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Includes earnings from the former International segments
activity other than the activity from the Czech Republic
operations included in Earnings from Discontinued Operations. |
UTILITY
Revenues
Utility
Operating Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended September 30
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
|
(Thousands)
|
|
|
Retail Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
Residential
|
|
$
|
993,928
|
|
|
$
|
868,292
|
|
|
$
|
808,740
|
|
Commercial
|
|
|
166,779
|
|
|
|
145,393
|
|
|
|
137,092
|
|
Industrial
|
|
|
13,484
|
|
|
|
13,998
|
|
|
|
17,454
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,174,191
|
|
|
|
1,027,683
|
|
|
|
963,286
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Off-System Sales
|
|
|
|
|
|
|
|
|
|
|
106,841
|
|
Transportation
|
|
|
92,569
|
|
|
|
83,669
|
|
|
|
80,563
|
|
Other
|
|
|
14,003
|
|
|
|
5,715
|
|
|
|
1,951
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
1,280,763
|
|
|
$
|
1,117,067
|
|
|
$
|
1,152,641
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
31
Utility
Throughput million cubic feet (MMcf)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended September 30
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
Retail Sales:
|
|
|
|
|
|
|
|
|
|
|
|
|
Residential
|
|
|
59,443
|
|
|
|
66,903
|
|
|
|
70,109
|
|
Commercial
|
|
|
10,681
|
|
|
|
11,984
|
|
|
|
12,752
|
|
Industrial
|
|
|
985
|
|
|
|
1,387
|
|
|
|
2,261
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
71,109
|
|
|
|
80,274
|
|
|
|
85,122
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Off-System Sales
|
|
|
|
|
|
|
|
|
|
|
16,839
|
|
Transportation
|
|
|
57,950
|
|
|
|
59,770
|
|
|
|
60,565
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
129,059
|
|
|
|
140,044
|
|
|
|
162,526
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Degree
Days
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Percent (Warmer)
|
|
|
|
|
|
|
|
|
|
|
|
|
Colder Than
|
|
Year Ended September 30
|
|
|
|
|
Normal
|
|
|
Actual
|
|
|
Normal
|
|
|
Prior Year
|
|
|
2006:
|
|
|
Buffalo
|
|
|
|
6,692
|
|
|
|
5,968
|
|
|
|
(10.8
|
)%
|
|
|
(9.4
|
)%
|
|
|
|
Erie
|
|
|
|
6,243
|
|
|
|
5,688
|
|
|
|
(8.9
|
)%
|
|
|
(8.9
|
)%
|
2005:
|
|
|
Buffalo
|
|
|
|
6,692
|
|
|
|
6,587
|
|
|
|
(1.6
|
)%
|
|
|
0.2
|
%
|
|
|
|
Erie
|
|
|
|
6,243
|
|
|
|
6,247
|
|
|
|
0.1
|
%
|
|
|
2.6
|
%
|
2004:
|
|
|
Buffalo
|
|
|
|
6,729
|
|
|
|
6,572
|
|
|
|
(2.3
|
)%
|
|
|
(7.9
|
)%
|
|
|
|
Erie
|
|
|
|
6,277
|
|
|
|
6,086
|
|
|
|
(3.0
|
)%
|
|
|
(10.1
|
)%
|
2006
Compared with 2005
Operating revenues for the Utility segment increased
$163.7 million in 2006 compared with 2005. This increase
largely resulted from a $146.5 million increase in retail
gas sales revenues. Transportation revenues and other revenues
also increased by $8.9 million and $8.3 million,
respectively.
The increase in retail gas sales revenues for the Utility
segment was largely a function of the recovery of higher gas
costs (gas costs are recovered dollar for dollar in revenues),
which more than offset the revenue impact of lower retail sales
volumes, as shown in the table above. See further discussion of
purchased gas below under the heading Purchased Gas.
Warmer weather, as shown in the table above, and greater
conservation by customers due to higher natural gas commodity
prices, were the principal reasons for the decrease in retail
sales volumes.
The increase in transportation revenues was primarily due to a
$5.9 million increase in the New York jurisdictions
calculation of the symmetrical sharing component of the gas
adjustment rate. The symmetrical sharing component is a
mechanism included in Distribution Corporations New York
rate settlement that shares with customers 90% of the difference
between actual revenues received from large volume customers and
the level of revenues that were projected to be received during
the rate year. Of the $5.9 million increase,
$3.9 million was due to an
out-of-period
adjustment recorded in fiscal year 2006 when it was determined
that certain credits that had been included in the calculation
should have been removed during the implementation of a previous
rate case. The adjustment related to fiscal years 2002 through
2005.
The impact of the August 2005 New York rate case settlement was
to increase operating revenues by $19.1 million (of which
$12.4 million was an increase to other operating revenues).
This increase consisted of a base rate increase, the
implementation of a merchant function charge, the elimination of
certain bill credits, and the elimination of the gross receipts
tax surcharge. The settlement also allowed Distribution
Corporation to continue to utilize certain refunds from upstream
pipeline companies and certain other credits (referred to as the
cost mitigation reserve) to offset certain specific
expense items. In 2005, Distribution Corporation utilized
32
$7.8 million of the cost mitigation reserve, which
increased other operating revenues, to recover previous
under-collections of pension and post-retirement expenses. The
impact of that increase in other operating revenues was offset
by an equal amount of operation and maintenance expense (thus
there was no earnings impact). Distribution Corporation did not
record any entries involving the cost mitigation reserve in
2006. Other operating revenues was also impacted by two
out-of-period
regulatory adjustments recorded during 2005. The first
adjustment related to the final settlement with the Staff of the
NYPSC of the earnings sharing liability for the 2001 to 2003
time period. As a result of that settlement, the New York rate
jurisdiction recorded additional earnings sharing expense (as an
offset to other operating revenues) of $0.9 million. The
second adjustment related to a regulatory liability recorded for
previous over-collections of New York State gross receipts tax.
In preparing for the implementation of the settlement agreement
in New York, the Company determined that it needed to adjust
that regulatory liability by $3.1 million (of which
$1.0 million was recorded as a reduction of other operating
revenues and $2.1 million was recorded as additional
interest expense) related to fiscal years 2004 and prior. These
adjustments did not recur in 2006.
In the Pennsylvania jurisdiction, the impact of the base rate
increase, which became effective in mid-April 2005, was to
increase operating revenues by $7.5 million. This increase
is included within both retail and transportation revenues in
the table above.
2005
Compared with 2004
Operating revenues for the Utility segment decreased
$35.6 million in 2005 compared with 2004. This resulted
primarily from the absence of off-system sales revenues of
$106.8 million, offset by an increase of $64.4 million
in retail revenues. Effective September 22, 2004,
Distribution Corporation stopped making off-system sales as a
result of the FERCs Order 2004, Standards of Conduct
for Transmission Providers. However, due to profit sharing
with retail customers, the margins resulting from off-system
sales have been minimal and there was not a material impact to
margins in 2005. The increase in retail revenues was primarily
the result of the recovery of higher gas costs (gas costs are
recovered dollar for dollar in revenues), colder weather in the
Pennsylvania jurisdiction and the impact of base rate increases
in both New York and Pennsylvania. The recovery of higher gas
costs resulted from a much higher cost of purchased gas. See
further discussion of purchased gas below under the heading
Purchased Gas. Lower retail sales volumes, due
primarily to lower customer usage per account, partially offset
the increase in retail revenues associated with the recovery of
higher gas costs and the base rate increases. Also, retail
industrial sales revenue declined due to fuel switching and
production declines of certain large volume industrial customers
as a result of a general economic downturn in the Utility
segments service territory.
The increase in other operating revenues of $3.8 million is
largely related to amounts recorded pursuant to rate settlements
with the NYPSC. In accordance with these settlements,
Distribution Corporation was allowed to utilize certain refunds
from upstream pipeline companies and certain other credits
(referred to as the cost mitigation reserve) to
offset certain specific expense items, as discussed above.
Purchased
Gas
The cost of purchased gas is the Companys single largest
operating expense. Annual variations in purchased gas costs are
attributed directly to changes in gas sales volumes, the price
of gas purchased and the operation of purchased gas adjustment
clauses.
Currently, Distribution Corporation has contracted for long-term
firm transportation capacity with Supply Corporation and six
other upstream pipeline companies, for long-term gas supplies
with a combination of producers and marketers, and for storage
service with Supply Corporation and three nonaffiliated
companies. In addition, Distribution Corporation satisfies a
portion of its gas requirements through spot market purchases.
Changes in wellhead prices have a direct impact on the cost of
purchased gas. Distribution Corporations average cost of
purchased gas, including the cost of transportation and storage,
was $12.07 per Mcf in 2006, an increase of 31% from the
average cost of $9.19 per Mcf in 2005. The average cost of
purchased gas in 2005 was 26% higher than the average cost of
$7.30 per Mcf in 2004. Additional discussion of the Utility
segments gas purchases appears under the heading
Sources and Availability of Raw Materials in
Item 1.
33
Earnings
2006
Compared with 2005
The Utility segments earnings in 2006 were
$49.8 million, an increase of $10.6 million when
compared with earnings of $39.2 million in 2005.
In the New York jurisdiction, earnings increased by
$9.2 million, primarily due to the positive impact of the
rate case settlement in this jurisdiction that became effective
August 2005 ($13.7 million). In addition, the increase in
the New York jurisdictions calculation of the symmetrical
sharing component of the gas adjustment rate, including the
out-of-period
adjustment discussed above, contributed $3.9 million to
earnings. Two
out-of-period
regulatory adjustments recorded during fiscal year 2005 that did
not recur during 2006, as discussed above, also contributed an
additional $2.6 million to earnings. The first adjustment,
related to the final settlement with the Staff of the NYPSC of
the earnings sharing liability for the fiscal 2001 through 2003
time period, increased earnings in fiscal 2006 by
$0.6 million. The second adjustment, related to a
regulatory liability recorded for previous over-collections of
New York State gross receipts tax, increased earnings in fiscal
2006 by $2.0 million. The increase in earnings due to the
New York rate case settlement, the symmetrical sharing component
of the gas adjustment rate, and the two
out-of-period
regulatory adjustments recorded in 2005, was partially offset by
a decline in margin associated with lower weather-normalized
usage by customers ($2.3 million), higher operation
expenses ($2.5 million), higher interest expense
($2.7 million), and a higher effective income tax rate
($3.2 million). The higher effective income tax rate is due
to positive tax adjustments recorded in 2005 that did not recur
in 2006. The increase in operation expenses consisted primarily
of higher pension expense offset by lower bad debt expense.
In the Pennsylvania jurisdiction, earnings increased by
$1.4 million, due to the positive impact of the rate case
settlement in this jurisdiction that became effective April 2005
($4.9 million), and lower operation expenses
($1.8 million). The decrease in operation expenses
consisted primarily of lower bad debt expense offset partially
by higher pension expense. These increases to earnings were
partially offset by the impact of warmer than normal weather in
Pennsylvania ($3.0 million), lower weather-normalized usage
by customer ($0.6 million), higher interest expense
($0.8 million), and a higher effective tax rate
($1.3 million).
The decrease in bad debt expense reflects the fact that in the
fourth quarter of 2005, the New York and Pennsylvania
jurisdictions increased the allowance for uncollectible accounts
to reflect the increase in final billed account balances and the
increased aging of outstanding active receivables heading into
the heating season. A similar adjustment was not required in
2006.
The impact of weather on the Utility segments New York
rate jurisdiction is tempered by a WNC. The WNC, which covers
the eight-month period from October through May, has had a
stabilizing effect on earnings for the New York rate
jurisdiction. In addition, in periods of colder than normal
weather, the WNC benefits the Utility segments New York
customers. In 2006, the WNC preserved earnings of approximately
$6.2 million because it was warmer than normal in the New
York service territory. In 2005, the WNC did not have a
significant impact on earnings.
2005
Compared with 2004
The Utility segments earnings in 2005 were
$39.2 million, a decrease of $7.5 million when
compared with earnings of $46.7 million in 2004. The major
factors driving this decrease were lower weather-normalized
usage per customer account in both the New York and Pennsylvania
jurisdictions ($8.2 million) and an increase in bad debt
expenses of $6.7 million. The increase in bad debt expenses
is attributable to the increase in the allowance for
uncollectible accounts to reflect the increase in final billed
balances, as well as the increased age of outstanding
receivables heading into the heating season. These negative
factors were partially offset by the impact of base rate
increases in both New York and Pennsylvania ($3.9 million)
and the recording of accrued interest on a pension related asset
in accordance with the New York rate case settlement agreement
($2.4 million), as well as the impact of colder than normal
weather in Pennsylvania ($1.0 million). The earnings impact
of the two
out-of-period
regulatory adjustments discussed above was largely offset by
lower interest expense on borrowings due to lower debt balances.
34
In 2005, the WNC did not have a significant impact on earnings.
For 2004, the WNC preserved earnings of approximately
$1.0 million because it was warmer than normal in the New
York service territory.
PIPELINE
AND STORAGE
Revenues
Pipeline
and Storage Operating Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended September 30
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
|
(Thousands)
|
|
|
Firm Transportation
|
|
$
|
118,551
|
|
|
$
|
117,146
|
|
|
$
|
120,443
|
|
Interruptible Transportation
|
|
|
4,858
|
|
|
|
4,413
|
|
|
|
3,084
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
123,409
|
|
|
|
121,559
|
|
|
|
123,527
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Firm Storage Service
|
|
|
66,718
|
|
|
|
65,320
|
|
|
|
63,962
|
|
Interruptible Storage Service
|
|
|
39
|
|
|
|
267
|
|
|
|
20
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
66,757
|
|
|
|
65,587
|
|
|
|
63,982
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
|
|
|
24,186
|
|
|
|
28,713
|
|
|
|
22,198
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
214,352
|
|
|
$
|
215,859
|
|
|
$
|
209,707
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pipeline
and Storage Throughput (MMcf)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended September 30
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
Firm Transportation
|
|
|
363,379
|
|
|
|
357,585
|
|
|
|
338,991
|
|
Interruptible Transportation
|
|
|
11,609
|
|
|
|
14,794
|
|
|
|
12,692
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
374,988
|
|
|
|
372,379
|
|
|
|
351,683
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006
Compared with 2005
Operating revenues for the Pipeline and Storage segment
decreased $1.5 million in 2006 as compared with 2005. This
decrease consisted of a $4.5 million decrease in other
revenues offset by a $1.8 million increase in firm and
interruptible transportation revenues and a $1.2 million
increase in firm and interruptible storage service revenues. The
decrease in other revenues is primarily due to a
$2.6 million decrease in revenues from unbundled pipeline
sales, due to lower natural gas prices, as well as a
$0.7 million decrease in cashout revenues. Cashout revenues
are completely offset by purchased gas expense. The increase in
firm and interruptible transportation revenues is due to
additional contracts with customers and the renewal of contracts
at higher rates, both of which reflect the increased demand for
transportation services due to market conditions resulting from
the effects of hurricane damage to production and pipeline
infrastructure in the Gulf of Mexico during the fall of 2005.
While Supply Corporations transportation volumes increased
during the year, volume fluctuations generally do not have a
significant impact on revenues as a result of Supply
Corporations straight fixed-variable rate design. The
increase in storage revenues reflects the renewal of storage
contracts at higher rates.
2005
Compared with 2004
Operating revenues for the Pipeline and Storage segment
increased $6.2 million in 2005 as compared with 2004. This
increase is primarily attributable to higher revenues from
unbundled pipeline sales of $5.5 million included in other
revenues in the table above, due to higher natural gas prices.
Higher cashout revenues of $1.1 million, reported as part
of other revenues in the table above, also contributed to the
increase. Cashout revenues are completely offset by purchased
gas expense. In addition, interruptible transportation revenues
increased by $1.3 million, primarily due to an increase in
Supply Corporations gathering revenues, and firm
35
storage revenues increased $1.4 million, primarily due to
higher rate agreements contracted with Supply Corporation
customers. Offsetting these increases, the decrease in firm
transportation revenues of $3.3 million reflects the
cancellation of contracts with Supply Corporation by certain
large usage non-affiliated customers ($2.6 million) and the
Utility segments cancellation of a portion of its firm
transportation with Supply Corporation in April 2005
($0.6 million). In addition, firm transportation revenues
decreased by $1.0 million because Supply Corporation no
longer charges customers a surcharge for its membership to the
Gas Research Institute (GRI). The decrease in revenues resulting
from cancellation of the GRI surcharge was completely offset by
lower operation expense. While Supply Corporations
transportation volumes increased during the year, volume
fluctuations generally do not have a significant impact on
revenues as a result of Supply Corporations straight
fixed-variable rate design. Offsetting the decreases in Supply
Corporations firm transportation revenues was a
$1.0 million increase in Empires firm transportation
revenues, primarily due to an increase in transportation volumes.
Earnings
2006
Compared with 2005
The Pipeline and Storage segments earnings in 2006 were
$55.6 million, a decrease of $4.9 million when
compared with earnings of $60.5 million in 2005. The
decrease reflects the non-recurrence of two events, a
$2.6 million gain on a FERC approved sale of base gas in
2005 and a $3.9 million gain associated with insurance
proceeds received in prior years for which a contingency was
resolved in 2005. Both of these items were recorded in Other
Income. It also reflects the earnings impact associated with
lower revenues from unbundled pipeline sales ($1.7 million)
and higher operation expenses ($0.6 million). These
earnings decreases were offset by the positive earnings impact
of higher transportation and storage revenues
($2.0 million), lower depreciation due to the
non-recurrence of a write-down of the Companys former
corporate office in 2005 ($0.9 million), and the earnings
benefit associated with a lower effective tax rate
($1.7 million).
2005
Compared with 2004
The Pipeline and Storage segments earnings in 2005 were
$60.5 million, an increase of $12.8 million when
compared with earnings of $47.7 million in 2004.
Contributing to the increase was a gain of $3.9 million
associated with the insurance proceeds received in prior years
for which a contingency was resolved during 2005. The other main
factors contributing to the increase were higher revenues from
unbundled pipeline sales ($3.6 million), lower interest
expense ($2.4 million), $2.0 million of expense that
did not recur in 2005 associated with the settlement of a
pension obligation recognized in 2004, as well as a
$2.6 million gain on the FERC approved sale of base gas in
March, 2005. An increase in the reserve for preliminary project
costs associated with the Empire Connector project
($1.8 million) partially offset these increases.
EXPLORATION
AND PRODUCTION
Revenues
Exploration
and Production Operating Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended September 30
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
|
(Thousands)
|
|
|
Gas (after Hedging)
|
|
$
|
184,268
|
|
|
$
|
181,713
|
|
|
$
|
167,127
|
|
Oil (after Hedging)
|
|
|
148,293
|
|
|
|
107,801
|
|
|
|
119,564
|
|
Gas Processing Plant
|
|
|
42,252
|
|
|
|
36,350
|
|
|
|
28,614
|
|
Other
|
|
|
3,771
|
|
|
|
(2,733
|
)
|
|
|
1,815
|
|
Intrasegment Elimination(1)
|
|
|
(31,704
|
)
|
|
|
(29,706
|
)
|
|
|
(23,422
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
346,880
|
|
|
$
|
293,425
|
|
|
$
|
293,698
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
36
|
|
|
(1) |
|
Represents the elimination of certain West Coast gas production
revenue included in Gas (after Hedging) in the table
above that is sold to the gas processing plant shown in the
table above. An elimination for the same dollar amount was made
to reduce the gas processing plants Purchased Gas expense. |
Production
Volumes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended September 30
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
Gas Production
(MMcf)
|
|
|
|
|
|
|
|
|
|
|
|
|
Gulf Coast
|
|
|
9,110
|
|
|
|
12,468
|
|
|
|
17,596
|
|
West Coast
|
|
|
3,880
|
|
|
|
4,052
|
|
|
|
4,057
|
|
Appalachia
|
|
|
5,108
|
|
|
|
4,650
|
|
|
|
5,132
|
|
Canada
|
|
|
7,673
|
|
|
|
8,009
|
|
|
|
6,228
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
25,771
|
|
|
|
29,179
|
|
|
|
33,013
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil Production
(Mbbl)
|
|
|
|
|
|
|
|
|
|
|
|
|
Gulf Coast
|
|
|
685
|
|
|
|
989
|
|
|
|
1,534
|
|
West Coast
|
|
|
2,582
|
|
|
|
2,544
|
|
|
|
2,650
|
|
Appalachia
|
|
|
69
|
|
|
|
36
|
|
|
|
20
|
|
Canada
|
|
|
272
|
|
|
|
300
|
|
|
|
324
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,608
|
|
|
|
3,869
|
|
|
|
4,528
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average
Prices
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended September 30
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
Average Gas Price/Mcf
|
|
|
|
|
|
|
|
|
|
|
|
|
Gulf Coast
|
|
$
|
8.01
|
|
|
$
|
7.05
|
|
|
$
|
5.61
|
|
West Coast
|
|
$
|
7.93
|
|
|
$
|
6.85
|
|
|
$
|
5.54
|
|
Appalachia
|
|
$
|
9.53
|
|
|
$
|
7.60
|
|
|
$
|
5.91
|
|
Canada
|
|
$
|
7.14
|
|
|
$
|
6.15
|
|
|
$
|
4.87
|
|
Weighted Average
|
|
$
|
8.04
|
|
|
$
|
6.86
|
|
|
$
|
5.51
|
|
Weighted Average After Hedging(1)
|
|
$
|
7.15
|
|
|
$
|
6.23
|
|
|
$
|
5.06
|
|
Average Oil Price/Barrel
(bbl)
|
|
|
|
|
|
|
|
|
|
|
|
|
Gulf Coast
|
|
$
|
64.10
|
|
|
$
|
49.78
|
|
|
$
|
35.31
|
|
West Coast(2)
|
|
$
|
56.80
|
|
|
$
|
42.91
|
|
|
$
|
31.89
|
|
Appalachia
|
|
$
|
65.28
|
|
|
$
|
48.28
|
|
|
$
|
31.30
|
|
Canada
|
|
$
|
51.40
|
|
|
$
|
42.97
|
|
|
$
|
30.94
|
|
Weighted Average
|
|
$
|
57.94
|
|
|
$
|
44.72
|
|
|
$
|
32.98
|
|
Weighted Average After Hedging(1)
|
|
$
|
41.10
|
|
|
$
|
27.86
|
|
|
$
|
26.40
|
|
|
|
|
(1) |
|
Refer to further discussion of hedging activities below under
Market Risk Sensitive Instruments and in
Note F Financial Instruments in Item 8 of
this report. |
|
(2) |
|
Includes low gravity oil which generally sells for a lower price. |
2006
Compared with 2005
Operating revenues for the Exploration and Production segment
increased $53.5 million in 2006 as compared with 2005. Oil
production revenue after hedging increased $40.5 million
due primarily to higher
37
weighted average prices after hedging ($13.24 per barrel).
This increase was offset slightly by a decrease in production
(261,000 barrels). Gas production revenue after hedging
increased $2.6 million. Increases in the weighted average
price of gas after hedging ($0.92 per Mcf) more than offset
an overall decrease in gas production (3,408 MMcf). The
decrease in gas production occurred primarily in the Gulf Coast
(a 3,358 MMcf decline), which is partly attributable to
last falls hurricane damage and partly attributable to the
expected decline rates for the Companys production in the
region. Other revenues increased $6.5 million largely due
to the non-recurrence of a $5.1 million
mark-to-market
adjustment, recorded in 2005, for losses on certain derivative
financial instruments that no longer qualified as effective
hedges due to the anticipated delays in oil and gas production
volumes caused by Hurricane Rita.
Refer to further discussion of derivative financial instruments
in the Market Risk Sensitive Instruments section
that follows. Refer to the tables above for production and price
information.
2005
Compared with 2004
Operating revenues for the Exploration and Production segment
decreased $0.3 million in 2005 as compared with 2004. Oil
production revenue after hedging decreased $11.8 million
due to a 659 Mbbl decline in production offset partly by higher
weighted average prices after hedging ($1.46 per barrel).
Most of the decrease in oil production occurred in the Gulf
Coast Region (a 545 Mbbl decrease). Gas production revenue after
hedging increased $14.6 million. Increases in the weighted
average price of gas after hedging ($1.17 per Mcf) more
than offset an overall decrease in gas production
(3,834 MMcf). Most of the decrease in gas production
occurred in the Gulf Coast (a 5,128 MMcf decline). The
decreases in Gulf Coast oil and gas production are consistent
with the expected decline rates in the region. This decrease in
Gulf Coast gas production was partially offset by a
1,781 MMcf increase in Canadian gas production. The
increase in Canadian gas production is attributable to the
Sukunka 60-E well, in which the Company has a 20% working
interest. Other revenues decreased $4.5 million largely due
to a $5.1 million
mark-to-market
adjustment for losses on certain derivative financial
instruments that no longer qualified as effective hedges due to
the anticipated delays in oil and gas production volumes caused
by Hurricane Rita. These volumes were originally forecast to be
produced in the first quarter of 2006.
Refer to further discussion of derivative financial instruments
in the Market Risk Sensitive Instruments section
that follows. Refer to the tables above for production and price
information.
Earnings
2006
Compared with 2005
The Exploration and Production segments earnings in 2006
were $21.0 million, a decrease of $29.7 million when
compared with earnings of $50.7 million in 2005. The
decrease is primarily the result of the impairment charges of
$68.6 million on this segments Canadian oil and gas
producing properties. Also, lower oil and gas production
decreased earnings by $18.5 million. Further contributing
to the decrease were higher lease operating expenses
($3.2 million), higher general and administrative and other
operating costs ($2.0 million) and higher depletion expense
($2.5 million). The increase in lease operating expenses
was primarily in the West Coast region due to higher steaming
costs associated with heavy crude oil production in the
California Midway-Sunset and North Lost Hills fields. The higher
steaming costs are due to an increase in the price for natural
gas purchased in the field and used in the steaming operations,
primarily in the second quarter of fiscal 2006, compared to the
second quarter of fiscal 2005. Beginning in April 2006, a
scrubber facility in the Midway-Sunset field was in full
operation and is burning waste gas rather than purchased gas to
generate the steam for its thermal recovery project. It is
anticipated that the scrubber facility will reduce steaming
costs in the future.* The increase in depletion expense was
mainly due to higher finding and development costs in the
Canadian region, coupled with a 10.5 Bcfe downward revision
of the proved reserve estimate (resulting in an increase to the
per unit depletion rate) in this region in 2006. Partially
offsetting these decreases, higher oil and gas prices, as
discussed above, contributed $46.5 million to earnings.
Also, the non-recurrence of the 2005
mark-to-market
adjustment discussed under Revenues above, contributed
$3.3 million to earnings and strong cash flow provided
higher interest income ($2.6 million). In the second
quarter of 2006, a $5.1 million benefit to earnings
38
was realized for an adjustment to a deferred income tax balance.
Under GAAP, a company may recognize the benefit of certain
expected future income tax deductions as a deferred tax asset
only if it anticipates sufficient future taxable income to
utilize those deductions. As a result of the rise in commodity
prices, the Company increased its forecast of future taxable
income in the Exploration and Production segments Canadian
division and, as a result, recorded a deferred tax asset for
certain drilling costs that it now expects to deduct on future
income tax returns. In the third quarter of 2006, a
$6.1 million benefit to earnings related to income taxes
was recognized. The Company reversed a valuation allowance
($2.9 million) associated with the capital loss
carryforward that resulted from the 2003 sale of certain of
Senecas oil properties, and also recognized a tax benefit
of $3.2 million related to the favorable resolution of
certain open tax issues.
2005
Compared with 2004
The Exploration and Production segments earnings in 2005
were $50.7 million, a decrease of $3.6 million when
compared with earnings of $54.3 million in 2004. Lower oil
and gas production, as discussed above, decreased earnings by
$23.9 million. Also, in 2004, the Company recorded an
adjustment to the sale of its Southeast Saskatchewan properties
that increased 2004 earnings by $4.6 million. In 2005, the
Company recorded a
mark-to-market
adjustment, as discussed above under Revenues, that
decreased 2005 earnings by $3.3 million. Higher lease
operating and depletion expenses also decreased 2005 earnings by
$2.1 million and $0.6 million, respectively. The
increase in lease operating expenses resulted mainly from
increased Canadian production and higher steaming costs
associated with heavy crude oil production in the West Coast
Region. Depletion expense increased despite a drop in production
mostly due to an increase in the per unit depletion rate, which
was largely the result of the higher finding and development
costs experienced by Seneca in 2005. All of these factors, which
collectively resulted in a $34.5 million decrease in 2005
earnings, were partially offset by higher oil and gas prices, as
discussed above, that contributed $25.9 million to
earnings. Also, 2005 earnings benefited from higher interest
income ($1.8 million) and lower interest expense
($1.2 million). The fluctuations in interest income and
interest expense reflect the fact that the Exploration and
Production segment has been operating solely within its own cash
flow from operations. Short-term borrowings have been eliminated
and excess cash has been invested, resulting in higher interest
income. This excess cash will be used to fund operations and
future capital expenditures.* Lower general and administrative
expenses, largely due to lower legal costs, also increased 2005
earnings by $1.0 million.
ENERGY
MARKETING
Revenues
Energy
Marketing Operating Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended September 30
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
|
(Thousands)
|
|
|
Natural Gas (after Hedging)
|
|
$
|
496,769
|
|
|
$
|
329,560
|
|
|
$
|
283,747
|
|
Other
|
|
|
300
|
|
|
|
154
|
|
|
|
602
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
497,069
|
|
|
$
|
329,714
|
|
|
$
|
284,349
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy
Marketing Volumes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended September 30
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
Natural Gas (MMcf)
|
|
|
45,270
|
|
|
|
40,683
|
|
|
|
41,651
|
|
2006
Compared with 2005
Operating revenues for the Energy Marketing segment increased
$167.4 million in 2006 as compared with 2005. The increase
primarily reflects higher natural gas commodity prices that were
recovered through revenues, and, to a lesser extent, an increase
in throughput. The increase in throughput was due to the
39
addition of certain large commercial and industrial customers,
which more than offset any decrease in throughput due to warmer
weather and greater conservation by customers due to higher
natural gas prices.
2005
Compared with 2004
Operating revenues for the Energy Marketing segment increased
$45.4 million in 2005 as compared with 2004. The increase
primarily reflects an increase in the price of natural gas.
Volumes were down compared to the prior year due to the loss of
certain lower margin wholesale customers.
Earnings
2006
Compared with 2005
The Energy Marketing segments earnings in 2006 were
$5.8 million, an increase of $0.7 million when
compared with earnings of $5.1 million in 2005. Despite
warmer weather and greater conservation by customers, gross
margin increased due to a number of factors, including higher
volumes and the marketing flexibility associated with stored
gas. The Energy Marketing segments contracts for
significant storage and transportation volumes provided
operational flexibility resulting in increased sales throughput
and earnings. The increase in gross margin more than offset an
increase in operation expense.
2005
Compared with 2004
The Energy Marketing segments earnings in 2005 were
$5.1 million, a decrease of $0.4 million when compared
with earnings of $5.5 million in 2004. The decrease
primarily reflects lower margins caused by a reduction in the
benefit of storage gas and, to a lesser extent, lower throughput.
TIMBER
Revenues
Timber
Operating Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended September 30
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
|
(Thousands)
|
|
|
Log Sales
|
|
$
|
23,077
|
|
|
$
|
22,478
|
|
|
$
|
21,790
|
|
Green Lumber Sales
|
|
|
7,123
|
|
|
|
7,296
|
|
|
|
5,923
|
|
Kiln Dry Lumber Sales
|
|
|
32,809
|
|
|
|
29,651
|
|
|
|
27,416
|
|
Other
|
|
|
2,020
|
|
|
|
1,861
|
|
|
|
841
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
65,029
|
|
|
$
|
61,286
|
|
|
$
|
55,970
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Timber
Board Feet
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended September 30
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
|
(Thousands)
|
|
|
Log Sales
|
|
|
9,527
|
|
|
|
7,601
|
|
|
|
6,848
|
|
Green Lumber Sales
|
|
|
10,454
|
|
|
|
10,489
|
|
|
|
9,552
|
|
Kiln Dry Lumber Sales
|
|
|
16,862
|
|
|
|
15,491
|
|
|
|
15,020
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
36,843
|
|
|
|
33,581
|
|
|
|
31,420
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006
Compared with 2005
Operating revenues for the Timber segment increased
$3.7 million in 2006 as compared with 2005. This increase
can be chiefly attributed to an increase in kiln dry lumber
sales of $3.2 million principally due to an increase in
kiln dry cherry lumber sales volumes of 2.0 million board
feet. Other kiln dry lumber sales volumes
40
decreased by 0.6 million board feet, but there was little
impact to revenues. The addition of two new kilns in February
2005 allowed for greater processing capacity in 2006 as compared
to 2005 since the kilns were in operation for all of 2006.
Higher log sales revenue of $0.6 million also contributed
to the increase in revenues. An increase in cherry export log
sales as a result of greater market demand and an increase in
saw log sales were the primary factors contributing to the
increase. Offsetting these increases was a decline in cherry
veneer log sales due to lower volumes of cherry veneer logs
harvested because of unfavorable weather conditions.
2005
Compared with 2004
Operating revenues for the Timber segment increased
$5.3 million in 2005 as compared with 2004. This increase
can be partially attributed to an increase in kiln dry lumber
sales of $2.2 million largely due to an increase in cherry
lumber sales volumes of 1.6 million board feet. While there
was a decline in kiln dry lumber sales volumes from other
species (1.1 million board feet), the revenue from those
species is not significant. Cherry kiln dry lumber revenues
represent over 90% of the Timber segments total kiln dry
lumber revenues. The increase in volume is a result of the
addition of two new kilns as discussed above, allowing for an
increase in the amount of kiln dry lumber that can be processed.
In addition, green lumber sales also increased by
$1.4 million due to increased sales of maple green lumber
primarily as a result of favorable weather conditions that
allowed for an increase in harvesting.
Earnings
2006
Compared with 2005
The Timber segment earnings in 2006 were $5.7 million, an
increase of $0.7 million when compared with earnings of
$5.0 million in 2005. Higher margins from kiln dry lumber
sales and cherry export log sales accounted for the earnings
increase.
2005
Compared with 2004
The Timber segment earnings in 2005 were $5.0 million, a
decrease of $0.6 million when compared with earnings of
$5.6 million in 2004. Increases in the cost of goods sold
during 2005 due to a greater amount of timber being harvested on
purchased stumpage, which has a higher cost basis than other raw
material sources, is primarily responsible for the earnings
decline. Also contributing to the decline were overall increases
in operating expenses due to higher utility costs. Partially
offsetting these declines in earnings were the increased sales
of kiln dry lumber and green lumber discussed above, as well as
the favorable earnings impact associated with the non-recurrence
of a $0.8 million loss recorded in 2004 related to the
Companys fiscal 2003 sale of timber properties. In 2004,
the Company received final timber cruise information of the
properties it sold in 2003 and, based on that information,
determined that property records pertaining to $1.3 million
of timber property were not properly shown as having been
transferred to the purchaser. As a result, the Company removed
those assets from its property records and adjusted the
previously recognized gain downward by recognizing a loss of
$0.8 million.
ALL OTHER
AND CORPORATE OPERATIONS
All Other and Corporate Operations primarily includes the
operations of Horizon LFG, Horizon Power, former International
segment activity other than the activity from the Czech Republic
operations, and corporate operations. Horizon LFG owns and
operates short-distance landfill gas pipeline companies. Horizon
Powers activity primarily consists of equity method
investments in Seneca Energy, Model City and ESNE. Horizon Power
has a 50% ownership interest in each of these entities. The
income from these equity method investments is reported as
Operations of Unconsolidated Subsidiaries on the Consolidated
Statement of Income. Seneca Energy and Model City generate and
sell electricity using methane gas obtained from landfills owned
by outside parties. ESNE generates electricity from an
80-megawatt, combined cycle, natural gas-fired power plant in
North East, Pennsylvania. Horizon Power also owns a gas-powered
turbine and other assets which it had planned to use in the
development of a co-generation plant. The Company is in the
process of selling these
41
assets. The former International segment activity primarily
consists of project development activities, the largest being
projects in Italy and Bulgaria.
Earnings
2006
Compared with 2005
All Other and Corporate operations experienced income of
$0.2 million in 2006, which was $7.1 million greater
than a loss of $6.9 million in 2005. The increase is due
primarily to the non-recurrence of $4.5 million of
impairment charges recorded in 2005, as discussed below. Also
contributing to the increase were higher interest income
($4.7 million) during 2006, resulting primarily from the
investment of proceeds from the sale of U.E. in July 2005,
combined with higher average interest rates in 2006 versus 2005.
These increases were partially offset by higher operating
expenses ($1.3 million) and lower margins on landfill gas
sales ($0.5 million).
2005
Compared with 2004
All Other and Corporate operations experienced a loss of
$6.9 million in 2005, which was $1.2 million greater
than a loss of $5.7 million in 2004. During 2005, Horizon
Power recorded a $2.7 million impairment in the value of
its 50% investment in ESNE. Management determined that there was
a decline in the fair market value of ESNE that was other than
temporary in nature given continuing high commodity prices for
natural gas and the negative impact these prices had on
operations. ESNE has experienced losses over the last few years.
It also recorded a $1.8 million impairment of the
gas-powered turbine mentioned above. This impairment was based
on a review of current market prices for similar turbines.
However, these impairments were partially offset by higher
equity method income from Horizon Powers investments in
Seneca Energy and Model City ($1.4 million). Horizon
LFGs earnings decreased by $1.3 million due to lower
margins on gas sales. The overall decreases experienced by
Horizon Power and Horizon LFG were partially offset by a
$1.7 million improvement in the losses experienced by the
former International segment, largely due to lower project
development costs, and a $1.2 million improvement in
earnings of Corporate operations.
INTEREST
INCOME
Interest income was $3.8 million higher in 2006 compared to
2005. As discussed in the earnings discussion by segment above,
the main reasons for this increase were strong cash flow from
operations, the investment of proceeds from the sale of U.E. in
July 2005 and higher average annual interest rates.
Additionally, interest income on a pension related asset in
accordance with the New York rate case settlement agreement
increased by $0.5 million.
Interest income was $4.7 million higher in 2005 compared to
2004. As discussed in the earnings discussion by segment above,
the main reason for this increase was the accrual of
$3.7 million in interest on a pension related asset in
accordance with the New York rate case settlement agreement that
was completed in 2005.
OTHER
INCOME
Other income was $9.9 million lower in 2006 compared to
2005. As discussed in the earnings discussion by segment above,
the main reasons for this decrease included non-recurring gains
recorded during 2005 in the Pipeline and Storage segment related
to the sale of base gas ($2.6 million), and the disposition
of insurance proceeds ($3.9 million) received in prior
years for which a contingency was resolved.
Other income was $9.8 million higher in 2005 compared to
2004. As discussed in the earnings discussion by segment above,
the main reasons for this increase included a $2.6 million
gain in the Pipeline and Storage segment associated with a FERC
approved sale of base gas in 2005 and a $3.9 million gain
in the Pipeline and Storage segment associated with insurance
proceeds received in prior years for which a contingency was
resolved during 2005.
42
INTEREST
CHARGES
Although most of the variances in Interest Charges are discussed
in the earnings discussion by segment above, following is a
summary on a consolidated basis:
Interest on long-term debt decreased $0.6 million in 2006
and $9.7 million in 2005. The decrease in 2005 was
primarily the result of a lower average amount of long-term debt
outstanding.
Other interest charges were $3.1 million lower in 2006
compared to 2005. The decrease resulted primarily from the
non-recurrence of $2.1 million of interest expense,
discussed below, recorded by the Utility segment in 2005 and a
lower average amount of short-term debt outstanding during 2006.
Other interest charges were $2.3 million higher in 2005
compared to 2004. The increase resulted mainly from
$2.1 million of interest expense recorded by the Utility
segment as part of an adjustment to a regulatory liability
recorded for previous over-collections of New York State gross
receipts tax.
CAPITAL
RESOURCES AND LIQUIDITY
The primary sources and uses of cash during the last three years
are summarized in the following condensed statement of cash
flows:
Sources
(Uses) of Cash
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended September 30
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
|
(Millions)
|
|
|
Provided by Operating Activities
|
|
$
|
471.4
|
|
|
$
|
317.3
|
|
|
$
|
437.1
|
|
Capital Expenditures
|
|
|
(294.2
|
)
|
|
|
(219.5
|
)
|
|
|
(172.3
|
)
|
Net Proceeds from Sale of Foreign
Subsidiary
|
|
|
|
|
|
|
111.6
|
|
|
|
|
|
Net Proceeds from Sale of Oil and
Gas Producing Properties
|
|
|
|
|
|
|
1.4
|
|
|
|
7.1
|
|
Other Investing Activities
|
|
|
(3.2
|
)
|
|
|
3.2
|
|
|
|
2.0
|
|
Change in Short-Term Debt
|
|
|
|
|
|
|
(115.4
|
)
|
|
|
38.6
|
|
Reduction of Long-Term Debt
|
|
|
(9.8
|
)
|
|
|
(13.3
|
)
|
|
|
(243.1
|
)
|
Issuance of Common Stock
|
|
|
23.3
|
|
|
|
20.3
|
|
|
|
23.8
|
|
Dividends Paid on Common Stock
|
|
|
(98.2
|
)
|
|
|
(94.1
|
)
|
|
|
(89.1
|
)
|
Dividends Paid to Minority Interest
|
|
|
|
|
|
|
(12.7
|
)
|
|
|
|
|
Excess Tax Benefits Associated
with Stock- Based Compensation Awards
|
|
|
6.5
|
|
|
|
|
|
|
|
|
|
Shares Repurchased under
Repurchase Plan
|
|
|
(85.2
|
)
|
|
|
|
|
|
|
|
|
Effect of Exchange Rates on Cash
|
|
|
1.4
|
|
|
|
1.3
|
|
|
|
3.5
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Increase in Cash and Temporary
Cash Investments
|
|
$
|
12.0
|
|
|
$
|
0.1
|
|
|
$
|
7.6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING
CASH FLOW
Internally generated cash from operating activities consists of
net income available for common stock, adjusted for non-cash
expenses, non-cash income and changes in operating assets and
liabilities. Non-cash items include depreciation, depletion and
amortization, impairment of oil and gas producing properties,
impairment of investment in partnership, deferred income taxes,
income or loss from unconsolidated subsidiaries net of cash
distributions, minority interest in foreign subsidiaries, loss
on sale of timber properties, gain on sale of oil and gas
producing properties, and gain on the sale of discontinued
operations.
Cash provided by operating activities in the Utility and
Pipeline and Storage segments may vary substantially from year
to year because of the impact of rate cases. In the Utility
segment, supplier refunds, over- or under-recovered purchased
gas costs and weather may also significantly impact cash flow.
The impact of
43
weather on cash flow is tempered in the Utility segments
New York rate jurisdiction by its WNC and in the Pipeline and
Storage segment by Supply Corporations straight
fixed-variable rate design.
Cash provided by operating activities in the Exploration and
Production segment may vary from period to period as a result of
changes in the commodity prices of natural gas and crude oil.
The Company uses various derivative financial instruments,
including price swap agreements, no cost collars, options and
futures contracts in an attempt to manage this energy commodity
price risk.
Net cash provided by operating activities totaled
$471.4 million in 2006, an increase of $154.1 million
compared with the $317.3 million provided by operating
activities in 2005. Higher oil and gas revenues in the
Exploration and Production segment were primarily responsible
for the increase. A decrease in hedging collateral deposits at
September 30, 2006 in the Exploration and Production and
Energy Marketing segments also contributed to the increase.
Hedging collateral deposits serve as collateral for open
positions on exchange-traded futures contracts, exchange-traded
options and
over-the-counter
swaps and collars. The decrease from the prior year is
reflective of lower natural gas prices and a smaller number of
derivative financial instruments outstanding at
September 30, 2006 verses September 30, 2005. These
increases were partially offset by the loss of positive cash
flow from the Companys former Czech Republic operations,
which were sold in July 2005.
INVESTING
CASH FLOW
Expenditures
for Long-Lived Assets
The Companys expenditures for long-lived assets totaled
$294.2 million in 2006. The table below presents these
expenditures:
|
|
|
|
|
|
|
Year Ended
|
|
|
|
September 30,
|
|
|
|
2006
|
|
|
|
Total Expenditures
|
|
|
|
For Long-Lived
|
|
|
|
Assets
|
|
|
|
(Millions)
|
|
|
Utility
|
|
$
|
54.4
|
|
Pipeline and Storage
|
|
|
26.0
|
|
Exploration and Production
|
|
|
208.3
|
|
Timber
|
|
|
2.3
|
|
All Other and Corporate
|
|
|
3.2
|
|
|
|
|
|
|
|
|
$
|
294.2
|
|
|
|
|
|
|
Utility
The majority of the Utility capital expenditures were made for
replacement of mains and main extensions, as well as for the
replacement of service lines.
Pipeline
and Storage
The majority of the Pipeline and Storage segments capital
expenditures were made for additions, improvements and
replacements to this segments transmission and gas storage
systems.
Exploration
and Production
The Exploration and Production segments capital
expenditures were primarily well drilling and completion
expenditures and included approximately $41.8 million for
the Canadian region, $103.4 million for the Gulf Coast
region ($102.8 million for the off-shore program in the
Gulf of Mexico), $36.1 million for the West Coast region
and $27.0 million for the Appalachian region. The
significant amount spent in the Gulf Coast region is related to
high commodity prices, which has improved the economics of
investment in the area, plus
44
projected royalty relief. These amounts included approximately
$55.6 million spent to develop proved undeveloped reserves.
Timber
The majority of the Timber segment capital expenditures were
made for purchases of equipment for Highlands sawmill and
kiln operations.
Estimated
Capital Expenditures
The Companys estimated capital expenditures for the next
three years are:*
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended September 30
|
|
|
|
2007
|
|
|
2008
|
|
|
2009
|
|
|
|
(Millions)
|
|
|
Utility
|
|
$
|
56.0
|
|
|
$
|
56.0
|
|
|
$
|
57.0
|
|
Pipeline and Storage
|
|
|
62.0
|
|
|
|
110.0
|
|
|
|
84.0
|
|
Exploration and Production(1)
|
|
|
212.0
|
|
|
|
207.0
|
|
|
|
243.0
|
|
Timber
|
|
|
4.0
|
|
|
|
1.0
|
|
|
|
1.0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
334.0
|
|
|
$
|
374.0
|
|
|
$
|
385.0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Includes estimated expenditures for the years ended
September 30, 2007, 2008 and 2009 of approximately
$23 million, $22 million and $25 million,
respectively, to develop proved undeveloped reserves. |
Estimated capital expenditures for the Utility segment in 2007
will be concentrated in the areas of main and service line
improvements and replacements and, to a lesser extent, the
purchase of new equipment.*
Estimated capital expenditures for the Pipeline and Storage
segment in 2007 will be concentrated in the replacement of
transmission and storage lines, reconditioning of storage wells
and improvements of compressor stations.* The estimated capital
expenditures for 2007 also includes $39.0 million for the
Empire Connector project as discussed below.
The Company continues to explore various opportunities to expand
its capabilities to transport gas to the East Coast, either
through the Supply Corporation or Empire systems or in
partnership with others. In October 2005, Empire filed an
application with the FERC for the authority to build and operate
the Empire Connector project to expand its natural gas pipeline
operations to serve new markets in New York and elsewhere in the
Northeast by extending the Empire Pipeline. The application also
asks that Empires existing business and facilities be
brought under FERC jurisdiction, and that FERC approve rates for
Empires existing and proposed services. Assuming the
proposed Millennium Pipeline is constructed, the Empire
Connector will provide an upstream supply link for the
Millennium Pipeline and will transport Canadian and other
natural gas supplies to downstream customers, including KeySpan
Gas East Corporation, which has entered into precedent
agreements to subscribe for at least 150 MDth per day of natural
gas transportation service through the Empire State Pipeline and
the Millennium Pipeline systems.* The Empire Connector will be
designed to move up to approximately 250 MDth of natural gas per
day.* In July 2006, Empire revised the planned in-service date
for the Empire Connector to extend beyond its original November
2007 target. The new targeted in-service date is November 2008,
or sooner if feasible.* FERC issued on July 20, 2006 a
preliminary determination regarding non-environmental aspects of
the application, in response to which Empire made a request for
rehearing on August 21, 2006. Empire anticipates that FERC
will issue a final certificate authorizing construction and
operation of the project on or about December 2006, after which
Empire will have to decide whether it will accept the final
approval on the terms contained therein.* Refer to the Rate and
Regulatory Matters section that follows for further discussion
of this matter. The forecasted expenditures for this project
over the next three years are as follows: $39.0 million in
2007, $85.0 million in 2008, and $22.0 million in
2009.* These expenditures are included as Pipeline and Storage
estimated capital expenditures in the table above. The Company
anticipates financing this project with cash on hand
and/or
through the use of the Companys bi-lateral lines of
credit.* As of September 30, 2006, the Company had incurred
approximately $6.0 million in
45
costs (all of which have been reserved) related to this project.
Of this amount, $2.0 million, $3.4 million and
$0.6 million were incurred during the years ended
September 30, 2006, 2005 and 2004, respectively.
The Company also has plans to expand Supply Corporations
existing interconnect with Empire at Pendleton, New York.
Compression will be added to allow Supply Corporation
transportation and storage volumes to be delivered to Empire,
which is operated at higher pressures than Supply
Corporations system.* The Pendleton Compression project
will be a key strategic expansion for Supply Corporation,
allowing access to both Empire and Millennium markets to the
east, as well as for Empire, providing its shippers with access
to storage services and Supply Corporations array of
interconnects. Supply Corporation is in the process of
negotiating customer agreement(s), and expects to complete
design and launch the regulatory approval process in late 2006.*
There have been no costs incurred by the Company related to this
project as of September 30, 2006, and the forecasted
expenditures for this project over the next three years are as
follows: $0 in 2007, $3.0 million in 2008, and
$1.0 million in 2009.* These expenditures are included as
Pipeline and Storage estimated capital expenditures in the table
above. The target in-service date for the Pendleton Compression
project is contingent upon the Millennium/Empire Connector
timeline.* Accordingly, Supply Corporation anticipates that most
of the capital spending associated with this expansion will
occur in fiscal 2008.*
Supply Corporation continues to view the Tuscarora Extension
project as an important link to Millennium and potential storage
development in the Corning, New York area.* The new pipeline,
which would expand the Supply Corporation system from its
Tuscarora storage field to the intersection of the proposed
Millennium and Empire Connector pipelines, will be designed
initially to transport up to approximately 130 MDth of natural
gas per day. It may also provide Supply Corporation with the
opportunity to increase the deliverability of the existing
Tuscarora storage field.* The project timeline relies on market
development, and should the market mature, the Company
anticipates financing the Tuscarora Extension with cash on hand
and/or
through the use of the Companys bi-lateral lines of
credit.* There have been no costs incurred by the Company
related to this project as of September 30, 2006, and the
forecasted expenditures for this project over the next three
years are as follows: $0 in 2007 and 2008, and
$39.0 million in 2009.* These expenditures are included as
Pipeline and Storage estimated capital expenditures in the table
above. The Company has not yet filed an application with the
FERC for the authority to build and operate the Tuscarora
Extension.
Estimated capital expenditures in 2007 for the Exploration and
Production segment include approximately $34.0 million for
Canada, $100.0 million for the Gulf Coast region
($98.0 million on the off-shore program in the Gulf of
Mexico), $43.0 million for the West Coast region and
$35.0 million for the Appalachian region.*
Estimated capital expenditures in 2007 in the Timber segment
will be concentrated on the purchase of new equipment and
improvements to facilities for this segments lumber yard,
sawmill and kiln operations.*
The Company continuously evaluates capital expenditures and
investments in corporations, partnerships and other business
entities. The amounts are subject to modification for
opportunities such as the acquisition of attractive oil and gas
properties, timber or natural gas storage facilities and the
expansion of natural gas transmission line capacities. While the
majority of capital expenditures in the Utility segment are
necessitated by the continued need for replacement and upgrading
of mains and service lines, the magnitude of future capital
expenditures or other investments in the Companys other
business segments depends, to a large degree, upon market
conditions.*
FINANCING
CASH FLOW
The Company did not have any outstanding short-term notes
payable to banks or commercial paper at September 30, 2006.
However, the Company continues to consider short-term debt
(consisting of short-term notes payable to banks and commercial
paper) an important source of cash for temporarily financing
capital expenditures and investments in corporations
and/or
partnerships,
gas-in-storage
inventory, unrecovered purchased gas costs, margin calls on
derivative financial instruments, exploration and development
expenditures and other working capital needs. Fluctuations in
these items can have a significant impact on the amount and
timing of short-term debt. As for bank loans, the Company
maintains a number of individual (bi-lateral) uncommitted or
discretionary lines of credit with certain financial
institutions for general corporate purposes. Borrowings under
these lines of credit are made at competitive market rates.
These credit lines, which aggregate
46
to $445.0 million, are revocable at the option of the
financial institutions and are reviewed on an annual basis. The
Company anticipates that these lines of credit will continue to
be renewed, or replaced by similar lines.* The total amount
available to be issued under the Companys commercial paper
program is $300.0 million. The commercial paper program is
backed by a syndicated committed credit facility totaling
$300.0 million that extends through September 30, 2010.
Under the Companys committed credit facility, the Company
has agreed that its debt to capitalization ratio will not exceed
.65 at the last day of any fiscal quarter from
September 30, 2005 through September 30, 2010. At
September 30, 2006, the Companys debt to
capitalization ratio (as calculated under the facility) was .44.
The constraints specified in the committed credit facility would
permit an additional $1.56 billion in short-term
and/or
long-term debt to be outstanding (further limited by the
indenture covenants discussed below) before the Companys
debt to capitalization ratio would exceed .65. If a downgrade in
any of the Companys credit ratings were to occur, access
to the commercial paper markets might not be possible.* However,
the Company expects that it could borrow under its uncommitted
bank lines of credit or rely upon other liquidity sources,
including cash provided by operations.*
Under the Companys existing indenture covenants, at
September 30, 2006, the Company would have been permitted
to issue up to a maximum of $1.03 billion in additional
long-term unsecured indebtedness at then current market interest
rates in addition to being able to issue new indebtedness to
replace maturing debt. The Companys present liquidity
position is believed to be adequate to satisfy known demands.*
The Companys 1974 indenture, pursuant to which
$399.0 million (or 36%) of the Companys long-term
debt (as of September 30, 2006) was issued, contains a
cross-default provision whereby the failure by the Company to
perform certain obligations under other borrowing arrangements
could trigger an obligation to repay the debt outstanding under
the indenture. In particular, a repayment obligation could be
triggered if the Company fails (i) to pay any scheduled
principal or interest on any debt under any other indenture or
agreement or (ii) to perform any other term in any other
such indenture or agreement, and the effect of the failure
causes, or would permit the holders of the debt to cause, the
debt under such indenture or agreement to become due prior to
its stated maturity, unless cured or waived.
The Companys $300.0 million committed credit facility
also contains a cross-default provision whereby the failure by
the Company or its significant subsidiaries to make payments
under other borrowing arrangements, or the occurrence of certain
events affecting those other borrowing arrangements, could
trigger an obligation to repay any amounts outstanding under the
committed credit facility. In particular, a repayment obligation
could be triggered if (i) the Company or its significant
subsidiaries fail to make a payment when due of any principal or
interest on any other indebtedness aggregating
$20.0 million or more or (ii) an event occurs that
causes, or would permit the holders of any other indebtedness
aggregating $20.0 million or more to cause, such
indebtedness to become due prior to its stated maturity. As of
September 30, 2006, the Company had no debt outstanding
under the committed credit facility.
The Companys embedded cost of long-term debt was 6.4% at
both September 30, 2006 and September 30, 2005. Refer
to Interest Rate Risk in this Item for a more
detailed breakdown of the Companys embedded cost of
long-term debt.
The Company has an effective registration statement on file with
the SEC under which it has available capacity to issue an
additional $550.0 million of debt and equity securities
under the Securities Act of 1933. The Company may sell all or a
portion of the remaining registered securities if warranted by
market conditions and the Companys capital requirements.
Any offer and sale of the above mentioned $550.0 million of
debt and equity securities will be made only by means of a
prospectus meeting the requirements of the Securities Act of
1933 and the rules and regulations thereunder.
The amounts and timing of the issuance and sale of debt or
equity securities will depend on market conditions, indenture
requirements, regulatory authorizations and the capital
requirements of the Company.
On December 8, 2005, the Companys Board of Directors
authorized the Company to implement a share repurchase program,
whereby the Company may repurchase outstanding shares of common
stock, up to an aggregate amount of 8 million shares in the
open market or through privately negotiated transactions. As of
47
September 30, 2006, the Company has repurchased
2,526,550 shares under this program, funded with cash
provided by operating activities. In the future, it is expected
that this share repurchase program will continue to be funded
with cash provided by operating activities
and/or
through the use of the Companys bi-lateral lines of
credit.* It is expected that open market repurchases will
continue from time to time depending on market conditions.*
OFF-BALANCE
SHEET ARRANGEMENTS
The Company has entered into certain off-balance sheet financing
arrangements. These financing arrangements are primarily
operating and capital leases. The Companys consolidated
subsidiaries have operating leases, the majority of which are
with the Utility and the Pipeline and Storage segments, having a
remaining lease commitment of approximately $44.0 million.
These leases have been entered into for the use of buildings,
vehicles, construction tools, meters, computer equipment and
other items and are accounted for as operating leases. The
Companys unconsolidated subsidiaries, which are accounted
for under the equity method, have capital leases of electric
generating equipment having a remaining lease commitment of
approximately $7.1 million. The Company has guaranteed 50%,
or $3.5 million, of these capital lease commitments.
CONTRACTUAL
OBLIGATIONS
The following table summarizes the Companys expected
future contractual cash obligations as of September 30,
2006, and the twelve-month periods over which they occur:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payments by Expected Maturity Dates
|
|
|
|
2007
|
|
|
2008
|
|
|
2009
|
|
|
2010
|
|
|
2011
|
|
|
Thereafter
|
|
|
Total
|
|
|
|
(Millions)
|
|
|
Long-Term Debt, including interest
expense(1)
|
|
$
|
93.7
|
|
|
$
|
266.0
|
|
|
$
|
154.7
|
|
|
$
|
51.8
|
|
|
$
|
238.9
|
|
|
$
|
776.7
|
|
|
$
|
1,581.8
|
|
Operating Lease Obligations
|
|
$
|
8.1
|
|
|
$
|
7.2
|
|
|
$
|
6.0
|
|
|
$
|
4.3
|
|
|
$
|
2.7
|
|
|
$
|
15.7
|
|
|
$
|
44.0
|
|
Capital Lease Obligations
|
|
$
|
1.1
|
|
|
$
|
0.9
|
|
|
$
|
0.5
|
|
|
$
|
0.4
|
|
|
$
|
0.4
|
|
|
$
|
0.2
|
|
|
$
|
3.5
|
|
Purchase Obligations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas Purchase Contracts(2)
|
|
$
|
742.8
|
|
|
$
|
149.4
|
|
|
$
|
17.7
|
|
|
$
|
6.9
|
|
|
$
|
6.5
|
|
|
$
|
64.7
|
|
|
$
|
988.0
|
|
Transportation and Storage Contracts
|
|
$
|
50.7
|
|
|
$
|
45.8
|
|
|
$
|
31.2
|
|
|
$
|
10.7
|
|
|
$
|
3.4
|
|
|
$
|
4.1
|
|
|
$
|
145.9
|
|
Other
|
|
$
|
25.0
|
|
|
$
|
2.9
|
|
|
$
|
2.0
|
|
|
$
|
2.0
|
|
|
$
|
1.8
|
|
|
$
|
4.6
|
|
|
$
|
38.3
|
|
|
|
|
(1) |
|
Refer to Note E Capitalization and Short-Term
Borrowings, as well as the table under Interest Rate Risk in the
Market Risk Sensitive Instruments section below, for the amounts
excluding interest expense. |
|
(2) |
|
Gas prices are variable based on the NYMEX prices adjusted for
basis. |
The Company has made certain other guarantees on behalf of its
subsidiaries. The guarantees relate primarily to:
(i) obligations under derivative financial instruments,
which are included on the consolidated balance sheet in
accordance with the SFAS 133 (see Item 7, MD&A
under the heading Critical Accounting
Estimates Accounting for Derivative Financial
Instruments); (ii) NFR obligations to purchase gas or
to purchase gas transportation/storage services where the
amounts due on those obligations each month are included on the
consolidated balance sheet as a current liability; and
(iii) other obligations which are reflected on the
consolidated balance sheet. The Company believes that the
likelihood it would be required to make payments under the
guarantees is remote, and therefore has not included them in the
table above.*
OTHER
MATTERS
In addition to the legal proceedings disclosed in Item 3 of
this report, the Company is involved in other litigation and
regulatory matters arising in the normal course of business.
These other matters may include, for example, negligence claims
and tax, regulatory or other governmental audits, inspections,
investigations or other proceedings. These matters may involve
state and federal taxes, safety, compliance with regulations,
rate base, cost of service and purchased gas cost issues, among
other things. While these normal-course matters
48
could have a material effect on earnings and cash flows in the
period in which they are resolved, they are not expected to
change materially the Companys present liquidity position,
nor to have a material adverse effect on the financial condition
of the Company.*
The Company has a tax-qualified, noncontributory defined-benefit
retirement plan (Retirement Plan) that covers approximately 77%
of the Companys domestic employees. The Company has been
making contributions to the Retirement Plan over the last
several years and anticipates that it will continue making
contributions to the Retirement Plan.* During 2006, the Company
contributed $20.9 million to the Retirement Plan. The
Company anticipates that the annual contribution to the
Retirement Plan in 2007 will be in the range of
$15.0 million to $20.0 million.* The Company expects
that all subsidiaries having domestic employees covered by the
Retirement Plan will make contributions to the Retirement Plan.*
The funding of such contributions will come from amounts
collected in rates in the Utility and Pipeline and Storage
segments or through short-term borrowings or through cash from
operations.*
The Company provides health care and life insurance benefits for
substantially all domestic retired employees under a
post-retirement benefit plan (Post-Retirement Plan). The Company
has been making contributions to the Post-Retirement Plan over
the last several years and anticipates that it will continue
making contributions to the Post-Retirement Plan.* During 2006,
the Company contributed $39.3 million to the
Post-Retirement Plan. The Company anticipates that the annual
contribution to the Post-Retirement Plan in 2007 will be in the
range of $35.0 million to $45.0 million.* The funding
of such contributions will come from amounts collected in rates
in the Utility and Pipeline and Storage segments.*
A capital loss carryover of $25.1 million exists at
September 30, 2006, which expires if not utilized by
September 30, 2008. Although realization is not assured,
management determined that it is more likely than not that the
entire deferred tax asset associated with this carryover will be
realized during the carryover period. As such, the valuation
allowance of $2.9 million was reversed during 2006 as
discussed under Exploration and Production in the
Results of Operations section above.
A deferred tax asset of $9.0 million relating to Canadian
operations exists at September 30, 2006. Although
realization is not assured, management determined that it is
more likely than not that future taxable income will be
generated in Canada to fully utilize this asset, and as such, no
valuation allowance was provided.
MARKET
RISK SENSITIVE INSTRUMENTS
Energy
Commodity Price Risk
The Company, in its Exploration and Production segment, Energy
Marketing segment, Pipeline and Storage segment, and All Other
category, uses various derivative financial instruments
(derivatives), including price swap agreements, no cost collars,
options and futures contracts, as part of the Companys
overall energy commodity price risk management strategy. Under
this strategy, the Company manages a portion of the market risk
associated with fluctuations in the price of natural gas and
crude oil, thereby attempting to provide more stability to
operating results. The Company has operating procedures in place
that are administered by experienced management to monitor
compliance with the Companys risk management policies. The
derivatives are not held for trading purposes. The fair value of
these derivatives, as shown below, represents the amount that
the Company would receive from or pay to the respective
counterparties at September 30, 2006 to terminate the
derivatives. However, the tables below and the fair value that
is disclosed do not consider the physical side of the natural
gas and crude oil transactions that are related to the financial
instruments.
The following tables disclose natural gas and crude oil price
swap information by expected maturity dates for agreements in
which the Company receives a fixed price in exchange for paying
a variable price as quoted in Inside FERC or on the
NYMEX. Notional amounts (quantities) are used to calculate the
contractual payments to be exchanged under the contract. The
weighted average variable prices represent the weighted average
49
settlement prices by expected maturity date as of
September 30, 2006. At September 30, 2006, the Company
had not entered into any natural gas or crude oil price swap
agreements extending beyond 2009.
Natural
Gas Price Swap Agreements
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expected Maturity Dates
|
|
|
|
2007
|
|
|
2008
|
|
|
2009
|
|
|
Total
|
|
|
Notional Quantities (Equivalent
Bcf)
|
|
|
3.9
|
|
|
|
2.8
|
|
|
|
0.7
|
|
|
|
7.4
|
|
Weighted Average Fixed Rate (per
Mcf)
|
|
$
|
6.95
|
|
|
$
|
7.26
|
|
|
$
|
8.63
|
|
|
$
|
7.24
|
|
Weighted Average Variable Rate
(per Mcf)
|
|
$
|
7.29
|
|
|
$
|
8.37
|
|
|
$
|
8.84
|
|
|
$
|
7.85
|
|
Crude
Oil Price Swap Agreements
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expected Maturity Dates
|
|
|
|
2007
|
|
|
2008
|
|
|
Total
|
|
|
Notional Quantities (Equivalent
bbls)
|
|
|
855,000
|
|
|
|
45,000
|
|
|
|
900,000
|
|
Weighted Average Fixed Rate (per
bbl)
|
|
$
|
37.03
|
|
|
$
|
39.00
|
|
|
$
|
37.13
|
|
Weighted Average Variable Rate
(per bbl)
|
|
$
|
65.47
|
|
|
$
|
68.90
|
|
|
$
|
65.64
|
|
At September 30, 2006, the Company would have had to pay
its respective counterparties an aggregate of approximately
$7.4 million to terminate the natural gas price swap
agreements outstanding at that date. The Company would have had
to pay an aggregate of approximately $27.6 million to its
counterparties to terminate the crude oil price swap agreements
outstanding at September 30, 2006.
At September 30, 2005, the Company had natural gas price
swap agreements covering 18.8 Bcf at a weighted average
fixed rate of $5.73 per Mcf. The Company also had crude oil
price swap agreements covering 2,835,000 bbls at a weighted
average fixed rate of $35.09 per bbl. The decrease in
natural gas price swap agreements from September 2005 to
September 2006 is largely attributable to managements
decision to utilize more no cost collars as a means of hedging
natural gas production in the Exploration and Production
segment. The decrease in crude oil price swap agreements is
primarily due to the fact that the Company has not been entering
into new swap agreements for its West Coast crude oil
production. This decision is related to the price, or
basis, differential that exists between the
Companys West Coast heavy sour crude oil and the West
Texas Intermediate light sweet crude oil that is quoted on the
NYMEX. The Company has been unable to hedge against changes in
the basis differential.
The following table discloses the notional quantities, the
weighted average ceiling price and the weighted average floor
price for the no cost collars used by the Company to manage
natural gas price risk. The no cost collars provide for the
Company to receive monthly payments from (or make payments to)
other parties when a variable price falls below an established
floor price (the Company receives payment from the counterparty)
or exceeds an established ceiling price (the Company pays the
counterparty). At September 30, 2006, the Company had not
entered into any natural gas or crude oil no cost collars
extending beyond 2008.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expected Maturity Dates
|
|
|
|
2007
|
|
|
2008
|
|
|
Total
|
|
|
Natural Gas
|
|
|
|
|
|
|
|
|
|
|
|
|
Notional Quantities (Equivalent
Bcf)
|
|
|
5.7
|
|
|
|
1.4
|
|
|
|
7.1
|
|
Weighted Average Ceiling Price
(per Mcf)
|
|
$
|
17.45
|
|
|
$
|
16.45
|
|
|
$
|
17.25
|
|
Weighted Average Floor Price (per
Mcf)
|
|
$
|
8.12
|
|
|
$
|
8.83
|
|
|
$
|
8.26
|
|
50
|
|
|
|
|
|
|
2007
|
|
|
Crude Oil
|
|
|
|
|
Notional Quantities (Equivalent
bbls)
|
|
|
180,000
|
|
Weighted Average Ceiling Price
(per bbl)
|
|
$
|
77.00
|
|
Weighted Average Floor Price (per
bbl)
|
|
$
|
70.00
|
|
At September 30, 2006, the Company would have received an
aggregate of approximately $10.4 million to terminate the
natural gas no cost collars outstanding at that date. The
Company would have received $0.9 million to terminate the
crude oil no cost collars at September 30, 2006.
At September 30, 2005, the Company had natural gas no cost
collars covering 8.5 Bcf at a weighted average floor price
of $7.54 per Mcf and a weighted average ceiling price of
$15.62 per Mcf. The Company did not have any outstanding
crude oil no cost collars at September 30, 2005. The
decrease in natural gas collars from September 2005 to September
2006 is due to managements decision to curtail hedging
activity in the fourth quarter of 2006 due to the forecast of a
more active hurricane season in 2006. In 2005, the Company
recognized a $5.1 million
mark-to-market
adjustment related to derivative financial instruments that no
longer qualified as effective hedges due to production delays
caused by Hurricane Rita, and management wanted to prevent this
from recurring in 2006. When the hurricane season did not turn
out to be as active as everyone had forecasted, the pricing
strip at that time was so low that management elected to hold
off on some of the hedging. Management is reviewing that policy
and is in the process of looking at layering in more hedges in
the future.*
The following table discloses the net contract volumes purchased
(sold), weighted average contract prices and weighted average
settlement prices by expected maturity date for futures
contracts used to manage natural gas price risk. At
September 30, 2006, the Company held no futures contracts
with maturity dates extending beyond 2012.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expected Maturity Dates
|
|
|
|
2007
|
|
|
2008
|
|
|
2009
|
|
|
2010
|
|
|
2011
|
|
|
2012
|
|
|
Total
|
|
|
Net Contract Volumes Purchased
(Sold)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Equivalent Bcf)
|
|
|
7.2
|
|
|
|
(0.1
|
)
|
|
|
(0.1
|
)
|
|
|
|
|
|
|
|
(1)
|
|
|
|
(1)
|
|
|
7.0
|
|
Weighted Average Contract Price
(per Mcf)
|
|
$
|
9.63
|
|
|
$
|
9.85
|
|
|
$
|
9.57
|
|
|
|
NA
|
|
|
$
|
6.99
|
|
|
$
|
8.68
|
|
|
$
|
9.67
|
|
Weighted Average Settlement Price
(per Mcf)
|
|
$
|
10.02
|
|
|
$
|
9.58
|
|
|
$
|
9.14
|
|
|
|
NA
|
|
|
$
|
6.91
|
|
|
$
|
9.29
|
|
|
$
|
9.89
|
|
|
|
|
(1) |
|
The Energy Marketing segment has purchased 4 and 6 futures
contracts (1 contract = 2,500 Dth) for 2011 and 2012,
respectively. |
At September 30, 2006, the Company would have had to pay
$4.9 million to terminate these futures contracts.
At September 30, 2005, the Company had futures contracts
covering 2.2 Bcf (net short position) at a weighted average
contract price of $8.63 per Mcf.
The increase in net long positions in 2006 was due to the
decrease in natural gas prices in the summer months which led to
an increase in fixed price sales commitments. These commitments
were hedged with long positions in the futures market.
The Company may be exposed to credit risk on some of the
derivatives disclosed above. Credit risk relates to the risk of
loss that the Company would incur as a result of nonperformance
by counterparties pursuant to the terms of their contractual
obligations. To mitigate such credit risk, management performs a
credit check and then, on an ongoing basis, monitors
counterparty credit exposure. Management has obtained guarantees
from the parent companies of the respective counterparties to
its derivatives. At September 30, 2006, the Company used
six counterparties for its over the counter derivatives. At
September 30, 2006, no individual counterparty represented
greater than 39% of total credit risk (measured as volumes
hedged by an individual counterparty as
51
a percentage of the Companys total volumes hedged). All of
the counterparties (or the parent of the counterparty) were
rated as investment grade entities at September 30, 2006.
Exchange
Rate Risk
The Exploration and Production segments investment in
Canada is valued in Canadian dollars, and, as such, this
investment is subject to currency exchange risk when the
Canadian dollars are translated into U.S. dollars. This
exchange rate risk to the Companys investment in Canada
results in increases or decreases to the CTA, a component of
Accumulated Other Comprehensive Income/Loss on the Consolidated
Balance Sheets. When the foreign currency increases in value in
relation to the U.S. dollar, there is a positive adjustment
to CTA. When the foreign currency decreases in value in relation
to the U.S. dollar, there is a negative adjustment to CTA.
Interest
Rate Risk
The Companys exposure to interest rate risk arises
primarily from the $22.8 million of variable rate debt
included in Other Notes in the table below. To mitigate this
risk, the Company uses an interest rate collar to limit interest
rate fluctuations. Under the interest rate collar the Company
makes quarterly payments to (or receives payments from) another
party when a variable rate falls below an established floor rate
(the Company pays the counterparty) or exceeds an established
ceiling rate (the Company receives payment from the
counterparty). Under the terms of the collar, which extends
until 2009, the variable rate is based on LIBOR. The floor rate
of the collar is 5.15% and the ceiling rate is 9.375%. The
Company would have had to pay $0.1 million to terminate the
interest rate collar at September 30, 2006.
The following table presents the principal cash repayments and
related weighted average interest rates by expected maturity
date for the Companys long-term fixed rate debt as well as
the other long-term debt of certain of the Companys
subsidiaries. The interest rates for the variable rate debt are
based on those in effect at September 30, 2006:
|
|
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|
|
|
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Principal Amounts by Expected Maturity Dates
|
|
|
|
2007
|
|
|
2008
|
|
|
2009
|
|
|
2010
|
|
|
2011
|
|
|
Thereafter
|
|
|
Total
|
|
|
|
(Dollars in millions)
|
|
|
National Fuel Gas
Company
|
|
|
|
|
|
|
|
|
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-Term Fixed Rate Debt
|
|
$
|
|
|
|
$
|
200.0
|
|
|
$
|
100.0
|
|
|
$
|
|
|
|
$
|
200.0
|
|
|
$
|
595.7
|
|
|
$
|
1,095.7
|
|
Weighted Average Interest Rate Paid
|
|
|
|
|
|
|
6.3
|
%
|
|
|
6.0
|
%
|
|
|
|
|
|
|
7.5
|
%
|
|
|
6.2
|
%
|
|
|
6.4
|
%
|
Fair Value = $1,125.2
|
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|
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|
|
|
|
|
|
Other Notes
|
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-Term Debt(1)
|
|
$
|
22.9
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
22.9
|
|
Weighted Average Interest Rate
Paid(2)
|
|
|
6.5
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
6.5
|
%
|
Fair Value = $22.9
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
$22.8 million is variable rate debt. It is the
Companys intention to pay off these notes within one year.
As such, the notes have been classified as current. |
|
(2) |
|
Weighted average interest rate excludes the impact of an
interest rate collar on $22.8 million of variable rate debt. |
RATE AND
REGULATORY MATTERS
Energy
Policy Act
On August 8, 2005, President Bush signed into law the
Energy Policy Act, which, among other things, included PUHCA
2005. PUHCA 2005 repealed PUHCA 1935 effective February 8,
2006. Since that date, the Company has been free from PUHCA
1935s broad regulatory provisions, including provisions
relating to the
52
issuance of securities, sales and acquisitions of securities and
utility assets, intra-company transactions and limitations on
diversification. PUHCA 2005, among other things, grants the FERC
and state public utility regulatory commissions access to
certain books and records of companies in holding company
systems. On December 8, 2005, the FERC issued Order 667 to
implement PUHCA 2005. The FERC clarified certain aspects of
Order 667 in Order
667-A,
issued on April 24, 2006. On June 15, 2006, pursuant
to the FERCs regulations, the Company filed a
notification of holding company status with the
FERC. Also on that date, the Company filed an exemption
request with the FERC, requesting exemption of the Company
and its subsidiaries from the FERCs regulations under
PUHCA 2005. The exemption request has been granted by operation
of law pursuant to the FERCs regulations.
Utility
Operation
Base rate adjustments in both the New York and Pennsylvania
jurisdictions do not reflect the recovery of purchased gas
costs. Such costs are recovered through operation of the
purchased gas adjustment clauses of the appropriate regulatory
authorities.
New York
Jurisdiction
On August 27, 2004, Distribution Corporation commenced a
rate case by filing proposed tariff amendments and supporting
testimony requesting approval to increase its annual revenues
beginning October 1, 2004. Various parties opposed the
filing. On April 15, 2005, Distribution Corporation, the
parties and others executed an agreement settling all
outstanding issues. In an order issued July 22, 2005, the
NYPSC approved the April 15, 2005 settlement agreement,
substantially as filed, for an effective date of August 1,
2005. The settlement agreement provides for a rate increase of
$21 million by means of the elimination of bill credits
($5.8 million) and an increase in base rates
($15.2 million). For the two-year term of the agreement and
thereafter, the return on equity level above which earnings must
be shared with rate payers is 11.5%.
Pennsylvania
Jurisdiction
On June 1, 2006, Distribution Corporation filed proposed
tariff amendments with PaPUC to increase annual revenues by
$25.9 million to cover increases in the cost of service to
be effective July 30, 2006. The rate request was filed to
address increased costs associated with Distribution
Corporations ongoing construction program as well as
increases in operating costs, particularly uncollectible
accounts. Following standard regulatory procedure, the PaPUC
issued an order on July 20, 2006 instituting a rate
proceeding and suspending the proposed tariff amendments until
March 2, 2007.* On October 2, 2006, the parties,
including Distribution Corporation, Staff of the PaPUC and
intervenors, executed an agreement (Settlement) proposing to
settle all issues in the rate proceeding. The Settlement
includes an increase in revenues of $14.3 million to
non-gas revenues, an agreement not to file a rate case until
January 28, 2008 at the earliest and an early
implementation date. The Settlement was approved by the PaPUC at
its meeting on November 30, 2006, and new rates will become
effective January 1, 2007.
On June 8, 2006, the NTSB issued safety recommendations to
Distribution Corporation as a result of an investigation of a
natural gas explosion that occurred on Distribution
Corporations system in Dubois, Pennsylvania in August
2004. The explosion destroyed a residence, resulting in the
death of two people who lived there, and damaged a number of
other houses in the immediate vicinity.
The NTSB and Distribution Corporation differ in their assessment
of the probable cause of the explosion. The NTSB determined that
the probable cause was the fracture of a defective
butt-fusion joint which had joined two sections of
plastic pipe, and the failure of Distribution Corporation to
have an adequate program to inspect butt-fusion joints and
replace those joints not meeting its inspection criteria.
Distribution Corporation had submitted to the NTSB a proposed
determination of probable cause that was substantially
different, namely, that the probable cause was the improper
excavation and backfill operations of a third party working in
the vicinity of Distribution Corporations pipeline.
Distribution Corporation also had raised issues concerning the
testing standards employed in the NTSB investigation.
Distribution Corporation is presently reviewing alternatives by
which to seek review of the NTSBs findings and conclusions
to ensure that the NTSB considered all
53
relevant evidence, including the report of Distribution
Corporations third-party plastic pipe expert and other
relevant evidence, in reaching its determination of probable
cause.
The NTSBs safety recommendations to Distribution
Corporation involved revisions to its butt-fusion procedures for
joining plastic pipe, and revisions to its procedures for
qualifying personnel who perform plastic fusions. Although not
required by law to do so, Distribution Corporation is presently
implementing those recommendations.
The NTSB also issued safety recommendations to the PaPUC and
certain other parties. The recommendation to the PaPUC was to
require an analysis of the integrity of butt-fusion joints in
Distribution Corporations system and replacement of those
joints that are determined to have unacceptable characteristics.
Distribution Corporation is working cooperatively with the Staff
of the PaPUC to permit the PaPUC to undertake the analysis
recommended by the NTSB. Specifically, Distribution has done the
following, in agreement with the PaPUC Staff:
|
|
|
(i) |
|
Distribution Corporation uncovered a limited number of
butt-fusions at two locations designated by the PaPUC Staff; |
|
(ii) |
|
Commencing July 6, 2006, Distribution Corporation has
uncovered additional butt-fusions throughout its Pennsylvania
service area as it has uncovered facilities for other purposes;
when a butt-fusion has been uncovered, Distribution Corporation
has notified the designated PaPUC Staff representative to permit
inspection of the quality of the fusion. Distribution
Corporation has removed a number of fusions for further
evaluation. |
Distribution Corporation met with the PaPUC Staff in August 2006
to review findings to date and to discuss further procedures to
facilitate the analysis. Distribution Corporation and the PaPUC
Staff agreed to submit several of the butt-fusion specimens
removed during the inspection process to an independent testing
laboratory to assess the integrity of the fusions (and to
provide an evaluation of the sampling procedure employed).
Distribution Corporation and the PaPUC Staff have agreed upon
procedures to test the butt-fusion specimens. Distribution
Corporation anticipates that it will continue to meet with the
PaPUC Staff to review findings pertaining to this matter and
address any integrity concerns that may be identified.* At this
time, Distribution Corporation is unable to predict the outcome
of the analysis or of any negotiations or proceedings that may
result from it. Distribution Corporations response to the
actions of the PaPUC will depend on its assessment of the
validity of the PaPUCs analysis and conclusions.
Without admitting liability, Distribution Corporation has
settled all significant third-party claims against it related to
the explosion, for amounts that are immaterial in the aggregate
to the Company. Distribution Corporation has been committed to
providing safe and reliable service throughout its service
territory and firmly believes, based on information presently
known, that its system continues to be safe and reliable.
According to the Plastics Pipe Institute, plastic pipe today
accounts for over 90% of the pipe installed for the natural gas
distribution industry in the United States and Canada.
Distribution Corporation, along with many other natural gas
utilities operating in the United States, has relied extensively
upon the use of plastic pipe in its natural gas distribution
system since the 1970s.
Pipeline
and Storage
On April 7, 2006, the NYPSC, PaPUC and Pennsylvania Office
of Consumer Advocate filed a complaint and a motion for summary
disposition against Supply Corporation with the FERC under
Sections 5(a) and 13 of the Natural Gas Act (NGA). The
complainants alleged that Supply Corporations rates were
unjust and unreasonable, and that Supply Corporation was
permitted to retain more gas from shippers than is necessary for
fuel and loss. As a result, the complainants alleged, Supply
Corporation has excess annual earnings of approximately
$30 million to $35 million.
In their complaint, the complainants asked FERC (i) to find
that Supply Corporations rates are unjust and
unreasonable, and (ii) to institute proceedings to
determine the just and reasonable rates Supply Corporation will
be authorized to charge prospectively. The complainants also
asked FERC in their complaint (i) to determine whether
Supply Corporation has the authority to make sales of gas
retained from shippers, and (ii) if FERC concludes that
Supply Corporation does not have such authority, to direct
Supply Corporation to show
54
cause why it should not be required to disgorge profits
associated with such sales. In their motion for summary
disposition, the complainants asked FERC (i) to find
summarily that the rate at which Supply Corporation is permitted
to retain gas from shippers for fuel and loss is unjust and
unreasonable, (ii) to require Supply Corporation to make a
compliance filing providing detailed information regarding its
fuel and loss retention and use, and (iii) to establish
just and reasonable fuel and loss percentages for Supply
Corporation.
On June 23, 2006, FERC denied the complainants motion
for summary disposition, set the matter for hearing and referred
the complaint to a settlement Administrative Law Judge. On
August 8, 2006, a presiding Administrative Law Judge was
appointed and discovery activity began. On August 22, 2006,
the presiding Administrative Law Judge established a procedural
schedule under which he would issue an initial recommended
decision by August 8, 2007. Discovery and settlement
activity continued. On September 26, 2006, the presiding
Administrative Law Judge granted Supply Corporations
unopposed motion to suspend the procedural schedule because the
active parties had reached a settlement in principle.
On November 17, 2006, Supply Corporation filed a motion
asking FERC to approve an uncontested settlement of the
proceeding. The proposed settlement would be implemented when
and if FERC approves the settlement, but if approved would be
effective as of December 1, 2006. The principal elements of
the settlement are as follows:
|
|
|
(i) |
|
All participants have reached a negotiated resolution of all the
issues raised or which could have been raised in the proceeding,
including the claim that Supply Corporation should disgorge all
previous efficiency gas sales profits. |
|
(ii) |
|
Supply Corporations gas retention allowances on
transportation services will decrease from 2% to 1.4%, which
will reduce Supply Corporations future revenue from sales
of excess efficiency gas. For example, if
pre-settlement Supply Corporation received 100 Dth of gas for
transportation under its firm transportation rate schedule,
Supply Corporation would retain 2 Dth for fuel, loss and company
use. Post-settlement, Supply Corporation would retain a total of
1.4 Dth for the combination of fuel, company use and lost
and unaccounted for (LAUF). Supply Corporation may
continue to sell the excess retained gas, if any, that is not
consumed or lost in operations (the efficiency gas)
and keep the proceeds. However, any profit from the purchase and
sale of gas to cash out shipper imbalances will continue to be
accounted for separately and refunded to customers. Supply
Corporation will publicly file at FERC a semi-annual report
disclosing, among other things, the quantity, price and
accounting treatment of all sales of efficiency gas. The amount
of net revenue from Supply Corporations future sales of
efficiency gas will depend upon the quantity of efficiency gas
that becomes available for sale and the prices which Supply
Corporation receives from selling that gas.* |
|
(iii) |
|
Supply Corporations annual depreciation rate for
transmission plant will decrease to 2.9%, and its annual
depreciation rate for storage plant will decrease to 2.23%. This
will result in a decrease to Supply Corporations
depreciation expense by $5.623 million per year from the
pre-settlement level of annual depreciation expense.* |
|
(iv) |
|
The settlement does not change Supply Corporations rates
other than its gas retention allowances. No general rate cases
or NGA Section 5 complaint may be filed by the settling
parties to be effective before December 1, 2011. However,
Supply Corporation may file limited NGA Section 4 rate
cases as permitted by FERC for matters of general applicability
to all pipelines (such as passing through some possible future
greenhouse gas tax), and may propose seasonal rates. |
|
(v) |
|
Supply Corporations Other Post-Retirement Benefits Rate
Allowance (the amount deemed to be recovered each year in rates
to fund the Post-Retirement Plan benefits described in
Note G Retirement Plan and Other
Post-Retirement Benefits) will increase from about
$4.736 million to $11.0 million per year. Supply
Corporation will contribute its entire Other Post-Retirement
Benefits Rate Allowance to the VEBA trusts and 401(h) account
described in that Note G. About $2.5 million per year
of the Other Post-Retirement Benefits Rate Allowance will be
applied to fully amortize over the next five years Supply
Corporations entire other post-retirement benefits
regulatory asset balance at December 1, 2006, which had
been deferred for recovery under a 1995 rate case settlement. To
the extent the remainder of the Other Post- |
55
|
|
|
|
|
Retirement Benefits Rate Allowance differs from the
SFAS 106 expense that Supply Corporation actually accrues
for the Post-Retirement Plan, that difference will be deferred
for future recovery or refund as a regulatory asset or
liability. See Note G Retirement Plan and Other
Post-Retirement Benefits for extensive disclosure on the
Post-Retirement Plan. |
|
(vi) |
|
Supply Corporations tariff provisions on discounting gas
retention allowances will be amended so as to be consistent with
FERCs current policy limiting fuel discounts.
Certain pre-settlement discounts in gas retention allowances
will also be incorporated into the tariff. The discounting
changes described in this subparagraph (vi) are not
expected to change Supply Corporations earnings as
compared to pre-settlement discounting practices.* |
This matter will be resolved at FERC by either (i) FERC
approval of a settlement, or (ii) the hearing process
described above, in the course of which the presiding judge
would issue initial recommended decision(s) which would be
considered by FERC.* In that event, FERC would issue an order
that would either be consistent or inconsistent with any
recommended decision, after which any new rates would go into
effect.* Supply Corporation expects the proposed settlement to
be approved.* If this matter goes to hearing, Supply Corporation
will vigorously oppose the complaint.*
Empire currently does not have a rate case on file with the
NYPSC. Management will continue to monitor its financial
position in the New York jurisdiction to determine the necessity
of filing a rate case in the future.
Among the issues that will be resolved in connection with
Empires FERC application to build the Empire Connector are
the rates and terms of service that would become applicable to
all of Empires business, effective upon Empire accepting
the FERC certificate and placing its new facilities into service
(currently targeted for November 2008, or sooner if feasible).
At that time, Empire would become an interstate pipeline subject
to FERC regulation.*
A preliminary determination was issued in the Empire Connector
FERC proceeding on July 20, 2006, resolving the rate and
other non-environmental issues subject to the outcome of pending
rehearing requests and any future appeals, and requiring Empire
to make a compliance filing with respect to certain
non-environmental issues. Empire made its compliance filing on
September 18, 2006. This filing developed initial rates
applicable to Empires existing services (as they would
look under FERC regulation), based on a derived annual cost of
service of $30.4 million. Included in this derived cost of
service is a change of Empires transmission plant annual
depreciation rate from 4% to 2.5%, resulting in a reduction of
$3.3 million in the filed-for cost of service. This
depreciation change would have no impact on earnings because the
resulting decrease in revenue would be matched by a decrease in
depreciation expense. The initial rates developed from this cost
of service are under a straight fixed variable rate design,
where all fixed elements of cost of service would be recovered
under a fixed monthly reservation charge, and costs which vary
with throughput would be recovered in charges per Dth of
throughput. This rate design would eliminate most of the revenue
variability associated with weather.*
On September 13, 2006 the New York State Department of
Environmental Conservation issued an Air State Facility Permit
for the Oakfield compressor station, a part of the Empire
Connector project. On October 13, 2006, FERC issued a final
supplemental environmental impact statement on the Empire
Connector project and the other related downstream projects,
indicating that FERC has not identified any environmental
reasons why those projects could not be built, and that it is
the preferred alternative. The next steps at FERC would be the
issuance and acceptance of Certificates of Public Convenience
and Necessity on all the related projects, followed by
additional environmental permits from the U.S. Army Corps
of Engineers and state environmental agencies.* The Company
expects that all the necessary permits will be obtained and
accepted, firm service agreements signed, acceptable proposals
for materials and construction-related services will be received
and accepted, and the Empire Connector project will be built and
in service by November 2008. *
ENVIRONMENTAL
MATTERS
The Company is subject to various federal, state and local laws
and regulations relating to the protection of the environment.
The Company has established procedures for the ongoing
evaluation of its operations to identify potential environmental
exposures and comply with regulatory policies and procedures. It
is the
56
Companys policy to accrue estimated environmental
clean-up
costs (investigation and remediation) when such amounts can
reasonably be estimated and it is probable that the Company will
be required to incur such costs. The Company has estimated its
remaining
clean-up
costs related to former manufactured gas plant sites and third
party waste disposal sites will be $3.8 million.* This
liability has been recorded on the Consolidated Balance Sheet at
September 30, 2006. The Company expects to recover its
environmental
clean-up
costs from a combination of rate recovery and insurance
proceeds.* Other than discussed in Note H (referred to
below), the Company is currently not aware of any material
additional exposure to environmental liabilities. However,
adverse changes in environmental regulations or other factors
could impact the Company.*
For further discussion refer to Item 8 at
Note H Commitments and Contingencies under the
heading Environmental Matters.
NEW
ACCOUNTING PRONOUNCEMENTS
In March 2005, the FASB issued FIN 47, an interpretation of
SFAS 143. FIN 47 provides additional guidance on the
term conditional asset retirement obligation as used
in SFAS 143, and in particular the standard clarifies when
a Company must record a liability for a conditional asset
retirement obligation. The Company has adopted FIN 47 as of
September 30, 2006. Refer to Item 8 at
Note B Asset Retirement Obligations for further
disclosure regarding the impact of FIN 47 on the
Companys consolidated financial statements.
In May 2005, the FASB issued SFAS 154. SFAS 154
replaces APB 20 and SFAS 3 and changes the
requirements for the accounting for and reporting of a change in
accounting principle. The Companys financial condition and
results of operations will only be impacted by SFAS 154 if
there are any accounting changes or corrections of errors in the
future. For further discussion of SFAS 154 and its impact
on the Company, refer to Item 8 at Note A
Summary of Significant Accounting Policies.
In June 2006, the FASB issued FIN 48, an interpretation of
SFAS 109. FIN 48 clarifies the accounting for
uncertainty in income taxes and reduces the diversity in current
practice associated with the financial statement recognition and
measurement of a tax position taken or expected to be taken in a
tax return by defining a more-likely-than-not
threshold regarding the sustainability of the position. The
Company is currently evaluating the impact of FIN 48 on its
consolidated financial statements. For further discussion of
FIN 48 and its impact on the Company, refer to Item 8
at Note A Summary of Significant Accounting
Policies.
In September 2006, the FASB issued SFAS 157. SFAS 157
provides guidance for using fair value to measure assets and
liabilities. The pronouncement serves to clarify the extent to
which companies measure assets and liabilities at fair value,
the information used to measure fair value, and the effect that
fair-value measurements have on earnings. The Company is
currently evaluating the impact that the adoption of
SFAS 157 will have on its consolidated financial
statements. For further discussion of SFAS 157 and its
impact on the Company, refer to Item 8 at
Note A Summary of Significant Accounting
Policies.
In September 2006, the FASB issued SFAS 158, an amendment
of SFAS 87, SFAS 88, SFAS 106, and
SFAS 132R. SFAS 158 requires that companies recognize
a net liability or asset to report the underfunded or overfunded
status of their defined benefit pension and other
post-retirement benefit plans on their balance sheets, as well
as recognize changes in the funded status of a defined benefit
post-retirement plan in the year in which the changes occur
through comprehensive income. The pronouncement also specifies
that a plans assets and obligations that determine its
funded status be measured as of the end of Companys fiscal
year, with limited exceptions. The Company is required to
recognize the funded status of its benefit plans and the
disclosure requirements of SFAS 158 by the fourth quarter
of fiscal 2007. The requirement to measure the plan assets and
benefit obligations as of the Companys fiscal year-end
date will be adopted by the Company by the end of fiscal 2009.
If the Company recognized the funded status of its pension and
post-retirement benefit plans at September 30, 2006, the
Companys Consolidated Balance Sheet would reflect a
liability of $220.8 million instead of the prepaid pension
and post-retirement costs of $64.1 million and pension and
post-retirement liabilities of $32.9 million that are
currently presented on the balance sheet at September 30,
2006. The Company expects that it will record a regulatory asset
for the majority of this liability with the remainder reflected
in accumulated other comprehensive income (loss). The difference
between what the Company
57
currently records on its Consolidated Balance Sheet for its
pension and post-retirement benefit obligations and what it will
be required to record under SFAS 158 is due to certain
unrecognized actuarial gains and losses and unrecognized prior
service costs for both the pension and other post-retirement
benefit plans as well as an unrecognized transition obligation
for the other post-retirement benefit plan. These amounts are
not required to be recorded on the Companys Consolidated
Balance Sheet under the current accounting standards, but were
instead amortized over a period of time.
EFFECTS
OF INFLATION
Although the rate of inflation has been relatively low over the
past few years, the Companys operations remain sensitive
to increases in the rate of inflation because of its capital
spending and the regulated nature of a significant portion of
its business.
SAFE
HARBOR FOR FORWARD-LOOKING STATEMENTS
The Company is including the following cautionary statement in
this
Form 10-K
to make applicable and take advantage of the safe harbor
provisions of the Private Securities Litigation Reform Act of
1995 for any forward-looking statements made by, or on behalf
of, the Company. Forward-looking statements include statements
concerning plans, objectives, goals, projections, strategies,
future events or performance, and underlying assumptions and
other statements which are other than statements of historical
facts. From time to time, the Company may publish or otherwise
make available forward-looking statements of this nature. All
such subsequent forward-looking statements, whether written or
oral and whether made by or on behalf of the Company, are also
expressly qualified by these cautionary statements. Certain
statements contained in this report, including, without
limitation, those which are designated with an asterisk
(*) and those which are identified by the use of the
words anticipates, estimates,
expects, intends, plans,
predicts, projects, and similar
expressions, are forward-looking statements as
defined in the Private Securities Litigation Reform Act of 1995
and accordingly involve risks and uncertainties which could
cause actual results or outcomes to differ materially from those
expressed in the forward-looking statements. The forward-looking
statements contained herein are based on various assumptions,
many of which are based, in turn, upon further assumptions. The
Companys expectations, beliefs and projections are
expressed in good faith and are believed by the Company to have
a reasonable basis, including, without limitation,
managements examination of historical operating trends,
data contained in the Companys records and other data
available from third parties, but there can be no assurance that
managements expectations, beliefs or projections will
result or be achieved or accomplished. In addition to other
factors and matters discussed elsewhere herein, the following
are important factors that, in the view of the Company, could
cause actual results to differ materially from those discussed
in the forward-looking statements:
|
|
|
|
1.
|
Changes in laws and regulations to which the Company is subject,
including changes in tax, environmental, safety and employment
laws and regulations;
|
|
|
2.
|
Changes in economic conditions, including economic disruptions
caused by terrorist activities, acts of war or major accidents;
|
|
|
3.
|
Changes in demographic patterns and weather conditions,
including the occurrence of severe weather such as hurricanes;
|
|
|
4.
|
Changes in the availability
and/or price
of natural gas or oil and the effect of such changes on the
accounting treatment or valuation of derivative financial
instruments or the Companys natural gas and oil reserves;
|
|
|
5.
|
Impairments under the SECs full cost ceiling test for
natural gas and oil reserves;
|
|
|
6.
|
Changes in the availability
and/or price
of derivative financial instruments;
|
|
|
7.
|
Changes in the price differentials between various types of oil;
|
|
|
8.
|
Failure of the price differential between heavy sour crude oil
and light sweet crude oil to return to its historical norm;
|
58
|
|
|
|
9.
|
Inability to obtain new customers or retain existing ones;
|
|
|
10.
|
Significant changes in competitive factors affecting the Company;
|
|
11.
|
Governmental/regulatory actions, initiatives and proceedings,
including those involving acquisitions, financings, rate cases
(which address, among other things, allowed rates of return,
rate design and retained gas), affiliate relationships, industry
structure, franchise renewal, and environmental/safety
requirements;
|
|
12.
|
Unanticipated impacts of restructuring initiatives in the
natural gas and electric industries;
|
|
13.
|
Significant changes from expectations in actual capital
expenditures and operating expenses and unanticipated project
delays or changes in project costs or plans, including changes
in the plans of the sponsors of the proposed Millennium Pipeline
with respect to that project;
|
|
14.
|
The nature and projected profitability of pending and potential
projects and other investments;
|
|
15.
|
Occurrences affecting the Companys ability to obtain funds
from operations or from issuances of debt or equity securities
to finance needed capital expenditures and other investments,
including any downgrades in the Companys credit ratings;
|
|
16.
|
Uncertainty of oil and gas reserve estimates;
|
|
17.
|
Ability to successfully identify and finance acquisitions or
other investments and ability to operate and integrate existing
and any subsequently acquired business or properties;
|
|
18.
|
Ability to successfully identify, drill for and produce
economically viable natural gas and oil reserves;
|
|
19.
|
Significant changes from expectations in the Companys
actual production levels for natural gas or oil;
|
|
20.
|
Regarding foreign operations, changes in trade and monetary
policies, inflation and exchange rates, taxes, operating
conditions, laws and regulations related to foreign operations,
and political and governmental changes;
|
|
21.
|
Significant changes in tax rates or policies or in rates of
inflation or interest;
|
|
22.
|
Significant changes in the Companys relationship with its
employees or contractors and
the
potential adverse effects if labor disputes, grievances or
shortages were to occur;
|
|
23.
|
Changes in accounting principles or the application of such
principles to the Company;
|
|
24.
|
The cost and effects of legal and administrative claims against
the Company;
|
|
25.
|
Changes in actuarial assumptions and the return on assets with
respect to the Companys retirement plan and
post-retirement benefit plans;
|
|
26.
|
Increasing health care costs and the resulting effect on health
insurance premiums and on the obligation to provide
post-retirement benefits; or
|
|
27.
|
Increasing costs of insurance, changes in coverage and the
ability to obtain insurance.
|
The Company disclaims any obligation to update any
forward-looking statements to reflect events or circumstances
after the date hereof.
|
|
Item 7A
|
Quantitative
and Qualitative Disclosures About Market Risk
|
Refer to the Market Risk Sensitive Instruments
section in Item 7, MD&A.
59
|
|
Item 8
|
Financial
Statements and Supplementary Data
|
Index
to Financial Statements
|
|
|
|
|
|
|
Page
|
Financial Statements:
|
|
|
|
|
|
|
|
61
|
|
|
|
|
63
|
|
|
|
|
64
|
|
|
|
|
65
|
|
|
|
|
66
|
|
|
|
|
67
|
|
Financial Statement Schedules:
|
|
|
|
|
For the three years ended
September 30, 2006
|
|
|
|
|
|
|
|
113
|
|
All other schedules are omitted because they are not applicable
or the required information is shown in the Consolidated
Financial Statements or Notes thereto.
Supplementary
Data
Supplementary data that is included in Note M
Quarterly Financial Data (unaudited) and Note O
Supplementary Information for Oil and Gas Producing Activities,
appears under this Item, and reference is made thereto.
60
REPORT OF
INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders of National Fuel Gas
Company:
We have completed integrated audits of National Fuel Gas
Companys fiscal 2006 and 2005 consolidated financial
statements and of its internal control over financial reporting
as of September 30, 2006, and an audit of its fiscal 2004
consolidated financial statements in accordance with the
standards of the Public Company Accounting Oversight Board
(United States). Our opinions, based on our audits, are
presented below.
Consolidated
financial statements and financial statement
schedule
In our opinion, the consolidated financial statements listed in
the accompanying index present fairly, in all material respects,
the financial position of National Fuel Gas Company and its
subsidiaries 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. In addition, in our opinion, the
financial statement schedule listed in the accompanying index
presents fairly, in all material respects, the information set
forth therein when read in conjunction with the related
consolidated financial statements. These financial statements
and financial statement schedule are the responsibility of the
Companys management. Our responsibility is to express an
opinion on these financial statements and financial statement
schedule based on our audits. We conducted our audits of these
statements in accordance with 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 the financial statements are
free of material misstatement. An audit of financial statements
includes examining, on a test basis, evidence supporting the
amounts and disclosures in the financial statements, assessing
the accounting principles used and significant estimates made by
management, and evaluating the overall financial statement
presentation. We believe that our audits provide a reasonable
basis for our opinion.
Internal
control over financial reporting
Also, in our opinion, managements assessment, included in
Managements Report on Internal Control Over
Financial Reporting appearing under Item 9A, that 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 (COSO), is fairly
stated, in all material respects, based on those criteria.
Furthermore, in our opinion, the Company maintained, in all
material respects, effective internal control over financial
reporting as of September 30, 2006, based on criteria
established in Internal Control Integrated
Framework issued by the COSO. The Companys 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 opinions on managements assessment and on
the effectiveness of the Companys internal control over
financial reporting based on our audit. We conducted our audit
of internal control over financial reporting 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. An audit of internal
control over financial reporting includes obtaining an
understanding of internal control over financial reporting,
evaluating managements assessment, testing and evaluating
the design and operating effectiveness of internal control, and
performing such other procedures as we consider necessary in the
circumstances. We believe that our audit provides a reasonable
basis for our opinions.
A companys internal control over financial reporting is a
process designed to provide reasonable assurance regarding the
reliability of financial reporting and the preparation of
financial statements for external purposes in accordance with
generally accepted accounting principles. A companys
internal control over financial reporting includes those
policies and procedures that (i) pertain to the maintenance
of records that, in reasonable detail, accurately and fairly
reflect the transactions and dispositions of the assets of the
company; (ii) provide reasonable assurance that
transactions are recorded as necessary to permit preparation of
financial statements in accordance with generally accepted
accounting principles, and that receipts and expenditures of
61
the company are being made only in accordance with
authorizations of management and directors of the company; and
(iii) provide reasonable assurance regarding prevention or
timely detection of unauthorized acquisition, use, or
disposition of the companys assets that could have a
material effect on the financial statements.
Because of its inherent limitations, internal control over
financial reporting may not prevent or detect misstatements.
Also, projections of any evaluation of effectiveness to future
periods are subject to the risk that controls may become
inadequate because of changes in conditions, or that the degree
of compliance with the policies or procedures may deteriorate.
PricewaterhouseCoopers LLP
Buffalo, New York
December 7, 2006
62
NATIONAL
FUEL GAS COMPANY
REINVESTED
IN THE BUSINESS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended September 30
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
|
(Thousands of dollars, except per common
|
|
|
|
share amounts)
|
|
|
INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Revenues
|
|
$
|
2,311,659
|
|
|
$
|
1,923,549
|
|
|
$
|
1,907,968
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchased Gas
|
|
|
1,267,562
|
|
|
|
959,827
|
|
|
|
949,452
|
|
Operation and Maintenance
|
|
|
413,726
|
|
|
|
404,517
|
|
|
|
385,519
|
|
Property, Franchise and Other Taxes
|
|
|
69,942
|
|
|
|
69,076
|
|
|
|
68,978
|
|
Depreciation, Depletion and
Amortization
|
|
|
179,615
|
|
|
|
179,767
|
|
|
|
174,289
|
|
Impairment of Oil and Gas
Producing Properties
|
|
|
104,739
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,035,584
|
|
|
|
1,613,187
|
|
|
|
1,578,238
|
|
Loss on Sale of Timber Properties
|
|
|
|
|
|
|
|
|
|
|
(1,252
|
)
|
Gain on Sale of Oil and Gas
Producing Properties
|
|
|
|
|
|
|
|
|
|
|
4,645
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Income
|
|
|
276,075
|
|
|
|
310,362
|
|
|
|
333,123
|
|
Other Income
(Expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from Unconsolidated
Subsidiaries
|
|
|
3,583
|
|
|
|
3,362
|
|
|
|
805
|
|
Impairment of Investment in
Partnership
|
|
|
|
|
|
|
(4,158
|
)
|
|
|
|
|
Interest Income
|
|
|
10,275
|
|
|
|
6,496
|
|
|
|
1,771
|
|
Other Income
|
|
|
2,825
|
|
|
|
12,744
|
|
|
|
2,908
|
|
Interest Expense on Long-Term Debt
|
|
|
(72,629
|
)
|
|
|
(73,244
|
)
|
|
|
(82,989
|
)
|
Other Interest Expense
|
|
|
(5,952
|
)
|
|
|
(9,069
|
)
|
|
|
(6,763
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from Continuing
Operations Before Income Taxes
|
|
|
214,177
|
|
|
|
246,493
|
|
|
|
248,855
|
|
Income Tax Expense
|
|
|
76,086
|
|
|
|
92,978
|
|
|
|
94,590
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from Continuing
Operations
|
|
|
138,091
|
|
|
|
153,515
|
|
|
|
154,265
|
|
Discontinued
Operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from Operations, Net of Tax
|
|
|
|
|
|
|
10,199
|
|
|
|
12,321
|
|
Gain on Disposal, Net of Tax
|
|
|
|
|
|
|
25,774
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from Discontinued
Operations
|
|
|
|
|
|
|
35,973
|
|
|
|
12,321
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income Available for Common
Stock
|
|
|
138,091
|
|
|
|
189,488
|
|
|
|
166,586
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EARNINGS REINVESTED IN THE
BUSINESS
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at Beginning of Year
|
|
|
813,020
|
|
|
|
718,926
|
|
|
|
642,690
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
951,111
|
|
|
|
908,414
|
|
|
|
809,276
|
|
Share Repurchases
|
|
|
66,269
|
|
|
|
|
|
|
|
|
|
Dividends on Common Stock
|
|
|
98,829
|
|
|
|
95,394
|
|
|
|
90,350
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at End of
Year
|
|
$
|
786,013
|
|
|
$
|
813,020
|
|
|
$
|
718,926
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings Per Common
Share:
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic:
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from Continuing Operations
|
|
$
|
1.64
|
|
|
$
|
1.84
|
|
|
$
|
1.88
|
|
Income from Discontinued Operations
|
|
|
|
|
|
|
0.43
|
|
|
|
0.15
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income Available for Common
Stock
|
|
$
|
1.64
|
|
|
$
|
2.27
|
|
|
$
|
2.03
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted:
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from Continuing Operations
|
|
$
|
1.61
|
|
|
$
|
1.81
|
|
|
$
|
1.86
|
|
Income from Discontinued Operations
|
|
|
|
|
|
|
0.42
|
|
|
|
0.15
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income Available for Common
Stock
|
|
$
|
1.61
|
|
|
$
|
2.23
|
|
|
$
|
2.01
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted Average Common
Shares Outstanding:
|
|
|
|
|
|
|
|
|
|
|
|
|
Used in Basic Calculation
|
|
|
84,030,118
|
|
|
|
83,541,627
|
|
|
|
82,045,535
|
|
Used in Diluted Calculation
|
|
|
86,028,466
|
|
|
|
85,029,131
|
|
|
|
82,900,438
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See Notes to Consolidated Financial Statements
63
NATIONAL
FUEL GAS COMPANY
|
|
|
|
|
|
|
|
|
|
|
At September 30
|
|
|
|
2006
|
|
|
2005
|
|
|
|
(Thousands of dollars)
|
|
|
ASSETS
|
Property, Plant and
Equipment
|
|
$
|
4,703,040
|
|
|
$
|
4,423,255
|
|
Less Accumulated
Depreciation, Depletion and Amortization
|
|
|
1,825,314
|
|
|
|
1,583,955
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,877,726
|
|
|
|
2,839,300
|
|
|
|
|
|
|
|
|
|
|
Current Assets
|
|
|
|
|
|
|
|
|
Cash and Temporary Cash Investments
|
|
|
69,611
|
|
|
|
57,607
|
|
Hedging Collateral Deposits
|
|
|
19,676
|
|
|
|
77,784
|
|
Receivables Net of
Allowance for Uncollectible Accounts of $31,427 and $26,940,
Respectively
|
|
|
144,254
|
|
|
|
141,408
|
|
Unbilled Utility Revenue
|
|
|
25,538
|
|
|
|
20,465
|
|
Gas Stored Underground
|
|
|
59,461
|
|
|
|
64,529
|
|
Materials and Supplies
at average cost
|
|
|
36,693
|
|
|
|
33,267
|
|
Unrecovered Purchased Gas Costs
|
|
|
12,970
|
|
|
|
14,817
|
|
Prepaid Pension and Post-Retirement
Benefit Costs
|
|
|
64,125
|
|
|
|
14,404
|
|
Other Current Assets
|
|
|
63,723
|
|
|
|
67,351
|
|
Deferred Income Taxes
|
|
|
23,402
|
|
|
|
83,774
|
|
|
|
|
|
|
|
|
|
|
|
|
|
519,453
|
|
|
|
575,406
|
|
|
|
|
|
|
|
|
|
|
Other Assets
|
|
|
|
|
|
|
|
|
Recoverable Future Taxes
|
|
|
79,511
|
|
|
|
85,000
|
|
Unamortized Debt Expense
|
|
|
15,492
|
|
|
|
17,567
|
|
Other Regulatory Assets
|
|
|
76,917
|
|
|
|
47,028
|
|
Deferred Charges
|
|
|
3,558
|
|
|
|
4,474
|
|
Other Investments
|
|
|
88,414
|
|
|
|
80,394
|
|
Investments in Unconsolidated
Subsidiaries
|
|
|
11,590
|
|
|
|
12,658
|
|
Goodwill
|
|
|
5,476
|
|
|
|
5,476
|
|
Intangible Assets
|
|
|
31,498
|
|
|
|
42,302
|
|
Fair Value of Derivative Financial
Instruments
|
|
|
11,305
|
|
|
|
|
|
Deferred Income Taxes
|
|
|
9,003
|
|
|
|
|
|
Other
|
|
|
4,388
|
|
|
|
15,677
|
|
|
|
|
|
|
|
|
|
|
|
|
|
337,152
|
|
|
|
310,576
|
|
|
|
|
|
|
|
|
|
|
Total Assets
|
|
$
|
3,734,331
|
|
|
$
|
3,725,282
|
|
|
|
|
|
|
|
|
|
|
|
CAPITALIZATION AND
LIABILITIES
|
Capitalization:
|
|
|
|
|
|
|
|
|
Comprehensive Shareholders
Equity
|
|
|
|
|
|
|
|
|
Common Stock, $1 Par Value
|
|
|
|
|
|
|
|
|
Authorized
200,000,000 Shares; Issued and Outstanding
83,402,670 Shares and 84,356,748 Shares, Respectively
|
|
$
|
83,403
|
|
|
$
|
84,357
|
|
Paid In Capital
|
|
|
543,730
|
|
|
|
529,834
|
|
Earnings Reinvested in the Business
|
|
|
786,013
|
|
|
|
813,020
|
|
|
|
|
|
|
|
|
|
|
Total Common Shareholders
Equity Before Items Of Other Comprehensive Income (Loss)
|
|
|
1,413,146
|
|
|
|
1,427,211
|
|
Accumulated Other Comprehensive
Income (Loss)
|
|
|
30,416
|
|
|
|
(197,628
|
)
|
|
|
|
|
|
|
|
|
|
Total Comprehensive
Shareholders Equity
|
|
|
1,443,562
|
|
|
|
1,229,583
|
|
Long-Term Debt, Net of Current
Portion
|
|
|
1,095,675
|
|
|
|
1,119,012
|
|
|
|
|
|
|
|
|
|
|
Total Capitalization
|
|
|
2,539,237
|
|
|
|
2,348,595
|
|
|
|
|
|
|
|
|
|
|
Current and Accrued
Liabilities
|
|
|
|
|
|
|
|
|
Notes Payable to Banks and
Commercial Paper
|
|
|
|
|
|
|
|
|
Current Portion of Long-Term Debt
|
|
|
22,925
|
|
|
|
9,393
|
|
Accounts Payable
|
|
|
133,034
|
|
|
|
155,485
|
|
Amounts Payable to Customers
|
|
|
23,935
|
|
|
|
1,158
|
|
Dividends Payable
|
|
|
25,008
|
|
|
|
24,445
|
|
Interest Payable on Long-Term Debt
|
|
|
18,420
|
|
|
|
18,438
|
|
Other Accruals and Current
Liabilities
|
|
|
27,040
|
|
|
|
44,596
|
|
Fair Value of Derivative Financial
Instruments
|
|
|
39,983
|
|
|
|
209,072
|
|
|
|
|
|
|
|
|
|
|
|
|
|
290,345
|
|
|
|
462,587
|
|
|
|
|
|
|
|
|
|
|
Deferred Credits
|
|
|
|
|
|
|
|
|
Deferred Income Taxes
|
|
|
544,502
|
|
|
|
489,720
|
|
Taxes Refundable to Customers
|
|
|
10,426
|
|
|
|
11,009
|
|
Unamortized Investment Tax Credit
|
|
|
6,094
|
|
|
|
6,796
|
|
Cost of Removal Regulatory Liability
|
|
|
85,076
|
|
|
|
90,396
|
|
Other Regulatory Liabilities
|
|
|
75,456
|
|
|
|
66,339
|
|
Pension and Other Post-Retirement
Liabilities
|
|
|
32,918
|
|
|
|
143,687
|
|
Asset Retirement Obligation
|
|
|
77,392
|
|
|
|
41,411
|
|
Other Deferred Credits
|
|
|
72,885
|
|
|
|
64,742
|
|
|
|
|
|
|
|
|
|
|
|
|
|
904,749
|
|
|
|
914,100
|
|
|
|
|
|
|
|
|
|
|
Commitments and
Contingencies
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Capitalization and
Liabilities
|
|
$
|
3,734,331
|
|
|
$
|
3,725,282
|
|
|
|
|
|
|
|
|
|
|
See Notes to Consolidated Financial Statements
64
NATIONAL
FUEL GAS COMPANY
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended September 30
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
|
(Thousands of dollars)
|
|
|
Operating Activities
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income Available for Common
Stock
|
|
$
|
138,091
|
|
|
$
|
189,488
|
|
|
$
|
166,586
|
|
Adjustments to Reconcile Net Income
to Net Cash Provided by Operating Activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Gain on Sale of Discontinued
Operations
|
|
|
|
|
|
|
(27,386
|
)
|
|
|
|
|
Loss on Sale of Timber Properties
|
|
|
|
|
|
|
|
|
|
|
1,252
|
|
Gain on Sale of Oil and Gas
Producing Properties
|
|
|
|
|
|
|
|
|
|
|
(4,645
|
)
|
Impairment of Oil and Gas Producing
Properties
|
|
|
104,739
|
|
|
|
|
|
|
|
|
|
Depreciation, Depletion and
Amortization
|
|
|
179,615
|
|
|
|
193,144
|
|
|
|
189,538
|
|
Deferred Income Taxes
|
|
|
(5,230
|
)
|
|
|
40,388
|
|
|
|
40,329
|
|
(Income) Loss from Unconsolidated
Subsidiaries, Net of Cash Distributions
|
|
|
1,067
|
|
|
|
(1,372
|
)
|
|
|
(19
|
)
|
Impairment of Investment in
Partnership
|
|
|
|
|
|
|
4,158
|
|
|
|
|
|
Minority Interest in Foreign
Subsidiaries
|
|
|
|
|
|
|
2,645
|
|
|
|
1,933
|
|
Excess Tax Benefits Associated with
Stock-Based Compensation Awards
|
|
|
(6,515
|
)
|
|
|
|
|
|
|
|
|
Other
|
|
|
4,829
|
|
|
|
7,390
|
|
|
|
9,839
|
|
Change in:
|
|
|
|
|
|
|
|
|
|
|
|
|
Hedging Collateral Deposits
|
|
|
58,108
|
|
|
|
(69,172
|
)
|
|
|
(7,151
|
)
|
Receivables and Unbilled Utility
Revenue
|
|
|
(7,397
|
)
|
|
|
(21,857
|
)
|
|
|
8,887
|
|
Gas Stored Underground and
Materials and Supplies
|
|
|
1,679
|
|
|
|
1,934
|
|
|
|
13,662
|
|
Unrecovered Purchased Gas Costs
|
|
|
1,847
|
|
|
|
(7,285
|
)
|
|
|
21,160
|
|
Prepayments and Other Current Assets
|
|
|
(39,572
|
)
|
|
|
(42,409
|
)
|
|
|
35,647
|
|
Accounts Payable
|
|
|
(23,144
|
)
|
|
|
48,089
|
|
|
|
(5,134
|
)
|
Amounts Payable to Customers
|
|
|
22,777
|
|
|
|
(1,996
|
)
|
|
|
2,462
|
|
Other Accruals and Current
Liabilities
|
|
|
(17,754
|
)
|
|
|
18,715
|
|
|
|
2,082
|
|
Other Assets
|
|
|
(22,700
|
)
|
|
|
(13,461
|
)
|
|
|
(4,829
|
)
|
Other Liabilities
|
|
|
80,960
|
|
|
|
(3,667
|
)
|
|
|
(34,450
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Cash Provided by Operating
Activities
|
|
|
471,400
|
|
|
|
317,346
|
|
|
|
437,149
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investing Activities
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital Expenditures
|
|
|
(294,159
|
)
|
|
|
(219,530
|
)
|
|
|
(172,341
|
)
|
Net Proceeds from Sale of Foreign
Subsidiary
|
|
|
|
|
|
|
111,619
|
|
|
|
|
|
Net Proceeds from Sale of Oil and
Gas Producing Properties
|
|
|
13
|
|
|
|
1,349
|
|
|
|
7,162
|
|
Other
|
|
|
(3,230
|
)
|
|
|
3,238
|
|
|
|
1,974
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Cash Used in Investing
Activities
|
|
|
(297,376
|
)
|
|
|
(103,324
|
)
|
|
|
(163,205
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Financing Activities
|
|
|
|
|
|
|
|
|
|
|
|
|
Change in Notes Payable to
Banks and Commercial Paper
|
|
|
|
|
|
|
(115,359
|
)
|
|
|
38,600
|
|
Excess Tax Benefits Associated with
Stock-Based Compensation Awards
|
|
|
6,515
|
|
|
|
|
|
|
|
|
|
Shares Repurchased under
Repurchase Plan
|
|
|
(85,168
|
)
|
|
|
|
|
|
|
|
|
Reduction of Long-Term Debt
|
|
|
(9,805
|
)
|
|
|
(13,317
|
)
|
|
|
(243,085
|
)
|
Proceeds from Issuance of Common
Stock
|
|
|
23,339
|
|
|
|
20,279
|
|
|
|
23,763
|
|
Dividends Paid on Common Stock
|
|
|
(98,266
|
)
|
|
|
(94,159
|
)
|
|
|
(89,092
|
)
|
Dividends Paid to Minority Interest
|
|
|
|
|
|
|
(12,676
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Cash Used in Financing
Activities
|
|
|
(163,385
|
)
|
|
|
(215,232
|
)
|
|
|
(269,814
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Effect of Exchange Rates on
Cash
|
|
|
1,365
|
|
|
|
1,276
|
|
|
|
3,451
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Increase in Cash and
Temporary Cash Investments
|
|
|
12,004
|
|
|
|
66
|
|
|
|
7,581
|
|
Cash and Temporary Cash
Investments At Beginning of Year
|
|
|
57,607
|
|
|
|
57,541
|
|
|
|
49,960
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and Temporary Cash
Investments At End of Year
|
|
$
|
69,611
|
|
|
$
|
57,607
|
|
|
$
|
57,541
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Supplemental Disclosure of Cash
Flow Information Cash Paid For:
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
|
|
$
|
78,003
|
|
|
$
|
84,455
|
|
|
$
|
90,705
|
|
Income Taxes
|
|
$
|
54,359
|
|
|
$
|
83,542
|
|
|
$
|
30,214
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See Notes to Consolidated Financial Statements
65
NATIONAL
FUEL GAS COMPANY
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended September 30
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
|
(Thousands of dollars)
|
|
|
Net Income Available for Common
Stock
|
|
$
|
138,091
|
|
|
$
|
189,488
|
|
|
$
|
166,586
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Comprehensive Income (Loss),
Before Tax:
|
|
|
|
|
|
|
|
|
|
|
|
|
Minimum Pension Liability
Adjustment
|
|
|
165,914
|
|
|
|
(83,379
|
)
|
|
|
56,612
|
|
Foreign Currency Translation
Adjustment
|
|
|
7,408
|
|
|
|
14,286
|
|
|
|
21,466
|
|
Reclassification Adjustment for
Realized Foreign Currency Translation Gain in Net Income
|
|
|
(716
|
)
|
|
|
(37,793
|
)
|
|
|
|
|
Unrealized Gain on Securities
Available for Sale Arising During the Period
|
|
|
2,573
|
|
|
|
2,891
|
|
|
|
3,629
|
|
Reclassification Adjustment for
Realized Gains On Securities Available for Sale in Net Income
|
|
|
|
|
|
|
(651
|
)
|
|
|
|
|
Unrealized Gain (Loss) on
Derivative Financial Instruments Arising During the Period
|
|
|
90,196
|
|
|
|
(206,847
|
)
|
|
|
(129,934
|
)
|
Reclassification Adjustment for
Realized Loss on Derivative Financial Instruments in Net Income
|
|
|
91,743
|
|
|
|
97,689
|
|
|
|
49,142
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Comprehensive Income (Loss),
Before Tax:
|
|
|
357,118
|
|
|
|
(213,804
|
)
|
|
|
915
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income Tax Expense (Benefit)
Related to Minimum Pension Liability Adjustment
|
|
|
58,070
|
|
|
|
(29,183
|
)
|
|
|
19,814
|
|
Income Tax Expense Related to
Foreign Currency Translation Adjustment
|
|
|
|
|
|
|
112
|
|
|
|
|
|
Reclassification Adjustment for
Income Tax Expense on Foreign Currency Translation Adjustment in
Net Income
|
|
|
|
|
|
|
(112
|
)
|
|
|
|
|
Income Tax Expense Related to
Unrealized Gain on Securities Available for Sale Arising During
the Period
|
|
|
894
|
|
|
|
1,012
|
|
|
|
1,270
|
|
Reclassification Adjustment for
Income Tax Expense on Realized Gains from Securities Available
for Sale in Net Income
|
|
|
|
|
|
|
(228
|
)
|
|
|
|
|
Income Tax Expense (Benefit)
Related to Unrealized Gain (Loss) on Derivative Financial
Instruments Arising During the Period
|
|
|
34,772
|
|
|
|
(79,059
|
)
|
|
|
(49,113
|
)
|
Reclassification Adjustment for
Income Tax Benefit on Realized Loss on Derivative Financial
Instruments In Net Income
|
|
|
35,338
|
|
|
|
36,507
|
|
|
|
18,182
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income Taxes Net
|
|
|
129,074
|
|
|
|
(70,951
|
)
|
|
|
(9,847
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Comprehensive Income (Loss)
|
|
|
228,044
|
|
|
|
(142,853
|
)
|
|
|
10,762
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive Income
|
|
$
|
366,135
|
|
|
$
|
46,635
|
|
|
$
|
177,348
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See Notes to Consolidated Financial Statements
66
NATIONAL
FUEL GAS COMPANY
Note A
Summary of Significant Accounting Policies
Principles
of Consolidation
The Company consolidates its majority owned entities. The equity
method is used to account for minority owned entities. All
significant intercompany balances and transactions are
eliminated.
The preparation of the consolidated financial statements in
conformity with GAAP requires management to make estimates and
assumptions that affect the reported amounts of assets and
liabilities and disclosure of contingent assets and liabilities
at the date of the financial statements and the reported amounts
of revenues and expenses during the reporting period. Actual
results could differ from those estimates.
Reclassification
Certain prior year amounts have been reclassified to conform
with current year presentation.
Regulation
The Company is subject to regulation by certain state and
federal authorities. The Company has accounting policies which
conform to GAAP, as applied to regulated enterprises, and are in
accordance with the accounting requirements and ratemaking
practices of the regulatory authorities. Reference is made to
Note C Regulatory Matters for further
discussion.
Revenues
The Companys Utility segment records revenue as bills are
rendered, except that service supplied but not billed is
reported as unbilled utility revenue and is included in
operating revenues for the year in which service is furnished.
The Companys Pipeline and Storage and Energy Marketing
segments record revenue as bills are rendered for service
supplied on a calendar month basis. The Companys Timber
segment records revenue on lumber and log sales as products are
shipped.
The Companys Exploration and Production segment records
revenue based on entitlement, which means that revenue is
recorded based on the actual amount of gas or oil that is
delivered to a pipeline and the Companys ownership
interest in the producing well. If a production imbalance occurs
between what was supposed to be delivered to a pipeline and what
was actually produced and delivered, the Company accrues the
difference as an imbalance.
Allowance
for Uncollectible Accounts
The allowance for uncollectible accounts is the Companys
best estimate of the amount of probable credit losses in the
existing accounts receivable. The allowance is determined based
on historical experience, the age and other specific information
about customer accounts. Account balances are charged off
against the allowance twelve months after the account is final
billed or when it is anticipated that the receivable will not be
recovered.
Regulatory
Mechanisms
The Companys rate schedules in the Utility segment contain
clauses that permit adjustment of revenues to reflect price
changes from the cost of purchased gas included in base rates.
Differences between amounts currently recoverable and actual
adjustment clause revenues, as well as other price changes and
pipeline and storage company refunds not yet includable in
adjustment clause rates, are deferred and accounted for as
either unrecovered purchased gas costs or amounts payable to
customers. Such amounts are generally recovered from (or passed
back to) customers during the following fiscal year.
67
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Estimated refund liabilities to ratepayers represent
managements current estimate of such refunds. Reference is
made to Note C Regulatory Matters for further
discussion.
The impact of weather on revenues in the Utility segments
New York rate jurisdiction is tempered by a WNC, which covers
the eight-month period from October through May. The WNC is
designed to adjust the rates of retail customers to reflect the
impact of deviations from normal weather. Weather that is more
than 2.2% warmer than normal results in a surcharge being added
to customers current bills, while weather that is more
than 2.2% colder than normal results in a refund being credited
to customers current bills. Since the Utility
segments Pennsylvania rate jurisdiction does not have a
WNC, weather variations have a direct impact on the Pennsylvania
rate jurisdictions revenues.
In the Pipeline and Storage segment, the allowed rates that
Supply Corporation bills its customers are based on a straight
fixed-variable rate design, which allows recovery of all fixed
costs in fixed monthly reservation charges. The allowed rates
that Empire bills its customers are based on a modified-fixed
variable rate design, which allows recovery of most fixed costs
in fixed monthly reservation charges. To distinguish between the
two rate designs, the modified fixed-variable rate design
recovers return on equity and income taxes through variable
charges whereas straight fixed-variable recovers all fixed
costs, including return on equity and income taxes, through its
monthly reservation charge. Because of the difference in rate
design, changes in throughput due to weather variations do not
have a significant impact on Supply Corporations revenues
but may have a significant impact on Empires revenues.
Property,
Plant and Equipment
The principal assets of the Utility and Pipeline and Storage
segments, consisting primarily of gas plant in service, are
recorded at the historical cost when originally devoted to
service in the regulated businesses, as required by regulatory
authorities.
Oil and gas property acquisition, exploration and development
costs are capitalized under the full cost method of accounting.
All costs directly associated with property acquisition,
exploration and development activities are capitalized, up to
certain specified limits. If capitalized costs exceed these
limits at the end of any quarter, a permanent impairment is
required to be charged to earnings in that quarter. The
Companys capitalized costs exceeded the full cost ceiling
for the Companys Canadian properties at June 30, 2006
and September 30, 2006. As such, the Company recognized
pre-tax impairments of $62.4 million at June 30, 2006
and $42.3 million at September 30, 2006.
Maintenance and repairs of property and replacements of minor
items of property are charged directly to maintenance expense.
The original cost of the regulated subsidiaries property,
plant and equipment retired, and the cost of removal less
salvage, are charged to accumulated depreciation.
68
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Depreciation,
Depletion and Amortization
For oil and gas properties, depreciation, depletion and
amortization is computed based on quantities produced in
relation to proved reserves using the units of production
method. The cost of unevaluated oil and gas properties is
excluded from this computation. For timber properties,
depletion, determined on a property by property basis, is
charged to operations based on the actual amount of timber cut
in relation to the total amount of recoverable timber. For all
other property, plant and equipment, depreciation, depletion and
amortization is computed using the straight-line method in
amounts sufficient to recover costs over the estimated service
lives of property in service. The following is a summary of
depreciable plant by segment:
|
|
|
|
|
|
|
|
|
|
|
As of September 30
|
|
|
|
2006
|
|
|
2005
|
|
|
|
(Thousands)
|
|
|
Utility
|
|
$
|
1,493,991
|
|
|
$
|
1,462,527
|
|
Pipeline and Storage
|
|
|
962,831
|
|
|
|
960,066
|
|
Exploration and Production
|
|
|
1,899,777
|
|
|
|
1,665,774
|
|
Energy Marketing
|
|
|
1,123
|
|
|
|
1,108
|
|
Timber
|
|
|
116,281
|
|
|
|
114,352
|
|
All Other and Corporate
|
|
|
33,338
|
|
|
|
29,275
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
4,507,341
|
|
|
$
|
4,233,102
|
|
|
|
|
|
|
|
|
|
|
Average depreciation, depletion and amortization rates are as
follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended September 30
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
Utility
|
|
|
2.8
|
%
|
|
|
2.8
|
%
|
|
|
2.8
|
%
|
Pipeline and Storage
|
|
|
4.0
|
%
|
|
|
4.1
|
%
|
|
|
4.1
|
%
|
Exploration and Production, per
Mcfe(1)
|
|
$
|
2.00
|
|
|
$
|
1.74
|
|
|
$
|
1.49
|
|
Energy Marketing
|
|
|
4.8
|
%
|
|
|
7.6
|
%
|
|
|
8.7
|
%
|
Timber
|
|
|
5.6
|
%
|
|
|
6.2
|
%
|
|
|
6.5
|
%
|
All Other and Corporate
|
|
|
4.1
|
%
|
|
|
4.3
|
%
|
|
|
6.2
|
%
|
|
|
|
(1) |
|
Amounts include depletion of oil and gas producing properties as
well as depreciation of fixed assets. As disclosed in
Note O Supplementary Information for Oil and
Gas Producing Properties, depletion of oil and gas producing
properties amounted to $1.98, $1.72 and $1.47 per Mcfe of
production in 2006, 2005 and 2004, respectively. |
Goodwill
The Company has recognized goodwill of $5.5 million as of
September 30, 2006 and 2005 on its consolidated balance
sheet related to the Companys acquisition of Empire in
2003. The Company accounts for goodwill in accordance with
SFAS 142, which requires the Company to test goodwill for
impairment annually. At September 30, 2006 and 2005, the
fair value of Empire was greater than its book value. As such,
the goodwill was considered not impaired.
Financial
Instruments
Unrealized gains or losses from the Companys investments
in an equity mutual fund and the stock of an insurance company
(securities available for sale) are recorded as a component of
accumulated other comprehensive income (loss). Reference is made
to Note F Financial Instruments for further
discussion.
69
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The Company uses a variety of derivative financial instruments
to manage a portion of the market risk associated with
fluctuations in the price of natural gas and crude oil. These
instruments include price swap agreements, no cost collars,
options and futures contracts. The Company accounts for these
instruments as either cash flow hedges or fair value hedges. In
both cases, the fair value of the instrument is recognized on
the Consolidated Balance Sheets as either an asset or a
liability labeled fair value of derivative financial
instruments. Fair value represents the amount the Company would
receive or pay to terminate these instruments.
For effective cash flow hedges, the offset to the asset or
liability that is recorded is a gain or loss recorded in
accumulated other comprehensive income (loss) on the
Consolidated Balance Sheets. Any ineffectiveness associated with
the cash flow hedges is recorded in the Consolidated Statements
of Income. The Company did not experience any material
ineffectiveness with regard to its cash flow hedges during 2006
or 2004. The gain or loss recorded in accumulated other
comprehensive income (loss) remains there until the hedged
transaction occurs, at which point the gains or losses are
reclassified to operating revenues, purchased gas expense or
interest expense on the Consolidated Statements of Income. At
September 30, 2005, it was determined that certain
derivative financial instruments no longer qualified as
effective cash flow hedges due to anticipated delays in oil and
gas production volumes caused by Hurricane Rita. These volumes
were originally forecast to be produced in the first quarter of
2006. As such, at September 30, 2005, the Company
reclassified $5.1 million in accumulated losses on such
derivative financial instruments from accumulated other
comprehensive income (loss) on the Consolidated Balance Sheet to
other revenues on the Consolidated Statement of Income. For fair
value hedges, the offset to the asset or liability that is
recorded is a gain or loss recorded to operating revenues or
purchased gas expense on the Consolidated Statements of Income.
However, in the case of fair value hedges, the Company also
records an asset or liability on the Consolidated Balance Sheets
representing the change in fair value of the asset or firm
commitment that is being hedged (see Other Current Assets
section in this footnote). The offset to this asset or liability
is a gain or loss recorded to operating revenues or purchased
gas expense on the Consolidated Statements of Income as well. If
the fair value hedge is effective, the gain or loss from the
derivative financial instrument is offset by the gain or loss
that arises from the change in fair value of the asset or firm
commitment that is being hedged. The Company did not experience
any material ineffectiveness with regard to its fair value
hedges during 2006, 2005 or 2004.
Accumulated
Other Comprehensive Income (Loss)
The components of Accumulated Other Comprehensive Income (Loss)
are as follows:
|
|
|
|
|
|
|
|
|
|
|
Year Ended September 30
|
|
|
|
2006
|
|
|
2005
|
|
|
|
(Thousands)
|
|
|
Minimum Pension Liability
Adjustment
|
|
$
|
|
|
|
$
|
(107,844
|
)
|
Cumulative Foreign Currency
Translation Adjustment
|
|
|
34,701
|
|
|
|
28,009
|
|
Net Unrealized Loss on Derivative
Financial Instruments
|
|
|
(11,510
|
)
|
|
|
(123,339
|
)
|
Net Unrealized Gain on Securities
Available for Sale
|
|
|
7,225
|
|
|
|
5,546
|
|
|
|
|
|
|
|
|
|
|
Accumulated Other Comprehensive
Income (Loss)
|
|
$
|
30,416
|
|
|
$
|
(197,628
|
)
|
|
|
|
|
|
|
|
|
|
At September 30, 2006, it is estimated that of the
$11.5 million net unrealized loss on derivative financial
instruments shown in the table above $12.7 million will be
reclassified into the Consolidated Statement of Income during
2007. The remaining unrealized gain on derivative financial
instruments of $1.2 million will be reclassified into the
Consolidated Statement of Income in subsequent years. As
disclosed in Note F Financial Instruments, the
Companys derivative financial instruments extend out to
2012.
70
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Gas
Stored Underground Current
In the Utility segment, gas stored underground
current in the amount of $29.5 million is carried at lower
of cost or market, on a LIFO method. Based upon the average
price of spot market gas purchased in September 2006, including
transportation costs, the current cost of replacing this
inventory of gas stored underground current exceeded
the amount stated on a LIFO basis by approximately
$136.0 million at September 30, 2006. All other gas
stored underground current, which is in the Energy
Marketing segment, is carried at lower of cost or market on an
average cost method.
Purchased
Timber Rights
In the Timber segment, the Company purchases the right to
harvest timber from land owned by other parties. These rights,
which extend from several months to several years, are purchased
to ensure a consistent supply of timber for the Companys
sawmill and kiln operations. The historical value of timber
rights expected to be harvested during the following year are
included in Materials and Supplies on the Consolidated Balance
Sheets while the historical value of timber rights expected to
be harvested beyond one year are included in Other Assets on the
Consolidated Balance Sheets. The components of the
Companys purchased timber rights are as follows:
|
|
|
|
|
|
|
|
|
|
|
Year Ended September 30
|
|
|
|
2006
|
|
|
2005
|
|
|
|
(Thousands)
|
|
|
Materials and Supplies
|
|
$
|
13,174
|
|
|
$
|
10,610
|
|
Other Assets
|
|
|
3,218
|
|
|
|
11,510
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
16,392
|
|
|
$
|
22,120
|
|
|
|
|
|
|
|
|
|
|
Unamortized
Debt Expense
Costs associated with the issuance of debt by the Company are
deferred and amortized over the lives of the related debt. Costs
associated with the reacquisition of debt related to
rate-regulated subsidiaries are deferred and amortized over the
remaining life of the issue or the life of the replacement debt
in order to match regulatory treatment.
Foreign
Currency Translation
The functional currency for the Companys foreign
operations is the local currency of the country where the
operations are located. Asset and liability accounts are
translated at the rate of exchange on the balance sheet date.
Revenues and expenses are translated at the average exchange
rate during the period. Foreign currency translation adjustments
are recorded as a component of accumulated other comprehensive
income (loss).
Income
Taxes
The Company and its domestic subsidiaries file a consolidated
federal income tax return. Investment tax credit, prior to its
repeal in 1986, was deferred and is being amortized over the
estimated useful lives of the related property, as required by
regulatory authorities having jurisdiction.
Consolidated
Statements of Cash Flows
For purposes of the Consolidated Statements of Cash Flows, the
Company considers all highly liquid debt instruments purchased
with a maturity of three months or less to be cash equivalents.
71
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Hedging
Collateral Account
Cash held in margin accounts serves as collateral for open
positions on exchange-traded futures contracts, exchange-traded
options and
over-the-counter
swaps and collars.
Other
Current Assets
Other Current Assets consist of prepayments in the amounts of
$25.7 million and $23.9 million at September 30,
2006 and 2005, respectively, federal income taxes receivable in
the amounts of $7.5 million and $27.1 million at
September 30, 2006 and 2005, respectively, state income
taxes receivable in the amounts of $7.4 million and
$2.6 million at September 30, 2006 and 2005,
respectively, and fair values of firm commitments in the amounts
of $23.1 million and $13.7 million at
September 30, 2006 and 2005, respectively.
Earnings
Per Common Share
Basic earnings per common share is computed by dividing income
available for common stock by the weighted average number of
common shares outstanding for the period. Diluted earnings per
common share reflects the potential dilution that could occur if
securities or other contracts to issue common stock were
exercised or converted into common stock. The only potentially
dilutive securities the Company has outstanding are stock
options. The diluted weighted average shares outstanding shown
on the Consolidated Statements of Income reflect the potential
dilution as a result of these stock options as determined using
the Treasury Stock Method. Stock options that are antidilutive
are excluded from the calculation of diluted earnings per common
share. For 2006, 119,241 stock options were excluded as being
antidilutive. There were no stock options excluded as being
antidilutive for 2005. For 2004, 2,296,828 stock options were
excluded as being antidilutive.
Share
Repurchases
The Company considers all shares repurchased as cancelled shares
restored to the status of authorized but unissued shares, in
accordance with New Jersey law. The repurchases are accounted
for on the date the share repurchase is settled as an adjustment
to common stock (at par value) with the excess repurchase price
allocated between paid in capital and retained earnings. Refer
to Note E Capitalization and Short-Term
Borrowings for further discussion of the share repurchase
program.
Stock-Based
Compensation
The Company has various stock option and stock award plans which
provide or provided for the issuance of one or more of the
following to key employees: incentive stock options,
nonqualified stock options, restricted stock, performance units
or performance shares. Stock options under all plans have
exercise prices equal to the average market price of Company
common stock on the date of grant, and generally no option is
exercisable less than one year or more than ten years after the
date of each grant. Restricted stock is subject to restrictions
on vesting and transferability. Restricted stock awards entitle
the participants to full dividend and voting rights.
Certificates for shares of restricted stock awarded under the
Companys stock option and stock award plans are held by
the Company during the periods in which the restrictions on
vesting are effective. Restrictions on restricted stock awards
generally lapse ratably over a period of not more than ten years
after the date of each grant.
Prior to October 1, 2005, the Company accounted for its
stock-based compensation under the recognition and measurement
principles of APB 25 and related interpretations. Under
that method, no compensation expense was recognized for options
granted under the Companys stock option and stock award
plans. The Company did record, in accordance with APB 25,
compensation expense for the market value of restricted stock on
the date of the award over the periods during which the vesting
restrictions existed.
72
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Effective October 1, 2005, the Company adopted
SFAS 123R, which requires the measurement and recognition
of compensation cost at fair value for all share-based payments,
including stock options. The Company has chosen to use the
modified version of prospective application, as allowed by
SFAS 123R. Using the modified prospective application, the
Company is recording compensation cost for the portion of awards
granted prior to October 1, 2005 for which the requisite
service had not been rendered and is recognizing such
compensation cost as the requisite service is rendered on or
after October 1, 2005. Such compensation expense is based
on the grant-date fair value of the awards as calculated for the
Companys disclosure using a Binomial option-pricing model
under SFAS 123. Any new awards, modifications to awards,
repurchases of awards, or cancellations of awards subsequent to
September 30, 2005 will follow the provisions of
SFAS 123R, with compensation expense being calculated using
the Black-Scholes-Merton closed form model. The Company has
chosen the Black-Scholes-Merton closed form model since it is
easier to administer than the Binomial option-pricing model.
Furthermore, since the Company does not have complex stock-based
compensation awards, it does not believe that compensation
expense would be materially different under either model. There
were 317,000, 700,000 and 87,000 stock-based compensation awards
granted during the years ended September 30, 2006, 2005 and
2004, respectively. Stock-based compensation expense for the
years ended September 30, 2006, September 30, 2005,
and September 30, 2004 was approximately $1,705,000
($442,000 of which relates to the application of the
non-substantive vesting period approach discussed below),
$517,000 and $835,000, respectively. Stock-based compensation
expense is included in operation and maintenance expense on the
Consolidated Statement of Income. The total income tax benefit
related to stock-based compensation expense during the years
ended September 30, 2006, 2005 and 2004 was approximately
$653,000, $206,000 and $333,000, respectively. There were no
capitalized stock-based compensation costs during the years
ended September 30, 2006 and September 30, 2005.
Prior to the adoption of SFAS 123R, the Company followed
the nominal vesting period approach under the disclosure
requirements of SFAS 123 for determining the vesting period
for awards with retirement-eligible provisions, which recognized
stock-based compensation expense over the nominal vesting
period. As a result of the adoption of SFAS 123R, the
Company currently applies the non-substantive vesting period
approach for determining the vesting period of such awards.
Under this approach, the retention of the award is not
contingent on providing subsequent service and the vesting
period would begin at the grant date and end at the
retirement-eligible date. For the year ended September 30,
2006, the Company recognized an additional $442,000
($288,000 net of tax) of stock-based compensation expense
by applying the non-substantive vesting approach. For the year
ended September 30, 2005, stock-based compensation expense
would have been $4,282,000 ($2,752,000 net of tax) for pro
forma recognition purposes had the non-substantive vesting
period approach been used. The pro forma stock-based
compensation expense would have been $2,670,000
($1,798,000 net of tax) under the non-substantive vesting
period approach for the year ended September 30, 2004. Pro
forma stock-based compensation expense following the nominal
vesting period approach is shown in the table below.
73
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The following table illustrates the effect on net income and
earnings per share of the Company had the Company applied the
fair value recognition provisions of SFAS 123 relating to
stock-based employee compensation for the years ended
September 30, 2005 and 2004:
|
|
|
|
|
|
|
|
|
|
|
Year Ended September 30
|
|
|
|
2005
|
|
|
2004
|
|
|
|
(Thousands, except per share amounts)
|
|
|
Net Income, Available for Common
Stock, As Reported
|
|
$
|
189,488
|
|
|
$
|
166,586
|
|
Add: Stock-Based Employee
Compensation Expense Included in Reported Net Income, Net of
Tax(1)
|
|
|
336
|
|
|
|
543
|
|
Deduct: Total Stock-Based Employee
Compensation Expense Determined Under Fair Value Based Methods
for all Awards, Net of Related Tax Effects
|
|
|
(2,782
|
)
|
|
|
(1,861
|
)
|
|
|
|
|
|
|
|
|
|
Pro Forma Net Income Available for
Common Stock
|
|
$
|
187,042
|
|
|
$
|
165,268
|
|
|
|
|
|
|
|
|
|
|
Earnings Per Common Share:
|
|
|
|
|
|
|
|
|
Basic As Reported
|
|
$
|
2.27
|
|
|
$
|
2.03
|
|
Basic Pro Forma
|
|
$
|
2.24
|
|
|
$
|
2.01
|
|
Diluted As Reported
|
|
$
|
2.23
|
|
|
$
|
2.01
|
|
Diluted Pro Forma
|
|
$
|
2.20
|
|
|
$
|
1.99
|
|
|
|
|
(1) |
|
Stock-based compensation expense in 2005 and 2004 represented
compensation expense related to restricted stock awards. The
pre-tax expense was $517,000 and $835,000, respectively, for the
years ended September 30, 2005 and 2004. |
Stock
Options
The total intrinsic value of stock options exercised during the
years ended September 30, 2006, September 30, 2005,
and September 30, 2004 totaled approximately
$30.9 million, $19.8 million, and $12.4 million,
respectively. For 2006, 2005 and 2004, the amount of cash
received by the Company from the exercise of such stock options
was approximately $30.1 million, $24.8 million, and
$16.4 million, respectively. The Company realizes tax
benefits related to the exercise of stock options on a calendar
year basis as opposed to a fiscal year basis. As such, for stock
options exercised during the quarters ended December 31,
2005, December 31, 2004, and December 31, 2003, the
Company realized a tax benefit of $0.9 million,
$1.1 million, and $0.1 million, respectively. For
stock options exercised during the period of January 1,
2006 through September 30, 2006, the Company will realize a
tax benefit of approximately $11.4 million in the quarter
ended December 31, 2006. For stock options exercised during
the period of January 1, 2005 through September 30,
2005, the Company realized a tax benefit of approximately
$6.3 million in the quarter ended December 31, 2005.
For stock options exercised during the period of January 1,
2004 through September 30, 2004, the Company realized a tax
benefit of approximately $4.8 million in the quarter ended
December 31, 2004. The weighted average grant date fair
value of options granted in 2006, 2005 and 2004 is
$6.68 per share, $4.59 per share, and $4.66 per
share, respectively. For the years ended September 30,
2006, 2005 and 2004, 89,665, 1,375,105 and 729,156 stock options
became fully vested, respectively. The total fair value of these
stock options was approximately $0.4 million,
$6.2 million and $3.3 million, respectively, for the
years ended September 30, 2006, 2005 and 2004. As of
September 30, 2006, unrecognized compensation expense
related to stock options totaled approximately
$0.9 million, which will be recognized over a weighted
average period of one year. For a summary of transactions during
2006 involving option shares for all plans, refer to
Note E Capitalization and Short-Term Borrowings.
74
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The fair value of options at the date of grant was estimated
using a Binomial option-pricing model for options granted prior
to October 1, 2005 and the Black-Scholes-Merton closed form
model for options granted after September 30, 2005. The
following weighted average assumptions were used in estimating
the fair value of options at the date of grant:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended September 30
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
Risk Free Interest Rate
|
|
|
5.08
|
%
|
|
|
4.46
|
%
|
|
|
4.61
|
%
|
Expected Life (Years)
|
|
|
7.0
|
|
|
|
7.0
|
|
|
|
7.0
|
|
Expected Volatility
|
|
|
17.71
|
%
|
|
|
17.76
|
%
|
|
|
21.77
|
%
|
Expected Dividend Yield (Quarterly)
|
|
|
0.83
|
%
|
|
|
1.00
|
%
|
|
|
1.12
|
%
|
The risk-free interest rate is based on the yield of a Treasury
Note with a remaining term commensurate with the expected term
of the option. The expected life and expected volatility are
based on historical experience.
For grants prior to October 1, 2005, the Company used a
forfeiture rate of 13.6% for calculating stock-based
compensation expense related to stock options and this rate is
based on the Companys historical experience of forfeitures
on unvested stock option grants. For grants during the year
ended September 30, 2006, it was assumed that there would
be no forfeitures, based on the vesting term and the number of
grantees.
Restricted
Share Awards
For a summary of transactions during 2006 involving restricted
share awards, refer to Note E Capitalization
and Short-Term Borrowings.
As of September 30, 2006, unrecognized compensation expense
related to restricted share awards totaled approximately
$577,000, which will be recognized over a weighted average
period of 2.1 years.
During 2006, a modification was made to a restricted share award
involving one employee. The modification accelerated the vesting
date of 4,000 shares from December 7, 2006 to
July 1, 2006. The incremental compensation expense,
totaling approximately $32,000, was included with the total
stock-based compensation expense for the year ended
September 30, 2006.
New
Accounting Pronouncements
In March 2005, the FASB issued FIN 47, an interpretation of
SFAS 143. FIN 47 provides clarification of the term
conditional asset retirement obligation as used in
SFAS 143, defined as a legal obligation to perform an asset
retirement activity in which the timing
and/or
method of settlement are conditional on a future event that may
or may not be within the control of the Company. Under this
standard, a company must record a liability for a conditional
asset retirement obligation if the fair value of the obligation
can be reasonably estimated. FIN 47 also serves to clarify
when a company would have sufficient information to reasonably
estimate the fair value of a conditional asset retirement
obligation. The Company has adopted FIN 47 as of
September 30, 2006. Refer to Note B Asset
Retirement Obligations for further disclosure regarding the
impact of FIN 47 on the Companys consolidated
financial statements.
In May 2005, the FASB issued SFAS 154. SFAS 154
replaces APB 20 and SFAS 3 and changes the
requirements for the accounting for and reporting of a change in
accounting principle. The Company is required to adopt
SFAS 154 for accounting changes and corrections of errors
that occur in 2007. The Companys financial condition and
results of operations will only be impacted by SFAS 154 if
there are any accounting changes or corrections of errors in the
future.
75
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
In June 2006, the FASB issued FIN 48, an interpretation of
SFAS 109. FIN 48 clarifies the accounting for
uncertainty in income taxes and reduces the diversity in current
practice associated with the financial statement recognition and
measurement of a tax position taken or expected to be taken in a
tax return by defining a more-likely-than-not
threshold regarding the sustainability of the position. The
Company is required to adopt FIN 48 by the first quarter of
fiscal 2008. The Company is currently evaluating the impact of
FIN 48 on its consolidated financial statements.
In September 2006, the FASB issued SFAS 157, Fair
Value Measurements. SFAS 157 provides guidance for
using fair value to measure assets and liabilities. The
pronouncement serves to clarify the extent to which companies
measure assets and liabilities at fair value, the information
used to measure fair value, and the effect that fair-value
measurements have on earnings. SFAS 157 is to be applied
whenever another standard requires or allows assets or
liabilities to be measured at fair value. The pronouncement is
effective as of the Companys first quarter of fiscal 2009.
The Company is currently evaluating the impact that the adoption
of SFAS 157 will have on its consolidated financial
statements.
In September 2006, the FASB also issued SFAS 158,
Employers Accounting for Defined Benefit Pension and
Other Postretirement Plans (an amendment of SFAS 87,
SFAS 88, SFAS 106, and SFAS 132R). SFAS 158
requires that companies recognize a net liability or asset to
report the underfunded or overfunded status of their defined
benefit pension and other post-retirement benefit plans on their
balance sheets, as well as recognize changes in the funded
status of a defined benefit post-retirement plan in the year in
which the changes occur through comprehensive income. The
pronouncement also specifies that a plans assets and
obligations that determine its funded status be measured as of
the end of the Companys fiscal year, with limited
exceptions. The Company is required to recognize the funded
status of its benefit plans and the disclosure requirements of
SFAS 158 by the fourth quarter of fiscal 2007. The
requirement to measure the plan assets and benefit obligations
as of the Companys fiscal year-end date will be adopted by
the Company by the end of fiscal 2009. If the Company recognized
the funded status of its pension and post-retirement benefit
plans at September 30, 2006, the Companys
consolidated balance sheet would reflect a liability of
$220.8 million instead of the prepaid pension and
post-retirement costs of $64.1 million and pension and
post-retirement liabilities of $32.9 million that are
currently presented on the balance sheet at September 30,
2006. The Company expects that it will record a regulatory asset
for the majority of this liability with the remainder reflected
in accumulated other comprehensive income (loss).
Note B
Asset Retirement Obligations
Effective October 1, 2002, the Company adopted
SFAS 143. SFAS 143 requires entities to record the
fair value of a liability for an asset retirement obligation in
the period in which it is incurred. When the liability is
initially recorded, the entity capitalizes the estimated cost of
retiring the asset as part of the carrying amount of the related
long-lived asset. Over time, the liability is adjusted to its
present value each period and the capitalized cost is
depreciated over the useful life of the related asset. Upon the
adoption of SFAS 143, the Company recorded an asset
retirement obligation representing plugging and abandonment
costs associated with the Exploration and Production
segments crude oil and natural gas wells.
On September 30, 2006, the Company adopted FIN 47, an
interpretation of SFAS 143. FIN 47 provides
clarification of the term conditional asset retirement
obligation as used in SFAS 143, defined as a legal
obligation to perform an asset retirement activity in which the
timing
and/or
method of settlement are conditional on a future event that may
or may not be within the control of the Company. Under this
standard, if the fair value of a conditional asset retirement
obligation can be reasonably estimated, a company must record a
liability and a corresponding asset for the conditional asset
retirement obligation representing the present value of that
obligation at the date the obligation was incurred. FIN 47
also serves to clarify when a company would have sufficient
information to reasonably estimate the fair value of a
conditional asset retirement obligation.
76
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
As a result of the adoption of FIN 47, the Company
identified future asset retirement obligations associated with
the plugging and abandonment of natural gas storage wells in the
Pipeline and Storage segment and the removal of asbestos and
asbestos-containing material in various facilities in the
Utility and Pipeline and Storage segments. The Company also
identified asset retirement obligations for certain costs
connected with the retirement of distribution mains and services
pipeline systems in the Utility segment and with the
transmission mains and other components in the pipeline systems
in the Pipeline and Storage segment. These retirement costs
within the distribution and transmission systems are primarily
for the capping and purging of pipe, which are generally
abandoned in place when retired, as well as for the
clean-up of
PCB contamination associated with the removal of certain pipe.
A reconciliation of the Companys asset retirement
obligation calculated in accordance with SFAS 143 is shown
below ($000s):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended September 30
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
|
(Thousands)
|
|
|
Balance at Beginning of Year
|
|
$
|
41,411
|
|
|
$
|
32,292
|
|
|
$
|
27,493
|
|
Additions Adoption of
FIN 47
|
|
|
23,234
|
|
|
|
|
|
|
|
|
|
Liabilities Incurred and Revisions
of Estimates
|
|
|
11,244
|
|
|
|
8,343
|
|
|
|
3,510
|
|
Liabilities Settled
|
|
|
(1,303
|
)
|
|
|
(1,938
|
)
|
|
|
(831
|
)
|
Accretion Expense
|
|
|
2,671
|
|
|
|
2,448
|
|
|
|
1,933
|
|
Exchange Rate Impact
|
|
|
135
|
|
|
|
266
|
|
|
|
187
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at End of Year
|
|
$
|
77,392
|
|
|
$
|
41,411
|
|
|
$
|
32,292
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As a result of the implementation of FIN 47 as of
September 30, 2006, the Company recorded additional asset
retirement obligations of $23.2 million and corresponding
long-lived plant assets, net of accumulated depreciation, of
$3.5 million. These assets will be depreciated over their
respective remaining depreciable life. The remaining
$19.7 million represents the cumulative accretion and
depreciation of the asset retirement obligations that would have
been recognized if this interpretation had been in effect at the
inception of the obligations. Of this amount, the Company
recorded an increase to regulatory assets of $9.0 million
and a reduction to cost of removal regulatory liability of
$10.7 million. The cost of removal regulatory liability
represents amounts collected from customers through depreciation
expense in the Companys Utility and Pipeline and Storage
segments. These removal costs are not a legal retirement
obligation in accordance with SFAS 143. Rather, they
represent a regulatory liability. However, SFAS 143
requires that such costs of removal be reclassified from
accumulated depreciation to other regulatory liabilities. At
September 30, 2006 and 2005, the costs of removal
reclassified to other regulatory liabilities amounted to
$85.1 million and $90.4 million, respectively.
Pursuant to FIN 47, the financial statements for periods
prior to September 30, 2006 have not been restated. If
FIN 47 had been in effect, the Company would have recorded
additional asset retirement obligations of $21.9 million at
September 30, 2005, and $20.6 million at
October 1, 2004.
77
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Note C
Regulatory Matters
Regulatory
Assets and Liabilities
The Company has recorded the following regulatory assets and
liabilities:
|
|
|
|
|
|
|
|
|
|
|
At September 30
|
|
|
|
2006
|
|
|
2005
|
|
|
|
(Thousands)
|
|
|
Regulatory Assets(1):
|
|
|
|
|
|
|
|
|
Recoverable Future Taxes
(Note D)
|
|
$
|
79,511
|
|
|
$
|
85,000
|
|
Pension and Post-Retirement
Benefit Costs(2) (Note G)
|
|
|
47,368
|
|
|
|
27,135
|
|
Unrecovered Purchased Gas Costs
(See Regulatory Mechanisms in Note A)
|
|
|
12,970
|
|
|
|
14,817
|
|
Environmental Site Remediation
Costs(2) (Note H)
|
|
|
12,937
|
|
|
|
13,054
|
|
Asset Retirement Obligation(2)
(Note B)
|
|
|
9,018
|
|
|
|
|
|
Unamortized Debt Expense
(Note A)
|
|
|
8,399
|
|
|
|
9,088
|
|
Other(2)
|
|
|
7,594
|
|
|
|
6,839
|
|
|
|
|
|
|
|
|
|
|
Total Regulatory Assets
|
|
|
177,797
|
|
|
|
155,933
|
|
|
|
|
|
|
|
|
|
|
Regulatory
Liabilities:
|
|
|
|
|
|
|
|
|
Cost of Removal Regulatory
Liability (Note B)
|
|
|
85,076
|
|
|
|
90,396
|
|
New York Rate Settlements(3)
|
|
|
40,881
|
|
|
|
53,205
|
|
Amounts Payable to Customers (See
Regulatory Mechanisms in Note A)
|
|
|
23,935
|
|
|
|
1,158
|
|
Tax Benefit on Medicare
Part D Subsidy(3)
|
|
|
13,791
|
|
|
|
|
|
Pension and Post-Retirement
Benefit Costs(3) (Note G)
|
|
|
13,063
|
|
|
|
12,751
|
|
Taxes Refundable to Customers
(Note D)
|
|
|
10,426
|
|
|
|
11,009
|
|
Deferred Insurance Proceeds(3)
|
|
|
7,516
|
|
|
|
|
|
Other(3)
|
|
|
205
|
|
|
|
383
|
|
|
|
|
|
|
|
|
|
|
Total Regulatory Liabilities
|
|
|
194,893
|
|
|
|
168,902
|
|
|
|
|
|
|
|
|
|
|
Net Regulatory Position
|
|
$
|
(17,096
|
)
|
|
$
|
(12,969
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
The Company recovers the cost of its regulatory assets but, with
the exception of Unrecovered Purchased Gas Costs, does not earn
a return on them. |
|
(2) |
|
Included in Other Regulatory Assets on the Consolidated Balance
Sheets. |
|
(3) |
|
Included in Other Regulatory Liabilities on the Consolidated
Balance Sheets. |
If for any reason the Company ceases to meet the criteria for
application of regulatory accounting treatment for all or part
of its operations, the regulatory assets and liabilities related
to those portions ceasing to meet such criteria would be
eliminated from the balance sheet and included in income of the
period in which the discontinuance of regulatory accounting
treatment occurs. Such amounts would be classified as an
extraordinary item.
78
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
New
York Rate Settlements
With respect to utility services provided in New York, the
Company has entered into rate settlements approved by the NYPSC.
The rate settlements have given rise to several significant
liabilities, which are described as follows:
Gross Receipts Tax Over-Collections In
accordance with NYPSC policies, Distribution Corporation
deferred the difference between the revenues it collects under a
New York State gross receipts tax surcharge and its actual New
York State income tax expense. Distribution Corporations
cumulative gross receipts tax revenues exceeded its New York
State income tax expense, resulting in a regulatory liability at
September 30, 2006 and 2005 of $19.8 million and
$34.3 million, respectively. Under the terms of its 2005
rate settlement, Distribution Corporation will pass back that
regulatory liability to rate payers over a twenty-four month
period that began August 1, 2005. Further, the gross
receipts tax surcharge that gave rise to the regulatory
liability was eliminated from Distribution Corporations
tariff (New York State income taxes are now recovered as a
component of base rates).
Cost Mitigation Reserve (CMR) The
CMR is a regulatory liability that can be used to offset certain
expense items specified in Distribution Corporations rate
settlements. The source of the CMR is principally the
accumulation of certain refunds from upstream pipeline
companies. During 2005, under the terms of the 2005 rate
settlement, Distribution Corporation transferred the remaining
balance in a generic restructuring reserve (which had been
established in a prior rate settlement) and the balances it had
accumulated under various earnings sharing mechanisms to the
CMR. The balance in the CMR at September 30, 2006 and 2005
amounted to $7.6 million and $7.0 million,
respectively.
Other The 2005 settlement also established a
reserve to fund area development projects. The balance in the
area development projects reserve at September 30, 2006 and
2005 amounted to $3.9 million and $3.8 million,
respectively (Distribution Corporation established the reserve
at September 30, 2005 by transferring $3.8 million
from the CMR discussed above). Various other regulatory
liabilities have also been created through the New York rate
settlements and amounted to $9.6 million and
$8.1 million at September 30, 2006 and 2005,
respectively.
Tax
Benefit on Medicare Part D Subsidy
The Company has established a regulatory liability for the tax
benefit it will receive under the Medicare Prescription Drug,
Improvement, and Modernization Act of 2003 (the Act). The Act
provides 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. In the
Companys Utility and Pipeline and Storage segments, the
rate payer funds the Companys post-retirement benefit
plans. As such, any tax benefit received under the Act must be
flowed-through to the rate payer. Refer to
Note G Retirement Plan and Other
Post-Retirement Benefits for further discussion of the Act and
its impact on the Company.
Deferred
Insurance Proceeds
The Company, in its Utility and Pipeline and Storage segments,
received $7.5 million in environmental insurance settlement
proceeds. Such proceeds have been deferred as a regulatory
liability to be applied against any future environmental claims
that may be incurred. The proceeds have been classified as a
regulatory liability in recognition of the fact that rate payers
funded the premiums on the former insurance policies.
79
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Note D
Income Taxes
The components of federal, state and foreign income taxes
included in the Consolidated Statements of Income are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended September 30
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
|
(Thousands)
|
|
|
Operating Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
Current Income Taxes
|
|
|
|
|
|
|
|
|
|
|
|
|
Federal
|
|
$
|
65,593
|
|
|
$
|
40,062
|
|
|
$
|
42,679
|
|
State
|
|
|
13,511
|
|
|
|
14,413
|
|
|
|
7,871
|
|
Foreign
|
|
|
2,212
|
|
|
|
1,503
|
|
|
|
206
|
|
Deferred Income Taxes
|
|
|
|
|
|
|
|
|
|
|
|
|
Federal
|
|
|
19,111
|
|
|
|
27,412
|
|
|
|
29,559
|
|
State
|
|
|
9,024
|
|
|
|
2,280
|
|
|
|
9,620
|
|
Foreign
|
|
|
(33,365
|
)
|
|
|
7,308
|
|
|
|
4,655
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
76,086
|
|
|
|
92,978
|
|
|
|
94,590
|
|
Other Income:
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred Investment Tax Credit
|
|
|
(697
|
)
|
|
|
(697
|
)
|
|
|
(697
|
)
|
Discontinued Operations
|
|
|
|
|
|
|
|
|
|
|
|
|
Operations
|
|
|
|
|
|
|
9,310
|
|
|
|
(1,479
|
)
|
Gain on Sale
|
|
|
|
|
|
|
1,612
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Income Taxes
|
|
$
|
75,389
|
|
|
$
|
103,203
|
|
|
$
|
92,414
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The U.S. and foreign components of income (loss) before income
taxes are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended September 30
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
|
(Thousands)
|
|
|
U.S.
|
|
$
|
293,887
|
|
|
$
|
223,113
|
|
|
$
|
232,928
|
|
Foreign
|
|
|
(80,407
|
)
|
|
|
69,578
|
|
|
|
26,072
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
213,480
|
|
|
$
|
292,691
|
|
|
$
|
259,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total income taxes as reported differ from the amounts that were
computed by applying the federal income tax rate to income
before income taxes. The following is a reconciliation of this
difference:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended September 30
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
|
(Thousands)
|
|
|
Income Tax Expense, Computed at
U.S. Federal Statutory Rate of 35%
|
|
$
|
74,718
|
|
|
$
|
102,442
|
|
|
$
|
90,650
|
|
Increase in Taxes Resulting from:
|
|
|
|
|
|
|
|
|
|
|
|
|
State Income Taxes
|
|
|
14,648
|
|
|
|
10,850
|
|
|
|
11,369
|
|
Foreign Tax Differential
|
|
|
(3,718
|
)
|
|
|
(4,845
|
)
|
|
|
(1,166
|
)
|
Foreign Tax Rate Reduction
|
|
|
|
|
|
|
|
|
|
|
(5,174
|
)
|
Reversal of Capital Loss Valuation
Allowance
|
|
|
(2,877
|
)
|
|
|
|
|
|
|
|
|
Miscellaneous
|
|
|
(7,382
|
)
|
|
|
(5,244
|
)
|
|
|
(3,265
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Income Taxes
|
|
$
|
75,389
|
|
|
$
|
103,203
|
|
|
$
|
92,414
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
80
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The foreign tax differential amount shown above for 2006
includes a $5.1 million deferred tax benefit relating to
additional future tax deductions forecasted in Canada and the
amount for 2005 includes tax effects relating to the disposition
of a foreign subsidiary. The foreign tax rate reduction amount
shown above for 2004 relates to the reduction of the statutory
income tax rate in the Czech Republic. The miscellaneous amount
shown above for 2006 includes a net reversal of
$3.2 million relating to a tax contingency reserve.
Significant components of the Companys deferred tax
liabilities and assets are as follows:
|
|
|
|
|
|
|
|
|
|
|
At September 30
|
|
|
|
2006
|
|
|
2005
|
|
|
|
(Thousands)
|
|
|
Deferred Tax Liabilities:
|
|
|
|
|
|
|
|
|
Property, Plant and Equipment
|
|
$
|
569,677
|
|
|
$
|
567,850
|
|
Other
|
|
|
37,865
|
|
|
|
52,436
|
|
|
|
|
|
|
|
|
|
|
Total Deferred Tax Liabilities
|
|
|
607,542
|
|
|
|
620,286
|
|
|
|
|
|
|
|
|
|
|
Deferred Tax Assets:
|
|
|
|
|
|
|
|
|
Minimum Pension Liability
Adjustment
|
|
|
|
|
|
|
(58,069
|
)
|
Capital Loss Carryover
|
|
|
(8,786
|
)
|
|
|
(9,145
|
)
|
Unrealized Hedging Losses
|
|
|
(4,653
|
)
|
|
|
(75,657
|
)
|
Other
|
|
|
(82,006
|
)
|
|
|
(74,346
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
(95,445
|
)
|
|
|
(217,217
|
)
|
Valuation Allowance
|
|
|
|
|
|
|
2,877
|
|
|
|
|
|
|
|
|
|
|
Total Deferred Tax Assets
|
|
|
(95,445
|
)
|
|
|
(214,340
|
)
|
|
|
|
|
|
|
|
|
|
Total Net Deferred Income Taxes
|
|
$
|
512,097
|
|
|
$
|
405,946
|
|
|
|
|
|
|
|
|
|
|
Presented as Follows:
|
|
|
|
|
|
|
|
|
Net Deferred Tax Asset
Current
|
|
$
|
(23,402
|
)
|
|
$
|
(83,774
|
)
|
Net Deferred Tax Asset
Non-Current
|
|
|
(9,003
|
)
|
|
|
|
|
Net Deferred Tax
Liability Non-Current
|
|
|
544,502
|
|
|
|
489,720
|
|
|
|
|
|
|
|
|
|
|
Total Net Deferred Income Taxes
|
|
$
|
512,097
|
|
|
$
|
405,946
|
|
|
|
|
|
|
|
|
|
|
Regulatory liabilities representing the reduction of previously
recorded deferred income taxes associated with rate-regulated
activities that are expected to be refundable to customers
amounted to $10.4 million and $11.0 million at
September 30, 2006 and 2005, respectively. Also, regulatory
assets representing future amounts collectible from customers,
corresponding to additional deferred income taxes not previously
recorded because of prior ratemaking practices, amounted to
$79.5 million and $85.0 million at September 30,
2006 and 2005, respectively.
The American Jobs Creation Act of 2004, signed into law on
October 22, 2004, included a provision which provided a
substantially reduced tax rate of 5.25% on certain dividends
received from foreign affiliates. During 2005, the Company
received a dividend of $72.8 million from a foreign
affiliate and recorded a tax of $3.8 million on such
dividend.
A capital loss carryover of $25.1 million exists at
September 30, 2006, which expires if not utilized by
September 30, 2008. Although realization is not assured,
management determined that it is more likely than not that the
entire deferred tax asset associated with this carryover will be
realized during the carryover period. As such, the valuation
allowance of $2.9 million was reversed during 2006.
81
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
A deferred tax asset of $9.0 million relating to Canadian
operations exists at September 30, 2006. Although
realization is not assured, management determined that it is
more likely than not that future taxable income will be
generated in Canada to fully utilize this asset, and as such, no
valuation allowance was provided.
Note E
Capitalization and Short-Term Borrowings
Summary
of Changes in Common Stock Equity
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings
|
|
|
Accumulated
|
|
|
|
|
|
|
|
|
|
|
|
|
Reinvested
|
|
|
Other
|
|
|
|
|
|
|
|
|
|
Paid
|
|
|
in
|
|
|
Comprehensive
|
|
|
|
Common Stock
|
|
|
In
|
|
|
the
|
|
|
Income
|
|
|
|
Shares
|
|
|
Amount
|
|
|
Capital
|
|
|
Business
|
|
|
(Loss)
|
|
|
|
(Thousands, except per share amounts)
|
|
|
Balance at September 30, 2003
|
|
|
81,438
|
|
|
$
|
81,438
|
|
|
$
|
478,799
|
|
|
$
|
642,690
|
|
|
$
|
(65,537
|
)
|
Net Income Available for Common
Stock
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
166,586
|
|
|
|
|
|
Dividends Declared on Common Stock
($1.10 Per Share)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(90,350
|
)
|
|
|
|
|
Other Comprehensive Income, Net of
Tax
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10,762
|
|
Common Stock Issued Under Stock
and Benefit Plans(1)
|
|
|
1,552
|
|
|
|
1,552
|
|
|
|
27,761
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at September 30, 2004
|
|
|
82,990
|
|
|
|
82,990
|
|
|
|
506,560
|
|
|
|
718,926
|
|
|
|
(54,775
|
)
|
Net Income Available for Common
Stock
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
189,488
|
|
|
|
|
|
Dividends Declared on Common Stock
($1.14 Per Share)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(95,394
|
)
|
|
|
|
|
Other Comprehensive Loss, Net of
Tax
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(142,853
|
)
|
Cancellation of Shares
|
|
|
(2
|
)
|
|
|
(2
|
)
|
|
|
(52
|
)
|
|
|
|
|
|
|
|
|
Common Stock Issued Under Stock
and Benefit Plans(1)
|
|
|
1,369
|
|
|
|
1,369
|
|
|
|
23,326
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at September 30, 2005
|
|
|
84,357
|
|
|
|
84,357
|
|
|
|
529,834
|
|
|
|
813,020
|
|
|
|
(197,628
|
)
|
Net Income Available for Common
Stock
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
138,091
|
|
|
|
|
|
Dividends Declared on Common Stock
($1.18 Per Share)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(98,829
|
)
|
|
|
|
|
Other Comprehensive Income, Net of
Tax
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
228,044
|
|
Share-Based Payment Expense(2)
|
|
|
|
|
|
|
|
|
|
|
1,705
|
|
|
|
|
|
|
|
|
|
Common Stock Issued Under Stock
and Benefit Plans(1)
|
|
|
1,572
|
|
|
|
1,572
|
|
|
|
28,564
|
|
|
|
|
|
|
|
|
|
Share Repurchases
|
|
|
(2,526
|
)
|
|
|
(2,526
|
)
|
|
|
(16,373
|
)
|
|
|
(66,269
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at September 30, 2006
|
|
|
83,403
|
|
|
$
|
83,403
|
|
|
$
|
543,730
|
|
|
$
|
786,013
|
(3)
|
|
$
|
30,416
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Paid in Capital includes tax benefits of $6.5 million,
$3.7 million and $1.5 million for September 30,
2006, 2005 and 2004, respectively, associated with the exercise
of stock options. |
|
(2) |
|
As of October 1, 2005, Paid in Capital includes
compensation costs associated with stock option and restricted
stock awards, in accordance with SFAS 123R. The expense is
included within Net Income Available For Common Stock, net of
tax benefits. |
|
(3) |
|
The availability of consolidated earnings reinvested in the
business for dividends payable in cash is limited under terms of
the indentures covering long-term debt. At September 30,
2006, $692.7 million of accumulated earnings was free of
such limitations. |
82
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Common
Stock
The Company has various plans which allow shareholders,
employees and others to purchase shares of the Company common
stock. The National Fuel Gas Company Direct Stock Purchase and
Dividend Reinvestment Plan allows shareholders to reinvest cash
dividends and make cash investments in the Companys common
stock and provides investors the opportunity to acquire shares
of the Company common stock without the payment of any brokerage
commissions in connection with such acquisitions. The 401(k)
Plans allow employees the opportunity to invest in the Company
common stock, in addition to a variety of other investment
alternatives. Generally, at the discretion of the Company,
shares purchased under these plans are either original issue
shares purchased directly from the Company or shares purchased
on the open market by an independent agent.
During 2006, the Company issued 2,292,639 original issue shares
of common stock as a result of stock option exercises and 16,000
original issue shares for restricted stock awards (non-vested
stock as defined in SFAS 123R). Holders of stock options or
restricted stock will often tender shares of common stock to the
Company for payment of option exercise prices
and/or
applicable withholding taxes. During 2006, 744,567 shares
of common stock were tendered to the Company for such purposes.
The Company considers all shares tendered as cancelled shares
restored to the status of authorized but unissued shares, in
accordance with New Jersey law.
The Company also has a Director Stock Program under which it
issues shares of the Company common stock to its non-employee
directors as partial consideration for their services as
directors. Under this program, the Company issued 8,400 original
issue shares of common stock to the non-employee directors of
the Company during 2006.
On December 8, 2005, the Companys Board of Directors
authorized the Company to implement a share repurchase program,
whereby the Company may repurchase outstanding shares of common
stock, up to an aggregate amount of 8 million shares in the
open market or through privately negotiated transactions. During
2006, the Company repurchased 2,526,550 shares under this
program, funded with cash provided by operating activities. At
September 30, 2006, the Company had made commitments to
repurchase an additional 99,100 shares of common stock.
These commitments were settled and recorded as a reduction of
the Companys outstanding shares of common stock in October
2006.
Shareholder
Rights Plan
In 1996, the Companys Board of Directors adopted a
shareholder rights plan (Plan). Effective April 30, 1999,
the Plan was amended and is now embodied in an Amended and
Restated Rights Agreement, under which the Board of Directors
made adjustments in connection with the
two-for-one
stock split of September 7, 2001.
The holders of the Companys common stock have one right
(Right) for each of their shares. Each Right, which will
initially be evidenced by the Companys common stock
certificates representing the outstanding shares of common
stock, entitles the holder to purchase one-half of one share of
common stock at a purchase price of $65.00 per share, being
$32.50 per half share, subject to adjustment (Purchase
Price).
The Rights become exercisable upon the occurrence of a
distribution date. At any time following a distribution date,
each holder of a Right may exercise its right to receive common
stock (or, under certain circumstances, other property of the
Company) having a value equal to two times the Purchase Price of
the Right then in effect. However, the Rights are subject to
redemption or exchange by the Company prior to their exercise as
described below.
A distribution date would occur upon the earlier of (i) ten
days after the public announcement that a person or group has
acquired, or obtained the right to acquire, beneficial ownership
of the Companys common stock or other voting stock having
10% or more of the total voting power of the Companys
common stock and other
83
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
voting stock and (ii) ten days after the commencement or
announcement by a person or group of an intention to make a
tender or exchange offer that would result in that person
acquiring, or obtaining the right to acquire, beneficial
ownership of the Companys common stock or other voting
stock having 10% or more of the total voting power of the
Companys common stock and other voting stock.
In certain situations after a person or group has acquired
beneficial ownership of 10% or more of the total voting power of
the Companys stock as described above, each holder of a
Right will have the right to exercise its Rights to receive
common stock of the acquiring company having a value equal to
two times the Purchase Price of the Right then in effect. These
situations would arise if the Company is acquired in a merger or
other business combination or if 50% or more of the
Companys assets or earning power are sold or transferred.
At any time prior to the end of the business day on the tenth
day following the announcement that a person or group has
acquired, or obtained the right to acquire, beneficial ownership
of 10% or more of the total voting power of the Company, the
Company may redeem the Rights in whole, but not in part, at a
price of $0.005 per Right, payable in cash or stock. A
decision to redeem the Rights requires the vote of 75% of the
Companys full Board of Directors. Also, at any time
following the announcement that a person or group has acquired,
or obtained the right to acquire, beneficial ownership of 10% or
more of the total voting power of the Company, 75% of the
Companys full Board of Directors may vote to exchange the
Rights, in whole or in part, at an exchange rate of one share of
common stock, or other property deemed to have the same value,
per Right, subject to certain adjustments.
After a distribution date, Rights that are owned by an acquiring
person will be null and void. Upon exercise of the Rights, the
Company may need additional regulatory approvals to satisfy the
requirements of the Rights Agreement. The Rights will expire on
July 31, 2008, unless they are exchanged or redeemed
earlier than that date.
The Rights have anti-takeover effects because they will cause
substantial dilution of the common stock if a person attempts to
acquire the Company on terms not approved by the Board of
Directors.
Stock
Option and Stock Award Plans
The Company has various stock option and stock award plans which
provide or provided for the issuance of one or more of the
following to key employees: incentive stock options,
nonqualified stock options, restricted stock, performance units
or performance shares. Stock options under all plans have
exercise prices equal to the average market price of Company
common stock on the date of grant, and generally no option is
exercisable less than one year or more than ten years after the
date of each grant.
84
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Transactions involving option shares for all plans are
summarized as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
|
|
|
|
|
|
|
Average
|
|
|
|
|
|
|
Number of
|
|
|
|
|
|
Remaining
|
|
|
Aggregate
|
|
|
|
Shares Subject
|
|
|
Weighted Average
|
|
|
Contractual
|
|
|
Intrinsic
|
|
|
|
to Option
|
|
|
Exercise Price
|
|
|
Life (Years)
|
|
|
Value
|
|
|
|
|
|
|
|
|
|
|
|
|
(In thousands)
|
|
|
Outstanding at September 30,
2005
|
|
|
10,996,893
|
|
|
$
|
23.78
|
|
|
|
|
|
|
|
|
|
Granted in 2006
|
|
|
317,000
|
|
|
$
|
35.21
|
|
|
|
|
|
|
|
|
|
Exercised in 2006
|
|
|
(2,292,639
|
)
|
|
$
|
21.77
|
|
|
|
|
|
|
|
|
|
Forfeited in 2006
|
|
|
(5,000
|
)
|
|
$
|
24.94
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at September 30,
2006
|
|
|
9,016,254
|
|
|
$
|
24.69
|
|
|
|
4.21
|
|
|
$
|
105,096
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Option shares exercisable at
September 30, 2006
|
|
|
8,643,753
|
|
|
$
|
24.32
|
|
|
|
4.01
|
|
|
$
|
103,999
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Option shares available for future
grant at September 30, 2006(1)
|
|
|
434,911
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Including shares available for restricted stock grants. |
The following table summarizes information about options
outstanding at September 30, 2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Options Outstanding
|
|
|
Options Exercisable
|
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
|
|
|
|
|
|
|
Number
|
|
|
Average
|
|
|
Weighted
|
|
|
Number
|
|
|
Weighted
|
|
|
|
Outstanding
|
|
|
Remaining
|
|
|
Average
|
|
|
Exercisable
|
|
|
Average
|
|
|
|
at
|
|
|
Contractual
|
|
|
Exercise
|
|
|
at
|
|
|
Exercise
|
|
Range of Exercise Price
|
|
9/30/06
|
|
|
Life
|
|
|
Price
|
|
|
9/30/06
|
|
|
Price
|
|
|
$18.55-$22.26
|
|
|
1,598,641
|
|
|
|
3.3
|
|
|
$
|
21.31
|
|
|
|
1,568,641
|
|
|
$
|
21.32
|
|
$22.27-$25.97
|
|
|
4,500,219
|
|
|
|
3.5
|
|
|
$
|
23.33
|
|
|
|
4,480,718
|
|
|
$
|
23.32
|
|
$25.98-$29.68
|
|
|
2,600,394
|
|
|
|
5.3
|
|
|
$
|
27.85
|
|
|
|
2,594,394
|
|
|
$
|
27.85
|
|
$29.69-$33.39
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$33.40-$37.10
|
|
|
317,000
|
|
|
|
9.6
|
|
|
$
|
35.21
|
|
|
|
|
|
|
|
|
|
Restricted
Share Awards
Restricted stock is subject to restrictions on vesting and
transferability. Restricted stock awards entitle the
participants to full dividend and voting rights. The market
value of restricted stock on the date of the award is recorded
as compensation expense over the vesting period. Certificates
for shares of restricted stock awarded under the Companys
stock option and stock award plans are held by the Company
during the periods in which the restrictions on vesting are
effective.
85
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Transactions involving option shares for all plans are
summarized as follows:
|
|
|
|
|
|
|
|
|
|
|
Number of
|
|
|
Weighted Average
|
|
|
|
Restricted
|
|
|
Fair Value per
|
|
|
|
Share Awards
|
|
|
Award
|
|
|
Restricted Share Awards
Outstanding at September 30, 2005
|
|
|
64,928
|
|
|
$
|
24.46
|
|
Granted in 2006
|
|
|
16,000
|
|
|
$
|
34.94
|
|
Vested in 2006
|
|
|
(38,600
|
)
|
|
$
|
24.43
|
|
|
|
|
|
|
|
|
|
|
Restricted Share Awards
Outstanding at September 30, 2006
|
|
|
42,328
|
|
|
$
|
28.44
|
|
|
|
|
|
|
|
|
|
|
Vesting restrictions for the outstanding shares of non-vested
restricted stock at September 30, 2006 will lapse as
follows: 2007 25,000 shares; 2008
2,500 shares; 2009 4,500 shares;
2010 5,828 shares; and 2011
4,500 shares.
Redeemable
Preferred Stock
As of September 30, 2006, there were 10,000,000 shares
of $1 par value Preferred Stock authorized but unissued.
Long-Term
Debt
The outstanding long-term debt is as follows:
|
|
|
|
|
|
|
|
|
|
|
At September 30
|
|
|
|
2006
|
|
|
2005
|
|
|
|
(Thousands)
|
|
|
Medium-Term Notes(1):
|
|
|
|
|
|
|
|
|
6.0% to 7.50% due May 2008 to June
2025
|
|
$
|
749,000
|
|
|
$
|
749,000
|
|
Notes(1):
|
|
|
|
|
|
|
|
|
5.25% to 6.50% due March 2013 to
September 2022(2)
|
|
|
346,665
|
|
|
|
347,222
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,095,665
|
|
|
|
1,096,222
|
|
|
|
|
|
|
|
|
|
|
Other Notes:
|
|
|
|
|
|
|
|
|
Secured(3)
|
|
|
22,766
|
|
|
|
32,100
|
|
Unsecured
|
|
|
169
|
|
|
|
83
|
|
|
|
|
|
|
|
|
|
|
Total Long-Term Debt
|
|
|
1,118,600
|
|
|
|
1,128,405
|
|
Less Current Portion
|
|
|
22,925
|
|
|
|
9,393
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
1,095,675
|
|
|
$
|
1,119,012
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
These medium-term notes and notes are unsecured. |
|
(2) |
|
At September 30, 2006 and 2005, $96,665,000 and
$97,222,000, respectively, of these notes were callable at par
at any time after September 15, 2006. The change in the
amount outstanding from year to year is attributable to the
estates of individual note holders exercising put options due to
the death of an individual note holder. |
|
(3) |
|
These notes constitute project financing and are
secured by the various project documentation and natural gas
transportation contracts related to the Empire State Pipeline.
The interest rate on these notes is a variable rate based on
LIBOR. It is the Companys intention to pay off these notes
within one year. As such, the notes have been classified as
current. |
86
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
As of September 30, 2006, the aggregate principal amounts
of long-term debt maturing during the next five years and
thereafter are as follows: $22.9 million in 2007,
$200.0 million in 2008, $100.0 million in 2009, zero
in 2010, $200.0 million in 2011, and $595.7 million
thereafter.
Short-Term
Borrowings
The Company historically has obtained short-term funds either
through bank loans or the issuance of commercial paper. As for
the former, the Company maintains a number of individual
(bi-lateral) uncommitted or discretionary lines of credit with
certain financial institutions for general corporate purposes.
Borrowings under these lines of credit are made at competitive
market rates. These credit lines, which aggregate to
$445.0 million, are revocable at the option of the
financial institutions and are reviewed on an annual basis. The
Company anticipates that these lines of credit will continue to
be renewed, or replaced by similar lines. The total amount
available to be issued under the Companys commercial paper
program is $300.0 million. The commercial paper program is
backed by a syndicated committed credit facility totaling
$300.0 million, which is committed to the Company through
September 30, 2010.
At September 30, 2006 and September 30, 2005, the
Company had no outstanding short-term notes payable to banks or
commercial paper.
Debt
Restrictions
Under the Companys committed credit facility, the Company
has agreed that its debt to capitalization ratio will not exceed
.65 at the last day of any fiscal quarter from
September 30, 2005 through September 30, 2010. At
September 30, 2006, the Companys debt to
capitalization ratio (as calculated under the facility) was .44.
The constraints specified in the committed credit facility would
permit an additional $1.56 billion in short-term
and/or
long-term debt to be outstanding (further limited by the
indenture covenants discussed below) before the Companys
debt to capitalization ratio would exceed .65. If a downgrade in
any of the Companys credit ratings were to occur, access
to the commercial paper markets might not be possible. However,
the Company expects that it could borrow under its uncommitted
bank lines of credit or rely upon other liquidity sources,
including cash provided by operations.
Under the Companys existing indenture covenants, at
September 30, 2006, the Company would have been permitted
to issue up to a maximum of $1.03 billion in additional
long-term unsecured indebtedness at then current market interest
rates in addition to being able to issue new indebtedness to
replace maturing debt.
The Companys 1974 indenture pursuant to which
$399.0 million (or 36%) of the Companys long-term
debt (as of September 30, 2006) was issued contains a
cross-default provision whereby the failure by the Company to
perform certain obligations under other borrowing arrangements
could trigger an obligation to repay the debt outstanding under
the indenture. In particular, a repayment obligation could be
triggered if the Company fails (i) to pay any scheduled
principal or interest or any debt under any other indenture or
agreement or (ii) to perform any other term in any other
such indenture or agreement, and the effect of the failure
causes, or would permit the holders of the debt to cause, the
debt under such indenture or agreement to become due prior to
its stated maturity, unless cured or waived.
The Companys $300.0 million committed credit facility
also contains a cross-default provision whereby the failure by
the Company or its significant subsidiaries to make payments
under other borrowing arrangements, or the occurrence of certain
events affecting those other borrowing arrangements, could
trigger an obligation to repay any amounts outstanding under the
committed credit facility. In particular, a repayment obligation
could be triggered if (i) the Company or any of its
significant subsidiaries fails to make a payment when due of any
principal or interest on any other indebtedness aggregating
$20.0 million or more or (ii) an event occurs that
causes, or would permit the holders of any other indebtedness
aggregating $20.0 million or
87
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
more to cause, such indebtedness to become due prior to its
stated maturity. As of September 30, 2006, the Company had
no debt outstanding under the committed credit facility.
Note F
Financial Instruments
Fair
Values
The fair market value of the Companys long-term debt is
estimated based on quoted market prices of similar issues having
the same remaining maturities, redemption terms and credit
ratings. Based on these criteria, the fair market value of
long-term debt, including current portion, was as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
At September 30
|
|
|
|
2006 Carrying
|
|
|
2006 Fair
|
|
|
2005 Carrying
|
|
|
2005 Fair
|
|
|
|
Amount
|
|
|
Value
|
|
|
Amount
|
|
|
Value
|
|
|
|
(Thousands)
|
|
|
Long-Term Debt
|
|
$
|
1,118,600
|
|
|
$
|
1,148,089
|
|
|
$
|
1,128,405
|
|
|
$
|
1,181,599
|
|
The fair value amounts are not intended to reflect principal
amounts that the Company will ultimately be required to pay.
Temporary cash investments, notes payable to banks and
commercial paper are stated at cost, which approximates their
fair value due to the short-term maturities of those financial
instruments. Investments in life insurance are stated at their
cash surrender values as discussed below. Investments in an
equity mutual fund and the stock of an insurance company
(marketable equity securities), as discussed below, are stated
at fair value based on quoted market prices.
Other
Investments
Other investments includes cash surrender values of insurance
contracts and marketable equity securities. The cash surrender
values of the insurance contracts amounted to $62.5 million
and $59.6 million at September 30, 2006 and 2005,
respectively. The fair value of the equity mutual fund was
$12.9 million and $9.8 million at September 30,
2006 and September 30, 2005, respectively. The gross
unrealized gain on this equity mutual fund was $1.0 million
and $0.4 million at September 30, 2006 and
September 30, 2005, respectively. During 2005, the Company
sold all of its interest in one equity mutual fund for
$8.5 million and reinvested the proceeds in another equity
mutual fund. The Company recognized a gain of $0.7 million
on the sale of the equity mutual fund. The fair value of the
stock of an insurance company was $12.7 million and
$10.5 million at September 30, 2006 and 2005,
respectively. The gross unrealized gain on this stock was
$10.3 million and $8.1 million at September 30,
2006 and 2005, respectively. The insurance contracts and
marketable equity securities are primarily informal funding
mechanisms for various benefit obligations the Company has to
certain employees.
Derivative
Financial Instruments
The Company uses a variety of derivative financial instruments
to manage a portion of the market risk associated with the
fluctuations in the price of natural gas and crude oil. These
instruments include price swap agreements, no cost collars,
options and futures contracts.
Under the price swap agreements, the Company receives monthly
payments from (or makes payments to) other parties based upon
the difference between a fixed price and a variable price as
specified by the agreement. The variable price is either a crude
oil or natural gas price quoted on the NYMEX or a quoted natural
gas price in Inside FERC. The majority of these
derivative financial instruments are accounted for as cash flow
hedges and are used to lock in a price for the anticipated sale
of natural gas and crude oil production in the Exploration and
Production segment and the All Other category. The Energy
Marketing segment accounts for these derivative financial
instruments as fair value hedges and uses them to hedge against
falling prices, a risk to which they are
88
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
exposed on their fixed price gas purchase commitments. The
Energy Marketing segment also uses these derivative financial
instruments to hedge against rising prices, a risk to which they
are exposed on their fixed price sales commitments. At
September 30, 2006, the Company had natural gas price swap
agreements covering a notional amount of 7.4 Bcf extending
through 2009 at a weighted average fixed rate of $7.24 per
Mcf. Of this amount, 1.1 Bcf is accounted for as fair value
hedges at a weighted average fixed rate of $6.98 per Mcf.
The remaining 6.3 Bcf are accounted for as cash flow hedges
at a weighted average fixed rate of $7.29 per Mcf. At
September 30, 2006, the Company would have had to pay a net
$7.4 million to terminate the price swap agreements. The
Company also had crude oil price swap agreements covering a
notional amount of 900,000 bbls extending through 2008 at a
weighted average fixed rate of $37.13 per bbl. At
September 30, 2006, the Company would have had to pay a net
$27.6 million to terminate the price swap agreements.
Under the no cost collars, the Company receives monthly payments
from (or makes payments to) other parties when a variable price
falls below an established floor price (the Company receives
payment from the counterparty) or exceeds an established ceiling
price (the Company pays the counterparty). The variable price is
either a crude oil price quoted on the NYMEX or a quoted natural
gas price in Inside FERC. These derivative financial
instruments are accounted for as cash flow hedges and are used
to lock in a price range for the anticipated sale of natural gas
and crude oil production in the Exploration and Production
segment. At September 30, 2006, the Company had no cost
collars on natural gas covering a notional amount of
7.1 Bcf extending through 2008 with a weighted average
floor price of $8.26 per Mcf and a weighted average ceiling
price of $17.25 per Mcf. At September 30, 2006, the
Company would have received $10.4 million to terminate the
no cost collars. At September 30, 2006, the Company had no
cost collars on crude oil covering a notional amount of 180,000
bbls extending through 2007 with a weighted average floor price
of $70.00 per bbl and a weighted average ceiling price of
$77.00 per bbl. At September 30, 2006, the Company
would have received $0.9 million to terminate these no cost
collars.
At September 30, 2006, the Company had long (purchased)
futures contracts covering 14.5 Bcf of gas extending
through 2012 at a weighted average contract price of
$9.20 per Mcf. They are accounted for as fair value hedges
and are used by the Companys Energy Marketing segment to
hedge against rising prices, a risk to which this segment is
exposed due to the fixed price gas sales commitments that it
enters into with commercial and industrial customers. The
Company would have had to pay $22.4 million to terminate
these futures contracts at September 30, 2006.
At September 30, 2006, the Company had short (sold) futures
contracts covering 7.5 Bcf of gas extending through 2009 at
a weighted average contract price of $10.57 per Mcf. Of
this amount, 4.7 Bcf is accounted for as cash flow hedges
as these contracts relate to the anticipated sale of natural gas
by the Energy Marketing segment. The remaining 2.8 Bcf is
accounted for as fair value hedges. The Company would have
received $17.5 million to terminate these futures contracts
at September 30, 2006.
The Company may be exposed to credit risk on some of the
derivative financial instruments discussed above. Credit risk
relates to the risk of loss that the Company would incur as a
result of nonperformance by counterparties pursuant to the terms
of their contractual obligations. To mitigate such credit risk,
management performs a credit check, and then on an ongoing basis
monitors counterparty credit exposure. Management has obtained
guarantees from the parent companies of the respective
counterparties to its derivative financial instruments. At
September 30, 2006, the Company used six counterparties for
its over the counter derivative financial instruments. At
September 30, 2006, no individual counterparty represented
greater than 39% of total credit risk (measured as volumes
hedged by an individual counterparty as a percentage of the
Companys total volumes hedged). All of the counterparties
(or the parent of the counterparty) were rated as investment
grade entities at September 30, 2006.
The Company uses an interest rate collar to limit interest rate
fluctuations on certain variable rate debt in the Pipeline and
Storage segment. Under the interest rate collar the Company
makes quarterly payments to (or receives payments from) another
party when a variable rate falls below an established floor rate
(the Company
89
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
pays the counterparty) or exceeds an established ceiling rate
(the Company receives payment from the counterparty). Under the
terms of the collar, which extends until 2009, the variable rate
is based on LIBOR. The floor rate of the collar is 5.15% and the
ceiling rate is 9.375%. At September 30, 2006 the notional
amount on the collar was $25.7 million. The Company would
have had to pay $0.1 million to terminate the interest rate
collar at September 30, 2006.
Note G
Retirement Plan and Other Post-Retirement Benefits
The Company has a tax-qualified, noncontributory,
defined-benefit retirement plan (Retirement Plan) that covers
approximately 77% of the domestic employees of the Company. The
Company provides health care and life insurance benefits for
substantially all domestic retired employees under a
post-retirement benefit plan (Post-Retirement Plan).
The Companys policy is to fund the Retirement Plan with at
least an amount necessary to satisfy the minimum funding
requirements of applicable laws and regulations and not more
than the maximum amount deductible for federal income tax
purposes. The Company has established VEBA trusts for its
Post-Retirement Plan. Contributions to the VEBA trusts are tax
deductible, subject to limitations contained in the Internal
Revenue Code and regulations and are made to fund
employees post-retirement health care and life insurance
benefits, as well as benefits as they are paid to current
retirees. In addition, the Company has established 401(h)
accounts for its Post-Retirement Plan. They are separate
accounts within the Retirement Plan used to pay retiree medical
benefits for the associated participants in the Retirement Plan.
Contributions are tax-deductible when made and investments
accumulate tax-free. Retirement Plan and Post-Retirement Plan
assets primarily consist of equity and fixed income investments
or units in commingled funds or money market funds.
The expected returns on plan assets of the Retirement Plan and
Post-Retirement Plan are applied to the market-related value of
plan assets of the respective plans. The market-related values
of the Retirement Plan and Post-Retirement Plan assets are equal
to market value as of the measurement date.
Reconciliations of the Benefit Obligations, Plan Assets and
Funded Status, as well as the components of Net Periodic Benefit
Cost and the Weighted Average Assumptions of the Retirement Plan
and Post-Retirement Plan are shown in the tables below. The date
used to measure the Benefit Obligations, Plan Assets and Funded
Status is June 30, 2006, 2005 and 2004, respectively.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Retirement Plan
|
|
|
Other Post-Retirement Benefits
|
|
|
|
Year Ended September 30
|
|
|
Year Ended September 30
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
|
(Thousands)
|
|
|
Change in Benefit
Obligation
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Benefit Obligation at Beginning of
Period
|
|
$
|
825,204
|
|
|
$
|
693,532
|
|
|
$
|
694,960
|
|
|
$
|
546,273
|
|
|
$
|
422,003
|
|
|
$
|
467,418
|
|
Service Cost
|
|
|
16,416
|
|
|
|
13,714
|
|
|
|
14,598
|
|
|
|
8,029
|
|
|
|
6,153
|
|
|
|
6,027
|
|
Interest Cost
|
|
|
40,196
|
|
|
|
42,079
|
|
|
|
40,565
|
|
|
|
26,804
|
|
|
|
25,783
|
|
|
|
26,393
|
|
Plan Participants
Contributions
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,559
|
|
|
|
1,017
|
|
|
|
627
|
|
Actuarial (Gain) Loss
|
|
|
(108,112
|
)
|
|
|
115,128
|
|
|
|
(19,593
|
)
|
|
|
(115,052
|
)
|
|
|
110,663
|
|
|
|
(62,146
|
)
|
Benefits Paid
|
|
|
(41,497
|
)
|
|
|
(39,249
|
)
|
|
|
(36,998
|
)
|
|
|
(21,682
|
)
|
|
|
(19,346
|
)
|
|
|
(16,316
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Benefit Obligation at End of
Period
|
|
$
|
732,207
|
|
|
$
|
825,204
|
|
|
$
|
693,532
|
|
|
$
|
445,931
|
|
|
$
|
546,273
|
|
|
$
|
422,003
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
90
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Retirement Plan
|
|
|
Other Post-Retirement Benefits
|
|
|
|
Year Ended September 30
|
|
|
Year Ended September 30
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
|
(Thousands)
|
|
|
Change in Plan
Assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value of Assets at Beginning
of Period
|
|
$
|
616,462
|
|
|
$
|
573,366
|
|
|
$
|
491,333
|
|
|
$
|
271,636
|
|
|
$
|
229,485
|
|
|
$
|
166,494
|
|
Actual Return on Plan Assets
|
|
|
68,649
|
|
|
|
56,201
|
|
|
|
81,946
|
|
|
|
34,785
|
|
|
|
20,577
|
|
|
|
38,960
|
|
Employer Contribution
|
|
|
20,907
|
|
|
|
26,144
|
|
|
|
37,085
|
|
|
|
39,326
|
|
|
|
39,903
|
|
|
|
39,720
|
|
Plan Participants
Contributions
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,559
|
|
|
|
1,017
|
|
|
|
627
|
|
Benefits Paid
|
|
|
(41,497
|
)
|
|
|
(39,249
|
)
|
|
|
(36,998
|
)
|
|
|
(21,682
|
)
|
|
|
(19,346
|
)
|
|
|
(16,316
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value of Assets at End of
Period
|
|
$
|
664,521
|
|
|
$
|
616,462
|
|
|
$
|
573,366
|
|
|
$
|
325,624
|
|
|
$
|
271,636
|
|
|
$
|
229,485
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reconciliation of Funded
Status
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Funded Status
|
|
$
|
(67,686
|
)
|
|
$
|
(208,742
|
)
|
|
$
|
(120,166
|
)
|
|
$
|
(120,307
|
)
|
|
$
|
(274,637
|
)
|
|
$
|
(192,518
|
)
|
Unrecognized Net Actuarial Loss
|
|
|
107,626
|
|
|
|
257,553
|
|
|
|
159,554
|
|
|
|
54,487
|
|
|
|
205,423
|
|
|
|
108,943
|
|
Unrecognized Transition Obligation
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
49,890
|
|
|
|
57,017
|
|
|
|
64,144
|
|
Unrecognized Prior Service Cost
|
|
|
7,185
|
|
|
|
8,142
|
|
|
|
9,171
|
|
|
|
12
|
|
|
|
17
|
|
|
|
20
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Amount Recognized at End of
Period
|
|
$
|
47,125
|
|
|
$
|
56,953
|
|
|
$
|
48,559
|
|
|
$
|
(15,918
|
)
|
|
$
|
(12,180
|
)
|
|
$
|
(19,411
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amounts Recognized in the
Balance Sheets Consist of:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accrued Benefit Liability
|
|
$
|
|
|
|
$
|
(117,103
|
)
|
|
$
|
(43,147
|
)
|
|
$
|
(32,918
|
)
|
|
$
|
(26,584
|
)
|
|
$
|
(27,263
|
)
|
Prepaid Benefit Cost
|
|
|
47,125
|
|
|
|
|
|
|
|
|
|
|
|
17,000
|
|
|
|
14,404
|
|
|
|
7,852
|
|
Intangible Assets
|
|
|
|
|
|
|
8,142
|
|
|
|
9,171
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated Other Comprehensive
Loss (Pre-Tax)
|
|
|
|
|
|
|
165,914
|
|
|
|
82,535
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Amount Recognized at End of
Period
|
|
$
|
47,125
|
|
|
$
|
56,953
|
|
|
$
|
48,559
|
|
|
$
|
(15,918
|
)
|
|
$
|
(12,180
|
)
|
|
$
|
(19,411
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted Average Assumptions
Used to Determine Benefit Obligation at
September 30
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Discount Rate
|
|
|
6.25
|
%
|
|
|
5.00
|
%
|
|
|
6.25
|
%
|
|
|
6.25
|
%
|
|
|
5.00
|
%
|
|
|
6.25
|
%*
|
Expected Return on Plan Assets
|
|
|
8.25
|
%
|
|
|
8.25
|
%
|
|
|
8.25
|
%
|
|
|
8.25
|
%
|
|
|
8.25
|
%
|
|
|
8.25
|
%
|
Rate of Compensation Increase
|
|
|
5.00
|
%
|
|
|
5.00
|
%
|
|
|
5.00
|
%
|
|
|
5.00
|
%
|
|
|
5.00
|
%
|
|
|
5.00
|
%
|
Components of Net Periodic
Benefit Cost
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Service Cost
|
|
$
|
16,416
|
|
|
$
|
13,714
|
|
|
$
|
14,598
|
|
|
$
|
8,029
|
|
|
$
|
6,153
|
|
|
$
|
6,027
|
|
Interest Cost
|
|
|
40,196
|
|
|
|
42,079
|
|
|
|
40,565
|
|
|
|
26,804
|
|
|
|
25,783
|
|
|
|
26,393
|
|
Expected Return on Plan Assets
|
|
|
(49,943
|
)
|
|
|
(49,545
|
)
|
|
|
(48,281
|
)
|
|
|
(22,302
|
)
|
|
|
(18,862
|
)
|
|
|
(14,898
|
)
|
Amortization of Prior Service Cost
|
|
|
957
|
|
|
|
1,029
|
|
|
|
1,103
|
|
|
|
4
|
|
|
|
4
|
|
|
|
4
|
|
Amortization of Transition Amount
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
7,127
|
|
|
|
7,127
|
|
|
|
7,127
|
|
Recognition of Actuarial Loss
|
|
|
23,108
|
|
|
|
10,473
|
|
|
|
9,438
|
|
|
|
23,402
|
|
|
|
12,467
|
|
|
|
17,092
|
|
Net Amortization and Deferral for
Regulatory Purposes
|
|
|
(6,409
|
)
|
|
|
1,988
|
|
|
|
722
|
|
|
|
(11,084
|
)
|
|
|
(410
|
)
|
|
|
(9,731
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Periodic Benefit Cost
|
|
$
|
24,325
|
|
|
$
|
19,738
|
|
|
$
|
18,145
|
|
|
$
|
31,980
|
|
|
$
|
32,262
|
|
|
$
|
32,014
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Comprehensive (Income) Loss
(Pre-Tax) Attributable to Change In Additional Minimum Liability
Recognition
|
|
$
|
(165,914
|
)
|
|
$
|
83,379
|
|
|
$
|
(56,612
|
)
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
91
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Retirement Plan
|
|
|
Other Post-Retirement Benefits
|
|
|
|
Year Ended September 30
|
|
|
Year Ended September 30
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
|
(Thousands)
|
|
|
Weighted Average Assumptions
Used to Determine Net Periodic Benefit Cost at
September 30
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Discount Rate
|
|
|
5.00
|
%
|
|
|
6.25
|
%
|
|
|
6.00
|
%
|
|
|
5.00
|
%
|
|
|
6.25
|
%
|
|
|
6.25
|
%*
|
Expected Return on Plan Assets
|
|
|
8.25
|
%
|
|
|
8.25
|
%
|
|
|
8.25
|
%
|
|
|
8.25
|
%
|
|
|
8.25
|
%
|
|
|
8.25
|
%
|
Rate of Compensation Increase
|
|
|
5.00
|
%
|
|
|
5.00
|
%
|
|
|
5.00
|
%
|
|
|
5.00
|
%
|
|
|
5.00
|
%
|
|
|
5.00
|
%
|
|
|
|
* |
|
The weighted average discount rate was 6.0% through 12/8/2003.
Subsequent to 12/8/2003, the discount rate used was 6.25%. |
The Net Periodic Benefit cost in the table above includes the
effects of regulation. The Company recovers pension and
post-retirement benefit costs in its Utility and Pipeline and
Storage segments in accordance with the applicable regulatory
commission authorizations. Certain of those commission
authorizations established tracking mechanisms which allow the
Company to record the difference between the amount of pension
and post-retirement benefit costs recoverable in rates and the
amounts of such costs as determined under SFAS 87 and
SFAS 106 as either a regulatory asset or liability, as
appropriate. Any activity under the tracking mechanisms
(including the amortization of pension and post-retirement
regulatory assets) is reflected in the Net Amortization and
Deferral for Regulatory Purposes line item above.
In accordance with the provisions of SFAS 87, the Company
recorded an additional minimum pension liability at
September 30, 2005 and 2004 representing the excess of the
accumulated benefit obligation over the fair value of plan
assets plus accrued amounts previously recorded. An intangible
asset, as shown in the table above, offset the additional
liability to the extent of previously Unrecognized Prior Service
Cost. The amount in excess of Unrecognized Prior Service Cost
was recorded net of the related tax benefit as accumulated other
comprehensive loss. At September 30, 2006, the Company
reversed the additional minimum pension liability, intangible
asset and accumulated other comprehensive loss recorded in prior
years since the fair value of the plan assets exceeded the
accumulated benefit obligation at September 30, 2006. The
pre-tax amounts of the change in accumulated other comprehensive
(income) loss at September 30, 2006, 2005 and 2004 are
shown in the table above. The projected benefit obligation,
accumulated benefit obligation and fair value of assets for the
retirement plan were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
Projected Benefit Obligation
|
|
$
|
732,207
|
|
|
$
|
825,204
|
|
|
$
|
693,532
|
|
Accumulated Benefit Obligation
|
|
$
|
660,026
|
|
|
$
|
733,565
|
|
|
$
|
616,513
|
|
Fair Value of Plan Assets
|
|
$
|
664,520
|
|
|
$
|
616,462
|
|
|
$
|
573,366
|
|
The effect of the discount rate change for the Retirement Plan
in 2006 was to decrease the projected benefit obligation of the
Retirement Plan by $113.1 million. The effect of the
discount rate change for the Retirement Plan in 2005 was to
increase the projected benefit obligation by
$113.0 million. The discount rate change for the Retirement
Plan in 2004 caused the projected benefit obligation to decrease
by $20.2 million.
The Company made cash contributions totaling $20.9 million
to the Retirement Plan during the year ended September 30,
2006. The Company expects that the annual contribution to the
Retirement Plan in 2007 will be in the range of
$15.0 million to $20.0 million. The following benefit
payments, which reflect expected future service, are expected to
be paid during the next five years and the five years
thereafter: $45.2 million in 2007; $46.1 million in
2008; $47.3 million in 2009; $48.7 million in 2010;
$50.0 million in 2011; and $275.6 million in the five
years thereafter.
92
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The Retirement Plan covers certain domestic employees hired
before July 1, 2003. Employees hired after June 30,
2003 are eligible for a Retirement Savings Account benefit
provided under the Companys defined contribution
Tax-Deferred Savings Plans. Costs associated with the Retirement
Savings Account benefit have been $0.2 million through
September 30, 2006 (with $0.1 million of costs
occurring in fiscal 2006). Costs associated with the
Companys contributions to the Tax-Deferred Savings Plans
were $4.1 million, $4.2 million, and $4.2 million
for the years ended September 30, 2006, 2005 and 2004,
respectively.
In addition to the Retirement Plan discussed above, the Company
also has a Non Qualified benefit plan that covers a group of
management employees designated by the Chief Executive Officer
of the Company. This plan provides for defined benefit payments
upon retirement of the management employee, or to the spouse
upon death of the management employee. The net periodic benefit
cost associated with this plan was $5.4 million,
$4.3 million and $13.7 million in 2006, 2005 and 2004,
respectively. The accumulated benefit obligation for this plan
was $26.5 million and $25.2 million at
September 30, 2006 and 2005, respectively. The projected
benefit obligation for the plan was $44.5 million and
$47.6 million at September 30, 2006 and 2005,
respectively. The actuarial valuations for this plan were
determined based on a discount rate of 6.25%, 5.0% and 6.25% as
of September 30, 2006, 2005 and 2004, respectively; a rate
of compensation increase of 10.0% as of September 30, 2006,
2005 and 2004; and an expected long-term rate of return on plan
assets of 8.25% at September 30, 2006, 2005 and 2004.
In January 2004, a participant of the Non Qualified benefit plan
received a $23 million lump sum payment under a provision
of an agreement previously entered into between the Company and
the participant. Under GAAP, this payment was considered a
partial settlement of the projected benefit obligation of the
plan. Accordingly, GAAP required that a pro rata portion of this
plans unrecognized actuarial loses resulting from
experience different from that assumed and from changes in
assumption be currently recognized. Therefore, $9.9 million
before tax ($6.4 million, after tax) was recognized as a
settlement expense (included in Operation and Maintenance
Expense) on the income statement.
The effect of the discount rate change in 2006 was to decrease
the other post-retirement benefit obligation by
$77.5 million. Effective July 1, 2006, the Medicare
Part B reimbursement trend, prescription drug trend and
medical trend assumptions were changed. The effect of these
assumption changes was to decrease the other post-retirement
benefit obligation by $1.7 million. A change in the
disability assumption decreased the other post-retirement
benefit obligation by $1.4 million. Other actuarial
experience decreased the other post-retirement benefit
obligation in 2006 by $34.4 million.
The effect of the discount rate change in 2005 was to increase
the other post-retirement benefit obligation by
$78.2 million. Effective July 1, 2005, the Medicare
Part B reimbursement trend, prescription drug trend and
medical trend assumptions were changed. The effect of these
assumption changes was to increase the other post-retirement
benefit obligation by $21.7 million. Also effective
July 1, 2005, the percent of active female participants who
are assumed to be married at retirement was changed. The effect
of this assumption change was to decrease the other
post-retirement benefit obligation by $6.9 million. Other
actuarial experience increased the other post-retirement benefit
obligation in 2005 by $17.9 million.
On December 8, 2003, the Medicare Prescription Drug,
Improvement, and Modernization Act of 2003 (the Act) was signed
into law. This 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. In accordance with FASB Staff Position
FAS 106-2,
Accounting and Disclosure Requirements Related to the
Medicare Prescription Drug, Improvement and Modernization Act of
2003, since the Company is assumed to continue to provide
a prescription drug benefit to retirees in the point of service
and indemnity plans that is at least actuarially equivalent to
Medicare Part D, the impact of the Act was reflected as of
December 8, 2003. The discount rate was changed from 6.0%
to 6.25% per annum as of the remeasurement date, which
resulted in a decrease in the benefit obligation of
$15.9 million in 2004. The other post-retirement benefit
obligation decreased by $42.9 million and the Net Periodic
Post-Retirement Benefit Cost
93
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
decreased by $4.2 million as a result of the Act for 2004.
Effective July 1, 2004, the Medicare B Reimbursement trend
assumption was changed. The effect of this change was to
decrease the other post-retirement benefit obligation by
$3.5 million for 2004.
The estimated gross benefit payments and gross amount of subsidy
receipts are as follows:
|
|
|
|
|
|
|
|
|
|
|
Benefit Payments
|
|
|
Subsidy Receipts
|
|
|
First Year
|
|
$
|
22,994,788
|
|
|
$
|
(1,475,584
|
)
|
Second Year
|
|
$
|
24,993,192
|
|
|
$
|
(1,712,545
|
)
|
Third Year
|
|
$
|
26,857,371
|
|
|
$
|
(1,959,704
|
)
|
Fourth Year
|
|
$
|
28,913,929
|
|
|
$
|
(2,191,014
|
)
|
Fifth Year
|
|
$
|
30,877,647
|
|
|
$
|
(2,413,305
|
)
|
Next Five Years
|
|
$
|
175,465,690
|
|
|
$
|
(15,964,373
|
)
|
The annual rate of increase in the per capita cost of covered
medical care benefits for both Pre and Post age 65
participants was assumed to be 10.0% for 2004. In 2005, the
Company began making separate estimates of the annual rate of
increase in the per capita cost of covered medical care benefits
for Pre and Post age 65 participants. The rate of increase
for Pre age 65 participants was assumed to be 10% while the
rate of increase for Post age 65 participants was assumed
to be 7.5%. In 2006, the rate of increase for Pre age 65
participants was 9% and was assumed to gradually decline to 5.0%
by the year 2014. The rate of increase for the Post age 65
participants was 7.0% and was assumed to gradually decline to
5.0% by the year 2014. The annual rate of increase in the per
capita cost of covered prescription drug benefits was assumed to
be 12.0% for 2004, 12.5% for 2005, 11.0% for 2006, and gradually
decline to 5.0% by the year 2014 and remain level thereafter.
The annual rate of increase in the per capita Medicare
Part B Reimbursement was assumed to be 9.25% for 2004, 6.0%
for 2005, and 5.25% for 2006. The annual rate of increase for
the Medicare Part B Reimbursement is expected to fluctuate
between 0% and 5.0% over the next 10 years and reach 5.0%
by 2016.
The health care cost trend rate assumptions used to calculate
the per capita cost of covered medical care benefits have a
significant effect on the amounts reported. If the health care
cost trend rates were increased by 1% in each year, the Other
Post-Retirement Benefit Obligation as of October 1, 2006
would be increased by $57.3 million. This 1% change would
also have increased the aggregate of the service and interest
cost components of net periodic post-retirement benefit cost for
2006 by $6.1 million. If the health care cost trend rates
were decreased by 1% in each year, the Other Post-Retirement
Benefit Obligation as of October 1, 2006 would be decreased
by $47.5 million. This 1% change would also have decreased
the aggregate of the service and interest cost components of net
periodic post-retirement benefit cost for 2006 by
$4.9 million.
The Company made cash contributions including payments made
directly to participants totaling $39.3 million to the
Post-Retirement Plan during the year ended September 30,
2006. The Company expects that the annual contribution to the
Post-Retirement Plan in 2006 will be in the range of
$35.0 million to $45.0 million.
The Companys Retirement Plan weighted average asset
allocations at September 30, 2006, 2005 and 2004 by asset
category are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Percentage of Plan
|
|
|
|
Target Allocation
|
|
|
Assets at September 30
|
|
Asset Category
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
Equity Securities
|
|
|
60-75
|
%
|
|
|
67
|
%
|
|
|
63
|
%
|
|
|
61
|
%
|
Fixed Income Securities
|
|
|
20-35
|
%
|
|
|
26
|
%
|
|
|
28
|
%
|
|
|
28
|
%
|
Other
|
|
|
0-15
|
%
|
|
|
7
|
%
|
|
|
9
|
%
|
|
|
11
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
|
|
|
100
|
%
|
|
|
100
|
%
|
|
|
100
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
94
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The Companys Post-Retirement Plan weighted average asset
allocations at September 30, 2006, 2005 and 2004 by asset
category are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Percentage of Plan
|
|
|
|
Target Allocation
|
|
|
Assets at September 30
|
|
Asset Category
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
Equity Securities
|
|
|
85-100
|
%
|
|
|
93
|
%
|
|
|
92
|
%
|
|
|
91
|
%
|
Fixed Income Securities
|
|
|
0-15
|
%
|
|
|
1
|
%
|
|
|
2
|
%
|
|
|
1
|
%
|
Other
|
|
|
0-15
|
%
|
|
|
6
|
%
|
|
|
6
|
%
|
|
|
8
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
|
|
|
100
|
%
|
|
|
100
|
%
|
|
|
100
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The Companys assumption regarding the expected long-term
rate of return on plan assets is 8.25%. The return assumption
reflects the anticipated long-term rate of return on the
plans current and future assets. The Company utilizes
historical investment data, projected capital market conditions,
and the plans target asset class and investment manager
allocations to set the assumption regarding the expected return
on plan assets.
The long-term investment objective of the Retirement Plan trust
and the Post-Retirement Plan VEBA trusts is to achieve the
target total return in accordance with the Companys risk
tolerance. Assets are diversified utilizing a mix of equities,
fixed income and other securities (including real estate). Risk
tolerance is established through consideration of plan
liabilities, plan funded status and corporate financial
condition.
Investment managers are retained to manage separate pools of
assets. Comparative market and peer group performance of
individual managers and the total fund are monitored on a
regular basis, and reviewed by the Companys Retirement
Committee on at least a quarterly basis.
The discount rate which is used to present value the future
benefit payment obligations of the Retirement Plan, the
Non-Qualified benefit plan, and the Post-Retirement Plan is
6.25% as of September 30, 2006. This rate is equal to the
Moodys Aa Long-Term Corporate Bond index, rounded to the
nearest 25 basis points. The duration of the securities
underlying that index (approximately 13 years) reasonably
matches the expected timing of anticipated future benefit
payments (approximately 12 years).
Note H
Commitments and Contingencies
Environmental
Matters
The Company is subject to various federal, state and local laws
and regulations relating to the protection of the environment.
The Company has established procedures for the ongoing
evaluation of its operations, to identify potential
environmental exposures and to comply with regulatory policies
and procedures.
It is the Companys policy to accrue estimated
environmental
clean-up
costs (investigation and remediation) when such amounts can
reasonably be estimated and it is probable that the Company will
be required to incur such costs. The Company has estimated its
remaining
clean-up
costs related to the sites described below in
paragraphs (i) and (ii) will be
$3.8 million. This liability has been recorded on the
Consolidated Balance Sheet at September 30, 2006. The
Company expects to recover its environmental
clean-up
costs from a combination of rate recovery and insurance proceeds
(refer to Note C Regulatory Matters for further
discussion of the insurance proceeds). Other than as discussed
below, the Company is currently not aware of any material
exposure to environmental liabilities. However, adverse changes
in environmental regulations, new information or other factors
could impact the Company.
(i) Former
Manufactured Gas Plant Sites
The Company has incurred or is incurring
clean-up
costs at five former manufactured gas plant sites in New York
and Pennsylvania. The Company continues to be responsible for
future ongoing maintenance at one
95
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
site. At a second site in New York, the Company settled its
environmental obligations related to this site during 2005. No
future liability is anticipated at this site. At a third site,
remediation is complete and long-term maintenance and monitoring
activities are ongoing. A fourth site, which allegedly contains,
among other things, manufactured gas plant waste, is in the
investigation stage. Remediation and post-remedial construction
care and maintenance have been completed at a fifth site, and
the Company has been released from any future liability related
to this site by the Pennsylvania Department of Environmental
Protection.
(ii) Third
Party Waste Disposal Sites
The Company has been identified by the Department of
Environmental Conservation (DEC) or the United States
Environmental Protection Agency as one of a number of companies
considered to be PRPs with respect to two waste disposal sites
in New York which were operated by unrelated third parties. The
PRPs are alleged to have contributed to the materials that may
have been collected at such waste disposal sites by the site
operators. The ultimate cost to the Company with respect to the
remediation of these sites will depend on such factors as the
remediation plan selected, the extent of site contamination, the
number of additional PRPs at each site and the portion of
responsibility, if any, attributed to the Company. The
remediation has been completed at one site, with costs subject
to an ongoing final reallocation process among five PRPs. At a
second waste disposal site, settlement was reached in the amount
of $9.3 million to be allocated among five PRPs. The
allocation process is currently being determined. Further
negotiations remain in process for additional settlements
related to this site.
(iii) Other
The Company received, in 1998 and again in October 1999, notice
that the DEC believes the Company is responsible for
contamination discovered at an additional former manufactured
gas plant site in New York. The Company, however, has not been
named as a PRP. The Company responded to these notices that
other companies operated that site before its predecessor did,
that liability could be imposed upon it only if hazardous
substances were disposed at the site during a period when the
site was operated by its predecessor, and that it was unaware of
any such disposal. The Company has not incurred any
clean-up
costs at this site nor has it been able to reasonably estimate
the probability or extent of potential liability.
Other
The Company, in its Utility segment, Energy Marketing segment,
and All Other category, has entered into contractual commitments
in the ordinary course of business, including commitments to
purchase gas, transportation, and storage service to meet
customer gas supply needs. Substantially all of these contracts
expire within the next five years. The future gas purchase,
transportation and storage contract commitments during the next
five years and thereafter are as follows: $793.5 million in
2007, $195.2 million in 2008, $48.9 million in 2009,
$17.6 million in 2010, $9.9 million in 2011, and
$68.8 million thereafter. In the Utility segment, these
costs are subject to state commission review, and are being
recovered in customer rates. Management believes that, to the
extent any stranded pipeline costs are generated by the
unbundling of services in the Utility segments service
territory, such costs will be recoverable from customers.
The Company has entered into leases for the use of buildings,
vehicles, construction tools, meters, computer equipment and
other items. These leases are accounted for as operating leases.
The future lease commitments during the next five years and
thereafter are as follows: $8.1 million in 2007,
$7.2 million in 2008, $6.0 million in 2009,
$4.3 million in 2010, $2.7 million in 2011, and
$15.7 million thereafter.
The Company is involved in litigation arising in the normal
course of business. In addition to the regulatory matters
discussed in Note C Regulatory Matters, the
Company is involved in other regulatory matters arising in the
normal course of business that involve rate base, cost of
service and purchased gas cost issues. While these normal-course
matters could have a material effect on earnings and cash flows
in the period in which they are
96
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
resolved, they are not expected to change materially the
Companys present liquidity position, nor to have a
material adverse effect on the financial condition of the
Company.
Note I
Discontinued Operations
On July 18, 2005, the Company completed the sale of its
entire 85.16% interest in U.E., a district heating and electric
generation business in the Bohemia region of the Czech Republic,
to Czech Energy Holdings, a.s. for sales proceeds of
approximately $116.3 million. The sale resulted in the
recognition of a gain of approximately $25.8 million, net
of tax, at September 30, 2005. Market conditions during
2005, including the increasing value of the Czech currency as
compared to the U.S. dollar, caused the value of the assets
of U.E. to increase, providing an opportunity to sell the U.E.
operations at a profit for the Company. As a result of the
decision to sell its majority interest in U.E., the Company
began presenting the Czech Republic operations, which are
primarily comprised of U.E., as discontinued operations in June
2005. U.E. was the major component of the Companys
International segment. With this change in presentation, the
Company discontinued all reporting for an International segment.
The following is selected financial information of the
discontinued operations for U.E.:
|
|
|
|
|
|
|
|
|
|
|
Year Ended September 30
|
|
|
|
2005
|
|
|
2004
|
|
|
|
(Thousands)
|
|
|
Operating Revenues
|
|
$
|
124,840
|
|
|
$
|
123,425
|
|
Operating Expenses
|
|
|
103,155
|
|
|
|
112,178
|
|
|
|
|
|
|
|
|
|
|
Operating Income
|
|
|
21,685
|
|
|
|
11,247
|
|
|
|
|
|
|
|
|
|
|
Other Income
|
|
|
2,048
|
|
|
|
1,992
|
|
Interest Expense
|
|
|
(558
|
)
|
|
|
(838
|
)
|
|
|
|
|
|
|
|
|
|
Income before Income Taxes and
Minority Interest
|
|
|
23,175
|
|
|
|
12,401
|
|
|
|
|
|
|
|
|
|
|
Income Tax Expense
|
|
|
10,331
|
|
|
|
(1,853
|
)
|
Minority Interest, Net of Taxes
|
|
|
2,645
|
|
|
|
1,933
|
|
|
|
|
|
|
|
|
|
|
Income from Discontinued Operations
|
|
|
10,199
|
|
|
|
12,321
|
|
|
|
|
|
|
|
|
|
|
Gain on Disposal, Net of Taxes of
$1,612
|
|
|
25,774
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from Discontinued Operations
|
|
$
|
35,973
|
|
|
$
|
12,321
|
|
Note J
Business Segment Information
The Company has five reportable segments: Utility, Pipeline and
Storage, Exploration and Production, Energy Marketing, and
Timber. The breakdown of the Companys operations into
reportable segments is based upon a combination of factors
including differences in products and services, regulatory
environment and geographic factors.
The Utility segment operations are regulated by the NYPSC and
the PaPUC and are carried out by Distribution Corporation.
Distribution Corporation sells natural gas to retail customers
and provides natural gas transportation services in western New
York and northwestern Pennsylvania.
The Pipeline and Storage segment operations are regulated. The
FERC regulates the operations of Supply Corporation and the
NYPSC regulates the operations of Empire. Supply Corporation
transports and stores natural gas for utilities (including
Distribution Corporation), natural gas marketers (including NFR)
and pipeline companies in the northeastern United States
markets. Empire transports natural gas from the United
States/Canadian border near Buffalo, New York into Central New
York just north of Syracuse, New York. Empire
97
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
transports gas to major industrial companies, utilities
(including Distribution Corporation) and power producers.
The Exploration and Production segment, through Seneca, is
engaged in exploration for, and development and purchase of,
natural gas and oil reserves in California, in the Appalachian
region of the United States, in the Gulf Coast region of Texas,
Louisiana and Alabama and in the provinces of Alberta,
Saskatchewan and British Columbia in Canada. Senecas
production is, for the most part, sold to purchasers located in
the vicinity of its wells. On September 30, 2003, Seneca
sold its southeast Saskatchewan oil and gas properties for a
loss of $58.5 million. Proved reserves associated with the
properties sold were 19.4 million barrels of oil and
0.3 Bcf of natural gas. When the transaction closed, the
initial proceeds received were subject to an adjustment based on
working capital and the resolution of certain income tax
matters. In 2004, those items were resolved with the buyer and,
as a result, the Company received an additional
$4.6 million of sales proceeds, as shown in the table below
for the year ended September 30, 2004.
The Energy Marketing segment is comprised of NFRs
operations. NFR markets natural gas to industrial, commercial,
public authority and residential end-users in western and
central New York and northwestern Pennsylvania, offering
competitively priced energy and energy management services for
its customers.
The Timber segments operations are carried out by the
Northeast division of Seneca and by Highland. This segment has
timber holdings (primarily high quality hardwoods) in the
northeastern United States and sawmills and kilns in
Pennsylvania. On August 1, 2003, the Company sold
approximately 70,000 acres of timber property in
Pennsylvania and New York. A gain of $168.8 million was
recognized on the sale of this timber property. During 2004, the
Company received final timber cruise information of the
properties it sold and, based on that information, determined
that property records pertaining to $1.3 million of timber
property were not properly shown as having been transferred to
the purchaser. As a result, the Company removed those assets
from its property records and adjusted the previously recognized
gain downward by recognizing a pretax loss of $1.3 million,
as shown in the table for the year ended September 30, 2004.
The data presented in the tables below reflect the reportable
segments and reconciliations to consolidated amounts. The
accounting policies of the segments are the same as those
described in Note A Summary of Significant
Accounting Policies. Sales of products or services between
segments are billed at regulated rates or at market rates, as
applicable. The Company evaluates segment performance based on
income before discontinued operations, extraordinary items and
cumulative effects of changes in accounting (when applicable).
When these items are not applicable, the Company evaluates
performance based on net income.
As disclosed in Note I Discontinued Operations,
the Company completed the sale of its majority interest in U.E.,
a district heating and electric generation business in the Czech
Republic, on July 18, 2005. As a result of the sale of its
majority interest in U.E., the Company discontinued all
reporting for an International segment and previous period
segment information has been restated to reflect this change.
All Czech Republic operations have been reported as discontinued
operations. Any remaining international activity has been
included in corporate operations.
98
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended September 30, 2006
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Corporate
|
|
|
|
|
|
|
|
|
|
Pipeline
|
|
|
Exploration
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
|
|
and
|
|
|
|
|
|
|
|
|
|
and
|
|
|
and
|
|
|
Energy
|
|
|
|
|
|
Reportable
|
|
|
All
|
|
|
Intersegment
|
|
|
Total
|
|
|
|
Utility
|
|
|
Storage
|
|
|
Production
|
|
|
Marketing
|
|
|
Timber
|
|
|
Segments
|
|
|
Other
|
|
|
Eliminations
|
|
|
Consolidated
|
|
|
|
(Thousands)
|
|
|
Revenue from External Customers
|
|
$
|
1,265,695
|
|
|
$
|
132,921
|
|
|
$
|
346,880
|
|
|
$
|
497,069
|
|
|
$
|
65,024
|
|
|
$
|
2,307,589
|
|
|
$
|
3,304
|
|
|
$
|
766
|
|
|
$
|
2,311,659
|
|
Intersegment Revenues
|
|
$
|
15,068
|
|
|
$
|
81,431
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
5
|
|
|
$
|
96,504
|
|
|
$
|
9,444
|
|
|
$
|
(105,948
|
)
|
|
$
|
|
|
Interest Income
|
|
$
|
4,889
|
|
|
$
|
454
|
|
|
$
|
8,682
|
|
|
$
|
445
|
|
|
$
|
747
|
|
|
$
|
15,217
|
|
|
$
|
22
|
|
|
$
|
(4,964
|
)
|
|
$
|
10,275
|
|
Interest Expense
|
|
$
|
26,174
|
|
|
$
|
6,620
|
|
|
$
|
50,457
|
|
|
$
|
227
|
|
|
$
|
3,095
|
|
|
$
|
86,573
|
|
|
$
|
2,555
|
|
|
$
|
(10,547
|
)
|
|
$
|
78,581
|
|
Depreciation, Depletion and
Amortization
|
|
$
|
40,172
|
|
|
$
|
36,876
|
|
|
$
|
94,738
|
|
|
$
|
53
|
|
|
$
|
6,495
|
|
|
$
|
178,334
|
|
|
$
|
789
|
|
|
$
|
492
|
|
|
$
|
179,615
|
|
Income Tax Expense (Benefit)
|
|
$
|
35,699
|
|
|
$
|
33,896
|
|
|
$
|
(2,808
|
)
|
|
$
|
3,748
|
|
|
$
|
3,277
|
|
|
$
|
73,812
|
|
|
$
|
969
|
|
|
$
|
1,305
|
|
|
$
|
76,086
|
|
Income from Unconsolidated
Subsidiaries
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
3,583
|
|
|
$
|
|
|
|
$
|
3,583
|
|
Significant Non-Cash Item:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Impairment of Oil and Gas Producing
Properties
|
|
$
|
|
|
|
$
|
|
|
|
$
|
104,739
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
104,739
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
104,739
|
|
Segment Profit (Loss): Net Income
(Loss)
|
|
$
|
49,815
|
|
|
$
|
55,633
|
|
|
$
|
20,971
|
|
|
$
|
5,798
|
|
|
$
|
5,704
|
|
|
$
|
137,921
|
|
|
$
|
359
|
|
|
$
|
(189
|
)
|
|
$
|
138,091
|
|
Expenditures for Additions to
Long-Lived Assets
|
|
$
|
54,414
|
|
|
$
|
26,023
|
|
|
$
|
208,303
|
|
|
$
|
16
|
|
|
$
|
2,323
|
|
|
$
|
291,079
|
|
|
$
|
85
|
|
|
$
|
2,995
|
|
|
$
|
294,159
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
At September 30, 2006
|
|
|
|
(Thousands)
|
|
|
Segment Assets
|
|
$
|
1,471,422
|
|
|
$
|
767,889
|
|
|
$
|
1,209,969
|
|
|
$
|
78,977
|
|
|
$
|
159,421
|
|
|
$
|
3,687,678
|
|
|
$
|
64,287
|
|
|
$
|
(17,634
|
)
|
|
$
|
3,734,331
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended September 30, 2005
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Corporate
|
|
|
|
|
|
|
|
|
|
Pipeline
|
|
|
Exploration
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
|
|
and
|
|
|
|
|
|
|
|
|
|
and
|
|
|
and
|
|
|
Energy
|
|
|
|
|
|
Reportable
|
|
|
All
|
|
|
Intersegment
|
|
|
Total
|
|
|
|
Utility
|
|
|
Storage
|
|
|
Production
|
|
|
Marketing
|
|
|
Timber
|
|
|
Segments
|
|
|
Other
|
|
|
Eliminations
|
|
|
Consolidated
|
|
|
|
(Thousands)
|
|
|
Revenue from External Customers
|
|
$
|
1,101,572
|
|
|
$
|
132,805
|
|
|
$
|
293,425
|
|
|
$
|
329,714
|
|
|
$
|
61,285
|
|
|
$
|
1,918,801
|
|
|
$
|
4,748
|
|
|
$
|
|
|
|
$
|
1,923,549
|
|
Intersegment Revenues
|
|
$
|
15,495
|
|
|
$
|
83,054
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
1
|
|
|
$
|
98,550
|
|
|
$
|
8,606
|
|
|
$
|
(107,156
|
)
|
|
$
|
|
|
Interest Income
|
|
$
|
4,111
|
|
|
$
|
76
|
|
|
$
|
4,661
|
|
|
$
|
783
|
|
|
$
|
438
|
|
|
$
|
10,069
|
|
|
$
|
19
|
|
|
$
|
(3,592
|
)
|
|
$
|
6,496
|
|
Interest Expense
|
|
$
|
22,900
|
|
|
$
|
7,128
|
|
|
$
|
48,856
|
|
|
$
|
11
|
|
|
$
|
2,764
|
|
|
$
|
81,659
|
|
|
$
|
1,726
|
|
|
$
|
(1,072
|
)
|
|
$
|
82,313
|
|
Depreciation, Depletion and
Amortization
|
|
$
|
40,159
|
|
|
$
|
38,050
|
|
|
$
|
90,912
|
|
|
$
|
41
|
|
|
$
|
6,601
|
|
|
$
|
175,763
|
|
|
$
|
3,537
|
|
|
$
|
467
|
|
|
$
|
179,767
|
|
Income Tax Expense (Benefit)
|
|
$
|
23,102
|
|
|
$
|
39,068
|
|
|
$
|
28,353
|
|
|
$
|
3,210
|
|
|
$
|
2,271
|
|
|
$
|
96,004
|
|
|
$
|
(1,425
|
)
|
|
$
|
(1,601
|
)
|
|
$
|
92,978
|
|
Income from Unconsolidated
Subsidiaries
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
3,362
|
|
|
$
|
|
|
|
$
|
3,362
|
|
Significant Non-Cash Item:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Impairment of Investment in
Partnership
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
(4,158
|
)(1)
|
|
$
|
|
|
|
$
|
(4,158
|
)
|
Segment Profit (Loss): Income
(Loss) from Continuing Operations
|
|
$
|
39,197
|
|
|
$
|
60,454
|
|
|
$
|
50,659
|
|
|
$
|
5,077
|
|
|
$
|
5,032
|
|
|
$
|
160,419
|
|
|
$
|
(2,616
|
)
|
|
$
|
(4,288
|
)
|
|
$
|
153,515
|
|
Expenditures for Additions to
Long-Lived Assets from Continuing Operations
|
|
$
|
50,071
|
|
|
$
|
21,099
|
|
|
$
|
122,450
|
|
|
$
|
58
|
|
|
$
|
18,894
|
|
|
$
|
212,572
|
|
|
$
|
463
|
|
|
$
|
618
|
|
|
$
|
213,653
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
At September 30, 2005
|
|
|
|
(Thousands)
|
|
|
Segment Assets
|
|
$
|
1,401,128
|
|
|
$
|
782,546
|
|
|
$
|
1,213,525
|
|
|
$
|
90,468
|
|
|
$
|
162,052
|
|
|
$
|
3,649,719
|
|
|
$
|
73,354
|
|
|
$
|
2,209
|
|
|
$
|
3,725,282
|
|
99
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
(1) |
|
Amount represents the impairment in the value of the
Companys 50% investment in ESNE, a partnership that owns
an 80-megawatt, combined cycle, natural gas-fired power plant in
the town of North East, Pennsylvania. |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended September 30, 2004
|
|
|
|
|
|
|
Pipeline
|
|
|
Exploration
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
|
|
Corporate and
|
|
|
|
|
|
|
|
|
|
and
|
|
|
and
|
|
|
Energy
|
|
|
|
|
|
Reportable
|
|
|
All
|
|
|
Intersegment
|
|
|
Total
|
|
|
|
Utility
|
|
|
Storage
|
|
|
Production
|
|
|
Marketing
|
|
|
Timber
|
|
|
Segments
|
|
|
Other
|
|
|
Eliminations
|
|
|
Consolidated
|
|
|
|
(Thousands)
|
|
|
Revenue from External Customers
|
|
$
|
1,137,288
|
|
|
$
|
122,970
|
|
|
$
|
293,698
|
|
|
$
|
284,349
|
|
|
$
|
55,968
|
|
|
$
|
1,894,273
|
|
|
$
|
13,695
|
|
|
$
|
|
|
|
$
|
1,907,968
|
|
Intersegment Revenues
|
|
$
|
15,353
|
|
|
$
|
86,737
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
2
|
|
|
$
|
102,092
|
|
|
$
|
|
|
|
$
|
(102,092
|
)
|
|
$
|
|
|
Interest Income
|
|
$
|
552
|
|
|
$
|
217
|
|
|
$
|
1,831
|
|
|
$
|
521
|
|
|
$
|
312
|
|
|
$
|
3,433
|
|
|
$
|
15
|
|
|
$
|
(1,677
|
)
|
|
$
|
1,771
|
|
Interest Expense
|
|
$
|
21,945
|
|
|
$
|
10,933
|
|
|
$
|
50,642
|
|
|
$
|
33
|
|
|
$
|
2,218
|
|
|
$
|
85,771
|
|
|
$
|
919
|
|
|
$
|
3,062
|
|
|
$
|
89,752
|
|
Depreciation, Depletion and
Amortization
|
|
$
|
39,101
|
|
|
$
|
37,345
|
|
|
$
|
89,943
|
|
|
$
|
102
|
|
|
$
|
6,277
|
|
|
$
|
172,768
|
|
|
$
|
1,071
|
|
|
$
|
450
|
|
|
$
|
174,289
|
|
Income Tax Expense (Benefit)
|
|
$
|
31,393
|
|
|
$
|
30,968
|
|
|
$
|
28,899
|
|
|
$
|
3,964
|
|
|
$
|
3,320
|
|
|
$
|
98,544
|
|
|
$
|
829
|
|
|
$
|
(4,783
|
)
|
|
$
|
94,590
|
|
Income from Unconsolidated
Subsidiaries
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
805
|
|
|
$
|
|
|
|
$
|
805
|
|
Significant Item:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss on Sale of Timber Properties
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
1,252
|
|
|
$
|
1,252
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
1,252
|
|
Significant Item:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gain on Sale of Oil and Gas
Producing Properties
|
|
$
|
|
|
|
$
|
|
|
|
$
|
4,645
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
4,645
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
4,645
|
|
Segment Profit (Loss): Income
(Loss) from Continuing Operations
|
|
$
|
46,718
|
|
|
$
|
47,726
|
|
|
$
|
54,344
|
|
|
$
|
5,535
|
|
|
$
|
5,637
|
|
|
$
|
159,960
|
|
|
$
|
1,530
|
|
|
$
|
(7,225
|
)
|
|
$
|
154,265
|
|
Expenditures for Additions to
Long-Lived Assets from Continuing Operations
|
|
$
|
55,449
|
|
|
$
|
23,196
|
|
|
$
|
77,654
|
|
|
$
|
10
|
|
|
$
|
2,823
|
|
|
$
|
159,132
|
|
|
$
|
200
|
|
|
$
|
5,511
|
|
|
$
|
164,843
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
At September 30, 2004
|
|
|
|
(Thousands)
|
|
|
Segment Assets
|
|
$
|
1,355,964
|
|
|
$
|
783,145
|
|
|
$
|
1,078,217
|
|
|
$
|
68,599
|
|
|
$
|
140,992
|
|
|
$
|
3,426,917
|
|
|
$
|
77,013
|
|
|
$
|
213,673
|
(1)
|
|
$
|
3,717,603
|
|
|
|
|
(1) |
|
Amount includes $268,119 of assets of the former International
segment, the majority of which has been discontinued with the
sale of U.E. (See Note I Discontinued
Operations). |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Year Ended September 30
|
|
Geographic Information
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
|
(Thousands)
|
|
|
Revenues from External
Customers (1):
|
|
|
|
|
|
|
|
|
|
|
|
|
United States
|
|
$
|
2,242,155
|
|
|
$
|
1,860,684
|
|
|
$
|
1,867,335
|
|
Canada
|
|
|
69,504
|
|
|
|
62,865
|
|
|
|
40,633
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
2,311,659
|
|
|
$
|
1,923,549
|
|
|
$
|
1,907,968
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
100
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
At September 30
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
|
(Thousands)
|
|
|
Long-Lived Assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
United States
|
|
$
|
3,117,644
|
|
|
$
|
2,978,680
|
|
|
$
|
2,941,779
|
|
Canada
|
|
|
97,234
|
|
|
|
171,196
|
|
|
|
143,042
|
|
Assets of Discontinued Operations
|
|
|
|
|
|
|
|
|
|
|
228,179
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
3,214,878
|
|
|
$
|
3,149,876
|
|
|
$
|
3,313,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Revenue is based upon the country in which the sale originates. |
Note K
Investments in Unconsolidated Subsidiaries
The Companys unconsolidated subsidiaries consist of equity
method investments in Seneca Energy, Model City and ESNE. The
Company has 50% interests in each of these entities. Seneca
Energy and Model City generate and sell electricity using
methane gas obtained from landfills owned by outside parties.
ESNE generates electricity from an 80-megawatt, combined cycle,
natural gas-fired power plant in North East, Pennsylvania. ESNE
sells its electricity into the New York power grid.
In September 2005, the Company recorded an impairment of
$4.2 million of its equity investment in ESNE due to a
decline in the fair market value of ESNE. This impairment was
recorded in accordance with APB 18.
A summary of the Companys investments in unconsolidated
subsidiaries at September 30, 2006 and 2005 is as follows:
|
|
|
|
|
|
|
|
|
|
|
At September 30
|
|
|
|
2006
|
|
|
2005
|
|
|
|
(Thousands)
|
|
|
ESNE
|
|
$
|
4,486
|
|
|
$
|
5,298
|
|
Seneca Energy
|
|
|
5,366
|
|
|
|
5,839
|
|
Model City
|
|
|
1,738
|
|
|
|
1,521
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
11,590
|
|
|
$
|
12,658
|
|
|
|
|
|
|
|
|
|
|
101
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Note L
Intangible Assets
As a result of the Empire and Toro acquisitions, the Company
acquired certain intangible assets during 2003. In the case of
the Empire acquisition, the intangible assets represent the fair
value of various long-term transportation contracts with
Empires customers. In the case of the Toro acquisition,
the intangible assets represent the fair value of various
long-term gas purchase contracts with the various landfills.
These intangible assets are being amortized over the lives of
the transportation and gas purchase contracts with no residual
value at the end of the amortization period. The
weighted-average amortization period for the gross carrying
amount of the transportation contracts is 8 years. The
weighted-average amortization period for the gross carrying
amount of the gas purchase contracts is 20 years. Details
of these intangible assets are as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
At September
|
|
|
|
At September 30, 2006
|
|
|
30, 2005
|
|
|
|
Gross Carrying
|
|
|
|
|
|
Net Carrying
|
|
|
Net Carrying
|
|
|
|
Amount
|
|
|
Accumulated Amortization
|
|
|
Amount
|
|
|
Amount
|
|
|
Intangible Assets Subject to
Amortization:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-Term Transportation Contracts
|
|
$
|
8,580
|
|
|
$
|
(3,920
|
)
|
|
$
|
4,660
|
|
|
$
|
5,729
|
|
Long-Term Gas Purchase Contracts
|
|
|
31,864
|
|
|
|
(5,026
|
)
|
|
|
26,838
|
|
|
|
28,431
|
|
Intangible Assets Not Subject to
Amortization:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Retirement Plan Intangible Asset
(see Note G)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
8,142
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
40,444
|
|
|
$
|
(8,946
|
)
|
|
$
|
31,498
|
|
|
$
|
42,302
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Aggregate Amortization Expense
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Year Ended
September 30, 2006
|
|
$
|
2,663
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Year Ended
September 30, 2005
|
|
$
|
2,663
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Year Ended
September 30, 2004
|
|
$
|
2,567
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The gross carrying amount of intangible assets subject to
amortization at September 30, 2006 remained unchanged from
September 30, 2005. The only activity with regard to
intangible assets subject to amortization was amortization
expense as shown on the table above. Amortization expense for
the long-term transportation contracts is estimated to be
$1.1 million annually for 2007 and 2008. Amortization
expense is estimated to be $0.5 million in 2009 and
$0.4 million in 2010 and 2011. Amortization expense for the
long-term gas purchase contracts is estimated to be
$1.6 million annually for 2007, 2008, 2009, 2010 and 2011.
Note M
Quarterly Financial Data (unaudited)
In the opinion of management, the following quarterly
information includes all adjustments necessary for a fair
statement of the results of operations for such periods. Per
common share amounts are calculated using the weighted average
number of shares outstanding during each quarter. The total of
all quarters may differ from the per common share amounts shown
on the Consolidated Statements of Income. Those per common share
amounts are based on the weighted average number of shares
outstanding for the entire fiscal year. Because of the seasonal
nature of the Companys heating business, there are
substantial variations in operations reported on a quarterly
basis.
102
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
|
|
|
Income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
|
|
|
(Loss)
|
|
|
Available
|
|
|
Earnings from
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
from
|
|
|
from
|
|
|
for
|
|
|
Continuing Operations per
|
|
|
|
|
|
|
|
Quarter
|
|
Operating
|
|
|
Operating
|
|
|
Continuing
|
|
|
Discontinued
|
|
|
Common
|
|
|
Common Share
|
|
|
Earnings per Common Share
|
|
Ended
|
|
Revenues
|
|
|
Income
|
|
|
Operations
|
|
|
Operations
|
|
|
Stock
|
|
|
Basic
|
|
|
Diluted
|
|
|
Basic
|
|
|
Diluted
|
|
|
|
(Thousands, except per common share amounts)
|
|
|
2006
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
9/30/2006
|
|
$
|
294,469
|
|
|
$
|
18,444
|
|
|
$
|
1,968
|
|
|
$
|
|
|
|
$
|
1,968
|
(1)
|
|
$
|
0.02
|
|
|
$
|
0.02
|
|
|
$
|
0.02
|
|
|
$
|
0.02
|
|
6/30/2006
|
|
$
|
415,452
|
|
|
$
|
8,541
|
|
|
$
|
111
|
|
|
$
|
|
|
|
$
|
111
|
(2)
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
3/31/2006
|
|
$
|
890,981
|
|
|
$
|
138,967
|
|
|
$
|
78,594
|
|
|
$
|
|
|
|
$
|
78,594
|
(3)
|
|
$
|
0.93
|
|
|
$
|
0.91
|
|
|
$
|
0.93
|
|
|
$
|
0.91
|
|
12/31/2005
|
|
$
|
710,757
|
|
|
$
|
110,123
|
|
|
$
|
57,418
|
|
|
$
|
|
|
|
$
|
57,418
|
(4)
|
|
$
|
0.68
|
|
|
$
|
0.67
|
|
|
$
|
0.68
|
|
|
$
|
0.67
|
|
2005
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
9/30/2005
|
|
$
|
287,064
|
|
|
$
|
34,926
|
|
|
$
|
18,311
|
(5)
|
|
$
|
30,900
|
(6)
|
|
$
|
49,211
|
(5)(6)
|
|
$
|
0.22
|
|
|
$
|
0.21
|
|
|
$
|
0.58
|
|
|
$
|
0.57
|
|
6/30/2005
|
|
$
|
400,359
|
|
|
$
|
63,028
|
|
|
$
|
26,393
|
|
|
$
|
(7,237
|
)(7)
|
|
$
|
19,156
|
(7)
|
|
$
|
0.32
|
|
|
$
|
0.31
|
|
|
$
|
0.23
|
|
|
$
|
0.23
|
|
3/31/2005
|
|
$
|
735,842
|
|
|
$
|
120,667
|
|
|
$
|
63,981
|
(8)
|
|
$
|
6,702
|
|
|
$
|
70,683
|
(8)
|
|
$
|
0.77
|
|
|
$
|
0.75
|
|
|
$
|
0.85
|
|
|
$
|
0.83
|
|
12/31/2004
|
|
$
|
500,284
|
|
|
$
|
91,741
|
|
|
$
|
44,830
|
|
|
$
|
5,608
|
|
|
$
|
50,438
|
|
|
$
|
0.54
|
|
|
$
|
0.53
|
|
|
$
|
0.61
|
|
|
$
|
0.60
|
|
|
|
|
(1) |
|
Includes expense of $29.1 million related to the impairment
of oil and gas producing properties. |
|
(2) |
|
Includes expense of $39.5 million related to the impairment
of oil and gas producing properties and income of
$6.1 million related to income tax adjustments. |
|
(3) |
|
Includes income of $5.1 million related to income tax
adjustments. |
|
(4) |
|
Includes income of $2.6 million related to a regulatory
adjustment. |
|
(5) |
|
Includes a $3.9 million gain associated with insurance
proceeds received in prior years for which a contingency was
resolved during the quarter, $3.3 million of expense
related to certain derivative financial instruments that no
longer qualified as effective hedges, $2.7 million of
expense related to the impairment of an investment in a
partnership, and $1.8 million of expense related to the
impairment of a gas-powered turbine. |
|
(6) |
|
Includes a $25.8 million gain related to the sale of U.E.
and income of $6.0 million due to the reversal of deferred
income taxes related to U.E. |
|
(7) |
|
Includes $6.0 million of previously unrecorded deferred
income tax expense related to U.E. |
|
(8) |
|
Includes a $2.6 million gain on a FERC approved sale of
base gas. |
103
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Note N
Market for Common Stock and Related Shareholder Matters
(unaudited)
At September 30, 2006, there were 17,767 registered
shareholders of Company common stock. The common stock is listed
and traded on the New York Stock Exchange. Information related
to restrictions on the payment of dividends can be found in
Note E Capitalization and Short-Term
Borrowings. The quarterly price ranges (based on intra-day
prices) and quarterly dividends declared for the fiscal years
ended September 30, 2006 and 2005, are shown below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Price Range
|
|
|
|
|
Quarter Ended
|
|
High
|
|
|
Low
|
|
|
Dividends Declared
|
|
|
2006
|
|
|
|
|
|
|
|
|
|
|
|
|
9/30/2006
|
|
$
|
39.16
|
|
|
$
|
34.95
|
|
|
$
|
.30
|
|
6/30/2006
|
|
$
|
36.75
|
|
|
$
|
31.33
|
|
|
$
|
.30
|
|
3/31/2006
|
|
$
|
35.43
|
|
|
$
|
30.60
|
|
|
$
|
.29
|
|
12/31/2005
|
|
$
|
35.27
|
|
|
$
|
29.25
|
|
|
$
|
.29
|
|
2005
|
|
|
|
|
|
|
|
|
|
|
|
|
9/30/2005
|
|
$
|
36.00
|
|
|
$
|
27.74
|
|
|
$
|
.29
|
|
6/30/2005
|
|
$
|
29.49
|
|
|
$
|
26.20
|
|
|
$
|
.29
|
|
3/31/2005
|
|
$
|
29.75
|
|
|
$
|
26.66
|
|
|
$
|
.28
|
|
12/31/2004
|
|
$
|
29.18
|
|
|
$
|
27.01
|
|
|
$
|
.28
|
|
Note O
Supplementary Information for Oil and Gas Producing
Activities
The following supplementary information is presented in
accordance with SFAS 69, Disclosures about Oil and
Gas Producing Activities, and related SEC accounting
rules. All monetary amounts are expressed in U.S. dollars.
Capitalized
Costs Relating to Oil and Gas Producing Activities
|
|
|
|
|
|
|
|
|
|
|
At September 30
|
|
|
|
2006
|
|
|
2005
|
|
|
|
(Thousands)
|
|
|
Proved Properties(1)
|
|
$
|
1,884,049
|
|
|
$
|
1,650,788
|
|
Unproved Properties
|
|
|
41,930
|
|
|
|
39,084
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,925,979
|
|
|
|
1,689,872
|
|
Less Accumulated
Depreciation, Depletion and Amortization
|
|
|
929,921
|
|
|
|
721,397
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
996,058
|
|
|
$
|
968,475
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Includes asset retirement costs of $42.2 million and
$30.8 million at September 30, 2006 and 2005,
respectively. |
104
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Costs related to unproved properties are excluded from
amortization as they represent unevaluated properties that
require additional drilling to determine the existence of oil
and gas reserves. Following is a summary of such costs excluded
from amortization at September 30, 2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
as
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
of
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
September
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
30,
|
|
|
Year Costs Incurred
|
|
|
|
2006
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
Prior
|
|
|
|
(Thousands)
|
|
|
Acquisition Costs
|
|
$
|
41,930
|
|
|
$
|
27,497
|
|
|
$
|
6,078
|
|
|
$
|
981
|
|
|
$
|
7,374
|
|
Costs
Incurred in Oil and Gas Property Acquisition, Exploration and
Development Activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended September 30
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
|
(Thousands)
|
|
|
United States
|
|
|
|
|
|
|
|
|
|
|
|
|
Property Acquisition Costs:
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved
|
|
$
|
5,339
|
|
|
$
|
287
|
|
|
$
|
(8
|
)
|
Unproved
|
|
|
8,844
|
|
|
|
1,215
|
|
|
|
3,529
|
|
Exploration Costs
|
|
|
64,087
|
|
|
|
32,456
|
|
|
|
10,503
|
|
Development Costs
|
|
|
87,738
|
|
|
|
49,016
|
|
|
|
31,881
|
|
Asset Retirement Costs
|
|
|
10,965
|
|
|
|
8,051
|
|
|
|
2,292
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
176,973
|
|
|
|
91,025
|
|
|
|
48,197
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canada
|
|
|
|
|
|
|
|
|
|
|
|
|
Property Acquisition Costs:
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved
|
|
|
(427
|
)
|
|
|
(1,551
|
)
|
|
|
29
|
|
Unproved
|
|
|
6,492
|
|
|
|
4,668
|
|
|
|
3,167
|
|
Exploration Costs
|
|
|
20,778
|
|
|
|
22,943
|
|
|
|
22,624
|
|
Development Costs
|
|
|
14,385
|
|
|
|
12,198
|
|
|
|
5,500
|
|
Asset Retirement Costs
|
|
|
279
|
|
|
|
292
|
|
|
|
1,218
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
41,507
|
|
|
|
38,550
|
|
|
|
32,538
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
|
|
Property Acquisition Costs:
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved
|
|
|
4,912
|
|
|
|
(1,264
|
)
|
|
|
21
|
|
Unproved
|
|
|
15,336
|
|
|
|
5,883
|
|
|
|
6,696
|
|
Exploration Costs
|
|
|
84,865
|
|
|
|
55,399
|
|
|
|
33,127
|
|
Development Costs
|
|
|
102,123
|
|
|
|
61,214
|
|
|
|
37,381
|
|
Asset Retirement Costs
|
|
|
11,244
|
|
|
|
8,343
|
|
|
|
3,510
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
218,480
|
|
|
$
|
129,575
|
|
|
$
|
80,735
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the years ended September 30, 2006, 2005 and 2004, the
Company spent $55.6 million, $19.2 million and
$12.1 million, respectively, developing proved undeveloped
reserves.
105
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Results
of Operations for Producing Activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended September 30
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
|
(Thousands, except per Mcfe amounts)
|
|
|
United States
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas (includes revenues
from sales to affiliates of $106, $77 and $72, respectively)
|
|
$
|
152,451
|
|
|
$
|
151,004
|
|
|
$
|
151,570
|
|
Oil, Condensate and Other Liquids
|
|
|
195,050
|
|
|
|
160,145
|
|
|
|
139,301
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Operating Revenues(1)
|
|
|
347,501
|
|
|
|
311,149
|
|
|
|
290,871
|
|
Production/Lifting Costs
|
|
|
41,354
|
|
|
|
38,442
|
|
|
|
39,677
|
|
Accretion Expense
|
|
|
2,412
|
|
|
|
2,220
|
|
|
|
1,756
|
|
Depreciation, Depletion and
Amortization ($1.74, $1.58 and $1.41 per Mcfe of production)
|
|
|
66,488
|
|
|
|
67,097
|
|
|
|
73,396
|
|
Income Tax Expense
|
|
|
88,104
|
|
|
|
74,110
|
|
|
|
65,337
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Results of Operations for
Producing Activities (excluding corporate overheads and interest
charges)
|
|
|
149,143
|
|
|
|
129,280
|
|
|
|
110,705
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canada
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas
|
|
|
54,819
|
|
|
|
49,275
|
|
|
|
30,359
|
|
Oil, Condensate and Other Liquids
|
|
|
13,985
|
|
|
|
12,875
|
|
|
|
10,018
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Operating Revenues(1)
|
|
|
68,804
|
|
|
|
62,150
|
|
|
|
40,377
|
|
Production/Lifting Costs
|
|
|
14,628
|
|
|
|
12,683
|
|
|
|
8,176
|
|
Accretion Expense
|
|
|
258
|
|
|
|
228
|
|
|
|
177
|
|
Depreciation, Depletion and
Amortization ($2.95, $2.36 and $1.83 per Mcfe of production)
|
|
|
27,439
|
|
|
|
23,108
|
|
|
|
14,922
|
|
Impairment of Oil and Gas
Producing Properties(2)
|
|
|
104,739
|
|
|
|
|
|
|
|
|
|
Income Tax Expense (Benefit)
|
|
|
(31,987
|
)
|
|
|
8,577
|
|
|
|
5,235
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Results of Operations for
Producing Activities (excluding corporate overheads and interest
charges)
|
|
|
(46,273
|
)
|
|
|
17,554
|
|
|
|
11,867
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
106
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended September 30
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
|
(Thousands, except per Mcfe amounts)
|
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas (includes revenues
from sales to affiliates of $106, $77 and $72, respectively)
|
|
|
207,270
|
|
|
|
200,279
|
|
|
|
181,929
|
|
Oil, Condensate and Other Liquids
|
|
|
209,035
|
|
|
|
173,020
|
|
|
|
149,319
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Operating Revenues(1)
|
|
|
416,305
|
|
|
|
373,299
|
|
|
|
331,248
|
|
Production/Lifting Costs
|
|
|
55,982
|
|
|
|
51,125
|
|
|
|
47,853
|
|
Accretion Expense
|
|
|
2,670
|
|
|
|
2,448
|
|
|
|
1,933
|
|
Depreciation, Depletion and
Amortization ($1.98, $1.72 and $1.47 per Mcfe of production)
|
|
|
93,927
|
|
|
|
90,205
|
|
|
|
88,318
|
|
Impairment of Oil and Gas
Producing Properties(2)
|
|
|
104,739
|
|
|
|
|
|
|
|
|
|
Income Tax Expense
|
|
|
56,117
|
|
|
|
82,687
|
|
|
|
70,572
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Results of Operations for
Producing Activities (excluding corporate overheads and interest
charges)
|
|
$
|
102,870
|
|
|
$
|
146,834
|
|
|
$
|
122,572
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Exclusive of hedging gains and losses. See further discussion in
Note F Financial Instruments. |
|
(2) |
|
See discussion of impairment in Note A Summary
of Significant Accounting Policies. |
Reserve
Quantity Information (unaudited)
The Companys proved oil and gas reserves are located in
the United States and Canada. The estimated quantities of proved
reserves disclosed in the table below are based upon estimates
by qualified Company geologists and engineers and are audited by
independent petroleum engineers. Such estimates are inherently
imprecise and may be subject to substantial revisions as a
result of numerous factors including, but not limited to,
additional development activity, evolving production history and
continual reassessment of the viability of production under
varying economic conditions.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas MMcf
|
|
|
|
U. S.
|
|
|
|
|
|
|
|
|
|
Gulf
|
|
|
West
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Coast
|
|
|
Coast
|
|
|
Appalachian
|
|
|
Total
|
|
|
|
|
|
Total
|
|
|
|
Region
|
|
|
Region
|
|
|
Region
|
|
|
U.S.
|
|
|
Canada
|
|
|
Company
|
|
|
Proved Developed and Undeveloped
Reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
September 30, 2003
|
|
|
47,683
|
|
|
|
70,062
|
|
|
|
81,219
|
|
|
|
198,964
|
|
|
|
52,153
|
|
|
|
251,117
|
|
Extensions and Discoveries
|
|
|
2,632
|
|
|
|
|
|
|
|
3,784
|
|
|
|
6,416
|
|
|
|
15,925
|
|
|
|
22,341
|
|
Revisions of Previous Estimates
|
|
|
(4,984
|
)
|
|
|
1,831
|
|
|
|
(1,111
|
)
|
|
|
(4,264
|
)
|
|
|
(11,004
|
)
|
|
|
(15,268
|
)
|
Production
|
|
|
(17,596
|
)
|
|
|
(4,057
|
)
|
|
|
(5,132
|
)
|
|
|
(26,785
|
)
|
|
|
(6,228
|
)
|
|
|
(33,013
|
)
|
Sales of Minerals in Place
|
|
|
(1
|
)
|
|
|
(392
|
)
|
|
|
|
|
|
|
(393
|
)
|
|
|
|
|
|
|
(393
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
107
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas MMcf
|
|
|
|
U. S.
|
|
|
|
|
|
|
|
|
|
Gulf
|
|
|
West
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Coast
|
|
|
Coast
|
|
|
Appalachian
|
|
|
Total
|
|
|
|
|
|
Total
|
|
|
|
Region
|
|
|
Region
|
|
|
Region
|
|
|
U.S.
|
|
|
Canada
|
|
|
Company
|
|
|
September 30, 2004
|
|
|
27,734
|
|
|
|
67,444
|
|
|
|
78,760
|
|
|
|
173,938
|
|
|
|
50,846
|
|
|
|
224,784
|
|
Extensions and Discoveries
|
|
|
17,165
|
|
|
|
|
|
|
|
5,461
|
|
|
|
22,626
|
|
|
|
4,849
|
|
|
|
27,475
|
|
Revisions of Previous Estimates
|
|
|
6,039
|
|
|
|
7,067
|
|
|
|
3,733
|
|
|
|
16,839
|
|
|
|
(1,600
|
)
|
|
|
15,239
|
|
Production
|
|
|
(12,468
|
)
|
|
|
(4,052
|
)
|
|
|
(4,650
|
)
|
|
|
(21,170
|
)
|
|
|
(8,009
|
)
|
|
|
(29,179
|
)
|
Sales of Minerals in Place
|
|
|
|
|
|
|
|
|
|
|
(179
|
)
|
|
|
(179
|
)
|
|
|
|
|
|
|
(179
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
September 30, 2005
|
|
|
38,470
|
|
|
|
70,459
|
|
|
|
83,125
|
|
|
|
192,054
|
|
|
|
46,086
|
|
|
|
238,140
|
|
Extensions and Discoveries
|
|
|
11,763
|
|
|
|
1,815
|
|
|
|
11,132
|
|
|
|
24,710
|
|
|
|
6,229
|
|
|
|
30,939
|
|
Revisions of Previous Estimates
|
|
|
679
|
|
|
|
5,757
|
|
|
|
(7,776
|
)
|
|
|
(1,340
|
)
|
|
|
(11,096
|
)
|
|
|
(12,436
|
)
|
Production
|
|
|
(9,110
|
)
|
|
|
(3,880
|
)
|
|
|
(5,108
|
)
|
|
|
(18,098
|
)
|
|
|
(7,673
|
)
|
|
|
(25,771
|
)
|
Purchases of Minerals in Place
|
|
|
|
|
|
|
1,715
|
|
|
|
|
|
|
|
1,715
|
|
|
|
|
|
|
|
1,715
|
|
Sales of Minerals in Place
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(12
|
)
|
|
|
(12
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
September 30, 2006
|
|
|
41,802
|
|
|
|
75,866
|
|
|
|
81,373
|
|
|
|
199,041
|
|
|
|
33,534
|
|
|
|
232,575
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved Developed Reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
September 30, 2003
|
|
|
45,402
|
|
|
|
54,180
|
|
|
|
81,218
|
|
|
|
180,800
|
|
|
|
42,745
|
|
|
|
223,545
|
|
September 30, 2004
|
|
|
25,827
|
|
|
|
53,035
|
|
|
|
78,760
|
|
|
|
157,622
|
|
|
|
46,223
|
|
|
|
203,845
|
|
September 30, 2005
|
|
|
23,108
|
|
|
|
58,692
|
|
|
|
83,125
|
|
|
|
164,925
|
|
|
|
43,980
|
|
|
|
208,905
|
|
September 30, 2006
|
|
|
32,345
|
|
|
|
64,196
|
|
|
|
81,373
|
|
|
|
177,914
|
|
|
|
33,534
|
|
|
|
211,448
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil Mbbl
|
|
|
|
U.S.
|
|
|
|
|
|
|
|
|
|
|
|
|
West
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gulf Coast
|
|
|
Coast
|
|
|
Appalachian
|
|
|
Total
|
|
|
|
|
|
Total
|
|
|
|
Region
|
|
|
Region
|
|
|
Region
|
|
|
U.S.
|
|
|
Canada
|
|
|
Company
|
|
|
Proved Developed and Undeveloped
Reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
September 30, 2003
|
|
|
3,383
|
|
|
|
63,852
|
|
|
|
138
|
|
|
|
67,373
|
|
|
|
2,391
|
|
|
|
69,764
|
|
Extensions and Discoveries
|
|
|
19
|
|
|
|
|
|
|
|
18
|
|
|
|
37
|
|
|
|
181
|
|
|
|
218
|
|
Revisions of Previous Estimates
|
|
|
213
|
|
|
|
(17
|
)
|
|
|
11
|
|
|
|
207
|
|
|
|
(144
|
)
|
|
|
63
|
|
Production
|
|
|
(1,534
|
)
|
|
|
(2,650
|
)
|
|
|
(20
|
)
|
|
|
(4,204
|
)
|
|
|
(324
|
)
|
|
|
(4,528
|
)
|
Sales of Minerals in Place
|
|
|
(1
|
)
|
|
|
(303
|
)
|
|
|
|
|
|
|
(304
|
)
|
|
|
|
|
|
|
(304
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
September 30, 2004
|
|
|
2,080
|
|
|
|
60,882
|
|
|
|
147
|
|
|
|
63,109
|
|
|
|
2,104
|
|
|
|
65,213
|
|
Extensions and Discoveries
|
|
|
99
|
|
|
|
|
|
|
|
63
|
|
|
|
162
|
|
|
|
204
|
|
|
|
366
|
|
Revisions of Previous Estimates
|
|
|
105
|
|
|
|
(1,253
|
)
|
|
|
3
|
|
|
|
(1,145
|
)
|
|
|
(186
|
)
|
|
|
(1,331
|
)
|
Production
|
|
|
(989
|
)
|
|
|
(2,544
|
)
|
|
|
(36
|
)
|
|
|
(3,569
|
)
|
|
|
(300
|
)
|
|
|
(3,869
|
)
|
Sales of Minerals in Place
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(122
|
)
|
|
|
(122
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
108
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil Mbbl
|
|
|
|
U.S.
|
|
|
|
|
|
|
|
|
|
|
|
|
West
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gulf Coast
|
|
|
Coast
|
|
|
Appalachian
|
|
|
Total
|
|
|
|
|
|
Total
|
|
|
|
Region
|
|
|
Region
|
|
|
Region
|
|
|
U.S.
|
|
|
Canada
|
|
|
Company
|
|
|
September 30, 2005
|
|
|
1,295
|
|
|
|
57,085
|
|
|
|
177
|
|
|
|
58,557
|
|
|
|
1,700
|
|
|
|
60,257
|
|
Extensions and Discoveries
|
|
|
39
|
|
|
|
172
|
|
|
|
108
|
|
|
|
319
|
|
|
|
128
|
|
|
|
447
|
|
Revisions of Previous Estimates
|
|
|
595
|
|
|
|
(80
|
)
|
|
|
57
|
|
|
|
572
|
|
|
|
101
|
|
|
|
673
|
|
Production
|
|
|
(685
|
)
|
|
|
(2,582
|
)
|
|
|
(69
|
)
|
|
|
(3,336
|
)
|
|
|
(272
|
)
|
|
|
(3,608
|
)
|
Purchases of Minerals in Place
|
|
|
|
|
|
|
274
|
|
|
|
|
|
|
|
274
|
|
|
|
|
|
|
|
274
|
|
Sales of Minerals in Place
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(25
|
)
|
|
|
(25
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
September 30, 2006
|
|
|
1,244
|
|
|
|
54,869
|
|
|
|
273
|
|
|
|
56,386
|
|
|
|
1,632
|
|
|
|
58,018
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved Developed Reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
September 30, 2003
|
|
|
2,533
|
|
|
|
40,079
|
|
|
|
139
|
|
|
|
42,751
|
|
|
|
2,391
|
|
|
|
45,142
|
|
September 30, 2004
|
|
|
2,061
|
|
|
|
38,631
|
|
|
|
148
|
|
|
|
40,840
|
|
|
|
2,104
|
|
|
|
42,944
|
|
September 30, 2005
|
|
|
1,229
|
|
|
|
41,701
|
|
|
|
177
|
|
|
|
43,107
|
|
|
|
1,700
|
|
|
|
44,807
|
|
September 30, 2006
|
|
|
1,217
|
|
|
|
42,522
|
|
|
|
273
|
|
|
|
44,012
|
|
|
|
1,632
|
|
|
|
45,644
|
|
Standardized
Measure of Discounted Future Net Cash Flows Relating to Proved
Oil and Gas Reserves (unaudited)
The Company cautions that the following presentation of the
standardized measure of discounted future net cash flows is
intended to be neither a measure of the fair market value of the
Companys oil and gas properties, nor an estimate of the
present value of actual future cash flows to be obtained as a
result of their development and production. It is based upon
subjective estimates of proved reserves only and attributes no
value to categories of reserves other than proved reserves, such
as probable or possible reserves, or to unproved acreage.
Furthermore, it is based on year-end prices and costs adjusted
only for existing contractual changes, and it assumes an
arbitrary discount rate of 10%. Thus, it gives no effect to
future price and cost changes certain to occur under widely
fluctuating political and economic conditions.
109
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The standardized measure is intended instead to provide a means
for comparing the value of the Companys proved reserves at
a given time with those of other oil- and gas-producing
companies than is provided by a simple comparison of raw proved
reserve quantities.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended September 30
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
|
(Thousands)
|
|
|
United States
|
|
|
|
|
|
|
|
|
|
|
|
|
Future Cash Inflows
|
|
$
|
3,911,059
|
|
|
$
|
6,138,522
|
|
|
$
|
3,728,168
|
|
Less:
|
|
|
|
|
|
|
|
|
|
|
|
|
Future Production Costs
|
|
|
758,258
|
|
|
|
777,417
|
|
|
|
676,361
|
|
Future Development Costs
|
|
|
205,497
|
|
|
|
188,795
|
|
|
|
124,298
|
|
Future Income Tax Expense at
Applicable Statutory Rate
|
|
|
1,019,307
|
|
|
|
1,868,548
|
|
|
|
995,327
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Future Net Cash Flows
|
|
|
1,927,997
|
|
|
|
3,303,762
|
|
|
|
1,932,182
|
|
Less:
|
|
|
|
|
|
|
|
|
|
|
|
|
10% Annual Discount for Estimated
Timing of Cash Flows
|
|
|
1,066,338
|
|
|
|
1,812,230
|
|
|
|
996,813
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Standardized Measure of Discounted
Future Net Cash Flows
|
|
|
861,659
|
|
|
|
1,491,532
|
|
|
|
935,369
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
110
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended September 30
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
|
(Thousands)
|
|
|
Canada
|
|
|
|
|
|
|
|
|
|
|
|
|
Future Cash Inflows
|
|
|
197,227
|
|
|
|
601,210
|
|
|
|
343,026
|
|
Less:
|
|
|
|
|
|
|
|
|
|
|
|
|
Future Production Costs
|
|
|
92,234
|
|
|
|
136,338
|
|
|
|
111,519
|
|
Future Development Costs
|
|
|
11,520
|
|
|
|
12,197
|
|
|
|
13,222
|
|
Future Income Tax Expense at
Applicable Statutory Rate
|
|
|
(151
|
)
|
|
|
137,524
|
|
|
|
60,610
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Future Net Cash Flows
|
|
|
93,624
|
|
|
|
315,151
|
|
|
|
157,675
|
|
Less:
|
|
|
|
|
|
|
|
|
|
|
|
|
10% Annual Discount for Estimated
Timing of Cash Flows
|
|
|
19,375
|
|
|
|
108,508
|
|
|
|
46,945
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Standardized Measure of Discounted
Future Net Cash Flows
|
|
|
74,249
|
|
|
|
206,643
|
|
|
|
110,730
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
|
|
Future Cash Inflows
|
|
|
4,108,286
|
|
|
|
6,739,732
|
|
|
|
4,071,194
|
|
Less:
|
|
|
|
|
|
|
|
|
|
|
|
|
Future Production Costs
|
|
|
850,492
|
|
|
|
913,755
|
|
|
|
787,880
|
|
Future Development Costs
|
|
|
217,017
|
|
|
|
200,992
|
|
|
|
137,520
|
|
Future Income Tax Expense at
Applicable Statutory Rate
|
|
|
1,019,156
|
|
|
|
2,006,072
|
|
|
|
1,055,937
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Future Net Cash Flows
|
|
|
2,021,621
|
|
|
|
3,618,913
|
|
|
|
2,089,857
|
|
Less:
|
|
|
|
|
|
|
|
|
|
|
|
|
10% Annual Discount for Estimated
Timing of Cash Flows
|
|
|
1,085,713
|
|
|
|
1,920,738
|
|
|
|
1,043,758
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Standardized Measure of Discounted
Future Net Cash Flows
|
|
$
|
935,908
|
|
|
$
|
1,698,175
|
|
|
$
|
1,046,099
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
111
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The principal sources of change in the standardized measure of
discounted future net cash flows were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended September 30
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
|
(Thousands)
|
|
|
United States
|
|
|
|
|
|
|
|
|
|
|
|
|
Standardized Measure of Discounted
Future
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Cash Flows at Beginning of Year
|
|
$
|
1,491,532
|
|
|
$
|
935,369
|
|
|
$
|
733,248
|
|
Sales, Net of Production Costs
|
|
|
(306,147
|
)
|
|
|
(272,707
|
)
|
|
|
(251,194
|
)
|
Net Changes in Prices, Net of
Production Costs
|
|
|
(941,545
|
)
|
|
|
1,093,353
|
|
|
|
592,326
|
|
Purchases of Minerals in Place
|
|
|
7,607
|
|
|
|
|
|
|
|
|
|
Sales of Minerals in Place
|
|
|
|
|
|
|
(762
|
)
|
|
|
(5,554
|
)
|
Extensions and Discoveries
|
|
|
66,975
|
|
|
|
100,102
|
|
|
|
16,638
|
|
Changes in Estimated Future
Development Costs
|
|
|
(83,750
|
)
|
|
|
(89,805
|
)
|
|
|
(40,042
|
)
|
Previously Estimated Development
Costs Incurred
|
|
|
67,048
|
|
|
|
25,038
|
|
|
|
32,653
|
|
Net Change in Income Taxes at
Applicable Statutory Rate
|
|
|
404,176
|
|
|
|
(362,956
|
)
|
|
|
(166,055
|
)
|
Revisions of Previous Quantity
Estimates
|
|
|
4,850
|
|
|
|
25,055
|
|
|
|
(5,107
|
)
|
Accretion of Discount and Other
|
|
|
150,913
|
|
|
|
38,845
|
|
|
|
28,456
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Standardized Measure of Discounted
Future Net Cash Flows at End of Year
|
|
|
861,659
|
|
|
|
1,491,532
|
|
|
|
935,369
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canada
|
|
|
|
|
|
|
|
|
|
|
|
|
Standardized Measure of Discounted
Future
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Cash Flows at Beginning of Year
|
|
|
206,643
|
|
|
|
110,730
|
|
|
|
85,157
|
|
Sales, Net of Production Costs
|
|
|
(54,176
|
)
|
|
|
(49,467
|
)
|
|
|
(32,201
|
)
|
Net Changes in Prices, Net of
Production Costs
|
|
|
(180,216
|
)
|
|
|
174,985
|
|
|
|
29,230
|
|
Purchases of Minerals in Place
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales of Minerals in Place
|
|
|
(238
|
)
|
|
|
(3,751
|
)
|
|
|
|
|
Extensions and Discoveries
|
|
|
10,369
|
|
|
|
31,028
|
|
|
|
36,986
|
|
Changes in Estimated Future
Development Costs
|
|
|
(3,282
|
)
|
|
|
(11,007
|
)
|
|
|
(8,491
|
)
|
Previously Estimated Development
Costs Incurred
|
|
|
4,450
|
|
|
|
12,032
|
|
|
|
5,055
|
|
Net Change in Income Taxes at
Applicable Statutory Rate
|
|
|
82,966
|
|
|
|
(51,541
|
)
|
|
|
(2,640
|
)
|
Revisions of Previous Quantity
Estimates
|
|
|
(15,478
|
)
|
|
|
(5,990
|
)
|
|
|
(19,369
|
)
|
Accretion of Discount and Other
|
|
|
23,211
|
|
|
|
(376
|
)
|
|
|
17,003
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Standardized Measure of Discounted
Future Net Cash Flows at End of Year
|
|
|
74,249
|
|
|
|
206,643
|
|
|
|
110,730
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
112
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended September 30
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
|
(Thousands)
|
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
|
|
Standardized Measure of Discounted
Future
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Cash Flows at Beginning of Year
|
|
|
1,698,175
|
|
|
|
1,046,099
|
|
|
|
818,405
|
|
Sales, Net of Production Costs
|
|
|
(360,323
|
)
|
|
|
(322,174
|
)
|
|
|
(283,395
|
)
|
Net Changes in Prices, Net of
Production Costs
|
|
|
(1,121,761
|
)
|
|
|
1,268,338
|
|
|
|
621,556
|
|
Purchases of Minerals in Place
|
|
|
7,607
|
|
|
|
|
|
|
|
|
|
Sales of Minerals in Place
|
|
|
(238
|
)
|
|
|
(4,513
|
)
|
|
|
(5,554
|
)
|
Extensions and Discoveries
|
|
|
77,344
|
|
|
|
131,130
|
|
|
|
53,624
|
|
Changes in Estimated Future
Development Costs
|
|
|
(87,032
|
)
|
|
|
(100,812
|
)
|
|
|
(48,533
|
)
|
Previously Estimated Development
Costs Incurred
|
|
|
71,498
|
|
|
|
37,070
|
|
|
|
37,708
|
|
Net Change in Income Taxes at
Applicable Statutory Rate
|
|
|
487,142
|
|
|
|
(414,497
|
)
|
|
|
(168,695
|
)
|
Revisions of Previous Quantity
Estimates
|
|
|
(10,628
|
)
|
|
|
19,065
|
|
|
|
(24,476
|
)
|
Accretion of Discount and Other
|
|
|
174,124
|
|
|
|
38,469
|
|
|
|
45,459
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Standardized Measure of Discounted
Future Net Cash Flows at End of Year
|
|
$
|
935,908
|
|
|
$
|
1,698,175
|
|
|
$
|
1,046,099
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Schedule II
Valuation and Qualifying Accounts
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Additions
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance
|
|
|
Charged
|
|
|
Additions
|
|
|
|
|
|
Balance
|
|
|
|
at
|
|
|
to
|
|
|
Charged
|
|
|
|
|
|
at
|
|
|
|
Beginning
|
|
|
Costs
|
|
|
to
|
|
|
|
|
|
End
|
|
|
|
of
|
|
|
and
|
|
|
Other
|
|
|
|
|
|
of
|
|
Description
|
|
Period
|
|
|
Expenses
|
|
|
Accounts
|
|
|
Deductions(3)
|
|
|
Period
|
|
|
|
(Thousands)
|
|
|
Year Ended September 30,
2006
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allowance for Uncollectible
Accounts
|
|
$
|
26,940
|
|
|
$
|
29,088
|
|
|
$
|
907
|
(1)
|
|
$
|
25,508
|
|
|
$
|
31,427
|
|
Deferred Tax Valuation Allowance
|
|
$
|
2,877
|
|
|
$
|
(2,877
|
)
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended September 30,
2005
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allowance for Uncollectible
Accounts
|
|
$
|
17,440
|
|
|
$
|
31,113
|
|
|
$
|
2,480
|
(2)
|
|
$
|
24,093
|
|
|
$
|
26,940
|
|
Deferred Tax Valuation Allowance
|
|
$
|
2,877
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
2,877
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended September 30,
2004
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allowance for Uncollectible
Accounts
|
|
$
|
17,943
|
|
|
$
|
20,328
|
|
|
$
|
|
|
|
$
|
20,831
|
|
|
$
|
17,440
|
|
Deferred Tax Valuation Allowance
|
|
$
|
6,357
|
|
|
$
|
(3,480
|
)
|
|
$
|
|
|
|
$
|
|
|
|
$
|
2,877
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Represents the discount on accounts receivable purchased in
accordance with the Utility segments 2005 New York rate
settlement. |
|
(2) |
|
Represents amounts reclassified from regulatory asset and
regulatory liability accounts under various rate settlements
($4.5 million). Also includes amounts removed with the sale
of U.E. (-$2.02 million). |
|
(3) |
|
Amounts represent net accounts receivable written-off. |
113
|
|
Item 9
|
Changes
in and Disagreements with Accountants on Accounting and
Financial Disclosure
|
None
|
|
Item 9A
|
Controls
and Procedures
|
Evaluation
of Disclosure Controls and Procedures
The term disclosure controls and procedures is
defined in
Rules 13a-15(e)
and
15d-15(e)
under the Exchange Act. These rules refer to the controls and
other procedures of a company that are designed to ensure that
information required to be disclosed by a company in the reports
that it files or submits under the Exchange Act is recorded,
processed, summarized and reported within required time periods.
Disclosure controls and procedures include, without limitation,
controls and procedures designed to ensure that information
required to be disclosed is accumulated and communicated to the
companys management, including its principal executive and
principal financial officers, as appropriate to allow timely
decisions regarding required disclosure. The Companys
management, including the Chief Executive Officer and Principal
Financial Officer, evaluated the effectiveness of the
Companys disclosure controls and procedures as of the end
of the period covered by this report. Based upon that
evaluation, the Companys Chief Executive Officer and
Principal Financial Officer concluded that the Companys
disclosure controls and procedures were effective as of
September 30, 2006.
Managements
Report on Internal Control over Financial
Reporting
The management of the Company is responsible for establishing
and maintaining adequate internal control over financial
reporting as defined in
Rules 13a-15(f)
and
15d-15(f)
under the Exchange Act. The Companys internal control over
financial reporting is designed to provide reasonable assurance
regarding the reliability of financial reporting and preparation
of financial statements for external purposes in accordance with
GAAP. Because of its inherent limitations, internal control over
financial reporting may not prevent or detect misstatements.
The Companys management assessed the effectiveness of the
Companys internal control over financial reporting as of
September 30, 2006. In making this assessment, management
used the framework and criteria set forth by the Committee of
Sponsoring Organizations of the Treadway Commission (COSO) in
Internal Control Integrated
Framework. Based on this assessment, management
concluded that the Company maintained effective internal control
over financial reporting as of September 30, 2006.
PricewaterhouseCoopers LLP, the independent registered public
accounting firm that audited the Companys consolidated
financial statements included in this Annual Report on
Form 10-K,
has issued a report on managements assessment of the
effectiveness of the Companys internal control over
financial reporting as of September 30, 2006. The report
appears in Part II, Item 8 of this Annual Report on
Form 10-K.
Changes
in Internal Control over Financial Reporting
There were no changes in the Companys internal control
over financial reporting that occurred during the quarter ended
September 30, 2006 that have materially affected, or are
reasonably likely to materially affect, the Companys
internal control over financial reporting.
|
|
Item 9B
|
Other
Information
|
None
PART III
|
|
Item 10
|
Directors
and Executive Officers of the Registrant
|
The information required by this item concerning the directors
of the Company is omitted pursuant to Instruction G of
Form 10-K
since the Companys definitive Proxy Statement for its
February 15, 2007 Annual
114
Meeting of Shareholders will be filed with the SEC not later
than 120 days after September 30, 2006. The
information concerning directors is set forth in the definitive
Proxy Statement under the headings entitled Nominees for
Election as Directors for Three-Year Terms to Expire in
2010, Directors Whose Terms Expire in 2009,
Directors Whose Terms Expire in 2008, and
Compliance with Section 16(a) of the Securities
Exchange Act of 1934 and is incorporated herein by
reference. Information concerning the Companys executive
officers can be found in Part I, Item 1, of this
report.
The Company has adopted a Code of Business Conduct and Ethics
that applies to the Companys directors, officers and
employees and has posted such Code of Business Conduct and
Ethics on the Companys website,
www.nationalfuelgas.com, together with certain other
corporate governance documents. Copies of the Companys
Code of Business Conduct and Ethics, charters of important
committees, and Corporate Governance Guidelines will be made
available free of charge upon written request to Investor
Relations, National Fuel Gas Company, 6363 Main Street,
Williamsville, New York 14221.
The Company intends to satisfy the disclosure requirement under
Item 5.05 of
Form 8-K
regarding an amendment to, or a waiver from, a provision of its
code of ethics that applies to the Companys principal
executive officer, principal financial officer, principal
accounting officer or controller, or persons performing similar
functions, and that relates to any element of the code of ethics
definition enumerated in paragraph (b) of
Item 406 of the SECs
Regulation S-K,
by posting such information on its website,
www.nationalfuelgas.com.
|
|
Item 11
|
Executive
Compensation
|
The information required by this item is omitted pursuant to
Instruction G of
Form 10-K
since the Companys definitive Proxy Statement for its
February 15, 2007 Annual Meeting of Shareholders will be
filed with the SEC not later than 120 days after
September 30, 2006. The information concerning executive
compensation is set forth in the definitive Proxy Statement
under the headings Executive Compensation and
Compensation Committee Interlocks and Insider
Participation and, excepting the Report of the
Compensation Committee and the Corporate Performance
Graph, is incorporated herein by reference.
|
|
Item 12
|
Security
Ownership of Certain Beneficial Owners and Management and
Related Stockholder Matters
|
Equity
Compensation Plan Information
The information required by this item is omitted pursuant to
Instruction G of
Form 10-K
since the Companys definitive Proxy Statement for its
February 15, 2007 Annual Meeting of Shareholders will be
filed with the SEC not later than 120 days after
September 30, 2006. The equity compensation plan
information is set forth in the definitive Proxy Statement under
the heading Equity Compensation Plan Information and
is incorporated herein by reference.
Security
Ownership and Changes in Control
|
|
(a)
|
Security
Ownership of Certain Beneficial Owners
|
The information required by this item is omitted pursuant to
Instruction G of
Form 10-K
since the Companys definitive Proxy Statement for its
February 15, 2007 Annual Meeting of Shareholders will be
filed with the SEC not later than 120 days after
September 30, 2006. The information concerning security
ownership of certain beneficial owners is set forth in the
definitive Proxy Statement under the heading Security
Ownership of Certain Beneficial Owners and Management and
is incorporated herein by reference.
|
|
(b)
|
Security
Ownership of Management
|
The information required by this item is omitted pursuant to
Instruction G of
Form 10-K
since the Companys definitive Proxy Statement for its
February 15, 2007 Annual Meeting of Shareholders will be
filed with the SEC not later than 120 days after
September 30, 2006. The information concerning security
ownership of management is set forth in the definitive Proxy
Statement under the heading Security Ownership of Certain
Beneficial Owners and Management and is incorporated
herein by reference.
115
None
|
|
Item 13
|
Certain
Relationships and Related Transactions
|
The information required by this item is omitted pursuant to
Instruction G of
Form 10-K
since the Companys definitive Proxy Statement for its
February 15, 2007 Annual Meeting of Shareholders will be
filed with the SEC not later than 120 days after
September 30, 2006. The information regarding certain
relationships and related transactions is set forth in the
definitive Proxy Statement under the heading Compensation
Committee Interlocks and Insider Participation and is
incorporated herein by reference.
|
|
Item 14
|
Principal
Accountant Fees and Services
|
The information required by this item is omitted pursuant to
Instruction G of
Form 10-K
since the Companys definitive Proxy Statement for its
February 15, 2007 Annual Meeting of Shareholders will be
filed with the SEC not later than 120 days after
September 30, 2006. The information concerning principal
accountant fees and services is set forth in the definitive
Proxy Statement under the heading Audit Fees and is
incorporated herein by reference.
PART IV
|
|
Item 15
|
Exhibits
and Financial Statement Schedules
|
(a)1. Financial
Statements
Financial statements filed as part of this report are listed in
the index included in Item 8 of this
Form 10-K,
and reference is made thereto.
(a)2. Financial
Statement Schedules
Financial statement schedules filed as part of this report are
listed in the index included in Item 8 of this
Form 10-K,
and reference is made thereto.
(a)3. Exhibits
|
|
|
|
|
Exhibit
|
|
Description of
|
Number
|
|
Exhibits
|
|
|
3(i)
|
|
|
Articles of Incorporation:
|
|
|
|
|
Restated Certificate of
Incorporation of National Fuel Gas Company dated
September 21, 1998 (Exhibit 3.1,
Form 10-K
for fiscal year ended September 30, 1998 in File
No. 1-3880)
|
|
|
|
|
Certificate of Amendment of
Restated Certificate of Incorporation (Exhibit 3(ii),
Form 8-K
dated March 14, 2005 in File No. 1-3880)
|
|
3(ii)
|
|
|
By-Laws:
|
|
|
|
|
National Fuel Gas Company By-Laws
as amended on December 9, 2004 (Exhibit 3(ii),
Form 8-K
dated December 9, 2004 in File No. 1-3880)
|
|
4
|
|
|
Instruments Defining the Rights of
Security Holders, Including Indentures:
|
|
|
|
|
Indenture, dated as of
October 15, 1974, between the Company and The Bank of New
York (formerly Irving Trust Company) (Exhibit 2(b) in File
No. 2-51796)
|
|
|
|
|
Third Supplemental Indenture,
dated as of December 1, 1982,to Indenture dated as of
October 15, 1974, between the Company and The Bank of New
York (formerly Irving Trust Company) (Exhibit 4(a)(4) in
File No.
33-49401)
|
|
|
|
|
Eleventh Supplemental Indenture,
dated as of May 1, 1992, to Indenture dated as of
October 15, 1974, between the Company and The Bank of New
York (formerly Irving Trust Company) (Exhibit 4(b),
Form 8-K
dated February 14, 1992 in File No. 1-3880)
|
116
|
|
|
|
|
Exhibit
|
|
Description of
|
Number
|
|
Exhibits
|
|
|
|
|
|
Twelfth Supplemental Indenture,
dated as of June 1, 1992, to Indenture dated as of
October 15, 1974, between the Company and The Bank of New
York (formerly Irving Trust Company) (Exhibit 4(c),
Form 8-K
dated June 18, 1992 in File No. 1-3880)
|
|
|
|
|
Thirteenth Supplemental Indenture,
dated as of March 1,1993, to Indenture dated as of
October 15, 1974, between the Company and The Bank of New
York (formerly Irving Trust Company) (Exhibit 4(a)(14) in
File No.
33-49401)
|
|
|
|
|
Fourteenth Supplemental Indenture,
dated as of July 1, 1993,to Indenture dated as of
October 15, 1974, between the Company and The Bank of New
York (formerly Irving Trust Company) (Exhibit 4.1,
Form 10-K
for fiscal year ended September 30, 1993 in File
No. 1-3880)
|
|
|
|
|
Fifteenth Supplemental Indenture,
dated as of September 1,1996, to Indenture dated as of
October 15, 1974, between the Company and The Bank of New
York (formerly Irving Trust Company) (Exhibit 4.1,
Form 10-K
for fiscal year ended September 30, 1996 in File
No. 1-3880)
|
|
|
|
|
Indenture dated as of
October 1, 1999, between the Company and The Bank of New
York (Exhibit 4.1,
Form 10-K
for fiscal year ended September 30, 1999 in File
No. 1-3880)
|
|
|
|
|
Officers Certificate Establishing
Medium-Term Notes, dated October 14, 1999
(Exhibit 4.2,
Form 10-K
for fiscal year ended September 30, 1999 in File
No. 1-3880)
|
|
|
|
|
Amended and Restated Rights
Agreement, dated as of April 30,1999, between the Company
and HSBC Bank USA
(Exhibit 10.2,Form 10-Q
for the quarterly period ended March 31, 1999 in File
No. 1-3880)
|
|
|
|
|
Certificate of Adjustment, dated
September 7, 2001, to the Amended and Restated Rights
Agreement dated as of April 30,1999, between the Company
and HSBC Bank USA (Exhibit 4, Form
8-K dated
September 7, 2001 in File No. 1-3880)
|
|
|
|
|
Officers Certificate establishing
6.50% Notes due 2022, dated September 18, 2002
(Exhibit 4,
Form 8-K
dated October 3, 2002 in File No. 1-3880)
|
|
|
|
|
Officers Certificate establishing
5.25% Notes due 2013, dated February 18, 2003
(Exhibit 4,
Form 10-Q
for the quarterly period ended March 31, 2003 in File
No. 1-3880)
|
|
10
|
|
|
Material Contracts:
|
|
|
|
|
Contracts other than compensatory
plans, contracts or arrangements:
|
|
|
|
|
Form of Indemnification Agreement,
dated September 2006, between the Company and each Director
(Exhibit 10.1,
Form 8-K
dated September 18, 2006 in File No. 1-3880)
|
|
|
|
|
Credit Agreement, dated as of
August 19, 2005, among the Company, the Lenders Party
Thereto and JPMorgan Chase Bank, N.A., as Administrative Agent
(Exhibit 10.1,
Form 10-K
for fiscal year ended September 30, 2005 in File
No. 1-3880)
|
|
|
|
|
Compensatory plans, contracts or
arrangements:
|
|
|
|
|
Form of Employment Continuation
and Noncompetition Agreement, dated as of December 11,
1998, among the Company, National Fuel Gas Distribution
Corporation and each of Philip C. Ackerman, Anna Marie Cellino,
Paula M, Ciprich, Donna L. DeCarolis, James D. Ramsdell, David
F. Smith and Ronald J. Tanski (Exhibit 10.1,
Form 10-Q
for the quarterly period ended June 30, 1999 in File
No. 1-3880)
|
|
|
|
|
Form of Employment Continuation
and Noncompetition Agreement, dated as of December 11,
1998, among the Company, National Fuel Gas Supply Corporation
and John R. Pustulka (Exhibit 10.2,
Form 10-Q
for the quarterly period ended June 30, 1999 in File
No. 1-3880)
|
|
|
|
|
National Fuel Gas Company 1993
Award and Option Plan, dated February 18, 1993
(Exhibit 10.1,
Form 10-Q
for the quarterly period ended March 31, 1993 in File
No. 1-3880)
|
|
|
|
|
Amendment to National Fuel Gas
Company 1993 Award and Option Plan, dated October 27, 1995
(Exhibit 10.8,
Form 10-K
for fiscal year ended September 30, 1995 in File
No. 1-3880)
|
|
|
|
|
Amendment to National Fuel Gas
Company 1993 Award and Option Plan, dated December 11, 1996
(Exhibit 10.8,
Form 10-K
for fiscal year ended September 30, 1996 in File
No. 1-3880)
|
|
|
|
|
Amendment to National Fuel Gas
Company 1993 Award and Option Plan, dated December 18, 1996
(Exhibit 10,
Form 10-Q
for the quarterly period ended December 31, 1996 in File
No. 1-3880)
|
117
|
|
|
|
|
Exhibit
|
|
Description of
|
Number
|
|
Exhibits
|
|
|
|
|
|
National Fuel Gas Company 1993
Award and Option Plan, amended through June 14, 2001
(Exhibit 10.1,
Form 10-K
for fiscal year ended September 30, 2001 in File
No. 1-3880)
|
|
|
|
|
National Fuel Gas Company 1993
Award and Option Plan, amended through September 8, 2005
(Exhibit 10.2,
Form 10-K
for fiscal year ended September 30, 2005 in File
No. 1-3880)
|
|
|
|
|
Administrative Rules with Respect
to At Risk Awards under the 1993 Award and Option Plan
(Exhibit 10.14,
Form 10-K
for fiscal year ended September 30, 1996 in File
No. 1-3880)
|
|
|
|
|
National Fuel Gas Company 1997
Award and Option Plan, amended through September 8, 2005
(Exhibit 10.3,
Form 10-K
for fiscal year ended September 30, 2005 in File
No. 1-3880)
|
|
|
|
|
Form of Award Notice under
National Fuel Gas Company 1997 Award and Option Plan
(Exhibit 10.1,
Form 8-K
dated March 28, 2005 in File No. 1-3880)
|
|
|
|
|
Form of Award Notice under
National Fuel Gas Company 1997 Award and Option Plan
(Exhibit 10.1,
Form 8-K
dated May 16, 2006 in File No. 1-3880)
|
|
|
|
|
Administrative Rules with Respect
to At Risk Awards under the 1997 Award and Option Plan amended
and restated as of September 8, 2005 (Exhibit 10.4,
Form 10-K
for fiscal year ended September 30, 2005 in File No. 1-3880)
|
|
|
|
|
Description of performance goals
for Chief Executive Officer under the Companys Annual At
Risk Compensation Incentive Program (Exhibit 10,
Form 10-Q
for the quarterly period ended December 31, 2004 in File
No. 1-3880)
|
|
|
|
|
Description of performance goals
for Chief Executive Officer under the Companys Annual At
Risk Compensation Incentive Program (Exhibit 10.2,
Form 10-Q
for the quarterly period ended December 31, 2005 in File
No. 1-3880)
|
|
|
|
|
Administrative Rules of the
Compensation Committee of the Board of Directors of National
Fuel Gas Company, as amended and restated, effective
March 9, 2005 (Exhibit 10.2,
Form 10-Q
for the quarterly period ended March 31, 2005 in File
No. 1-3880)
|
|
|
|
|
National Fuel Gas Company Deferred
Compensation Plan, as amended and restated through May 1,
1994 (Exhibit 10.7,
Form10-K for
fiscal year ended September 30, 1994 in File
No. 1-3880)
|
|
|
|
|
Amendment to National Fuel Gas
Company Deferred Compensation Plan, dated September 27,
1995 (Exhibit 10.9,
Form 10-K
for fiscal year ended September 30, 1995 in File
No. 1-3880)
|
|
|
|
|
Amendment to National Fuel Gas
Company Deferred Compensation Plan, dated September 19,
1996 (Exhibit 10.10,
Form 10-K
for fiscal year ended September 30, 1996 in File
No. 1-3880)
|
|
|
|
|
National Fuel Gas Company Deferred
Compensation Plan, as amended and restated through
March 20, 1997
(Exhibit 10.3,Form 10-K
for fiscal year ended September 30, 1997 in File
No. 1-3880)
|
|
|
|
|
Amendment to National Fuel Gas
Company Deferred Compensation Plan, dated June 16, 1997
(Exhibit 10.4,
Form 10-K
for fiscal year ended September 30, 1997 in File
No. 1-3880)
|
|
|
|
|
Amendment No. 2 to the
National Fuel Gas Company Deferred Compensation Plan, dated
March 13, 1998 (Exhibit 10.1,
Form10-K for
fiscal year ended September 30, 1998 in File
No. 1-3880)
|
|
|
|
|
Amendment to the National Fuel Gas
Company Deferred Compensation Plan, dated February 18, 1999
(Exhibit
10.1,Form 10-Q
for the quarterly period ended March 31, 1999 in File
No. 1-3880)
|
|
|
|
|
Amendment to National Fuel Gas
Company Deferred Compensation Plan, dated June 15, 2001
(Exhibit 10.3,
Form 10-K
for fiscal year ended September 30, 2001 in File
No. 1-3880)
|
|
|
|
|
Amendment to the National Fuel Gas
Company Deferred Compensation Plan, dated October 21, 2005
(Exhibit 10.5,
Form 10-K
for fiscal year ended September 30, 2005 in File
No. 1-3880)
|
|
|
|
|
Form of Letter Regarding Deferred
Compensation Plan and Internal Revenue Code Section 409A,
dated July 12, 2005 (Exhibit 10.6,
Form 10-K
for fiscal year ended September 30, 2005 in File
No. 1-3880)
|
|
|
|
|
National Fuel Gas Company Tophat
Plan, effective March 20, 1997 (Exhibit 10,
Form 10-Q
for the quarterly period ended June 30, 1997 in File
No. 1-3880)
|
|
|
|
|
Amendment No. 1 to National
Fuel Gas Company Tophat Plan, dated April 6, 1998
(Exhibit 10.2,
Form 10-K
for fiscal year ended September 30, 1998 in File
No. 1-3880)
|
118
|
|
|
|
|
Exhibit
|
|
Description of
|
Number
|
|
Exhibits
|
|
|
|
|
|
Amendment No. 2 to National
Fuel Gas Company Tophat Plan, dated December 10, 1998
(Exhibit 10.1,
Form 10-Q
for the quarterly period ended December 31, 1998 in File
No. 1-3880)
|
|
|
|
|
Form of Letter Regarding Tophat
Plan and Internal Revenue Code Section 409A, dated
July 12, 2005 (Exhibit 10.7,
Form 10-K
for fiscal year ended September 30, 2005 in File
No. 1-3880)
|
|
|
|
|
National Fuel Gas Company Tophat
Plan, Amended and Restated December 7, 2005
(Exhibit 10.1,
Form 10-Q
for the quarterly period ended December 31, 2005 in File
No. 1-3880)
|
|
|
|
|
Amended and Restated Split Dollar
Insurance and Death Benefit Agreement, dated September 17,
1997 between the Company and Philip C. Ackerman
(Exhibit 10.5,
Form 10-K
for fiscal year ended September 30, 1997 in File
No. 1-3880)
|
|
|
|
|
Amendment Number 1 to Amended
and Restated Split Dollar Insurance and Death Benefit Agreement
by and between the Company and Philip C. Ackerman, dated
March 23, 1999 (Exhibit 10.3,
Form 10-K
for fiscal year ended September 30, 1999 in File
No. 1-3880)
|
|
|
|
|
Amended and Restated Split Dollar
Insurance and Death Benefit Agreement, dated September 15,
1997, between the Company and Dennis J. Seeley
(Exhibit 10.9,
Form 10-K
for fiscal year ended September 30, 1999 in File No. 1-3880)
|
|
|
|
|
Amendment Number 1 to Amended
and Restated Split Dollar Insurance and Death Benefit Agreement
by and between the Company and Dennis J. Seeley, dated
March 29, 1999 (Exhibit 10.10,
Form 10-K
for fiscal year ended September 30, 1999 in File
No. 1-3880)
|
|
|
|
|
Split Dollar Insurance and Death
Benefit Agreement dated September 15, 1997, between the
Company and Bruce H. Hale (Exhibit 10.11,
Form 10-K
for fiscal year ended September 30, 1999 in File
No. 1-3880)
|
|
|
|
|
Amendment Number 1 to Split
Dollar Insurance and Death Benefit Agreement by and between the
Company and Bruce H. Hale, dated March 29, 1999
(Exhibit 10.12,
Form 10-K
for fiscal year ended September 30, 1999 in File
No. 1-3880)
|
|
|
|
|
Split Dollar Insurance and Death
Benefit Agreement, dated September 15, 1997, between the
Company and David F. Smith (Exhibit 10.13,
Form 10-K
for fiscal year ended September 30, 1999 in File
No. 1-3880)
|
|
|
|
|
Amendment Number 1 to Split
Dollar Insurance and Death Benefit Agreement by and between the
Company and David F. Smith, dated March 29, 1999
(Exhibit 10.14,
Form 10-K
for fiscal year ended September 30, 1999 in File
No. 1-3880)
|
|
|
|
|
National Fuel Gas Company
Parameters for Executive Life Insurance Plan (Exhibit 10.1,
Form 10-K
for fiscal year ended September 30, 2004 in File
No. 1-3880)
|
|
|
|
|
National Fuel Gas Company and
Participating Subsidiaries Executive Retirement Plan as amended
and restated through November 1, 1995 (Exhibit 10.10,
Form 10-K
for fiscal year ended September 30, 1995 in File No. 1-3880)
|
|
|
|
|
Amendments to National Fuel Gas
Company and Participating Subsidiaries Executive Retirement
Plan, dated September 18, 1997 (Exhibit 10.9,
Form 10-K
for fiscal year ended September 30, 1997 in File
No. 1-3880)
|
|
|
|
|
Amendments to National Fuel Gas
Company and Participating Subsidiaries Executive Retirement
Plan, dated December 10, 1998 (Exhibit 10.2,
Form 10-Q
for the quarterly period ended December 31, 1998 in File
No. 1-3880)
|
|
|
|
|
Amendments to National Fuel Gas
Company and Participating Subsidiaries Executive Retirement
Plan, effective September 16, 1999 (Exhibit 10.15,
Form 10-K
for fiscal year ended September 30, 1999 in File No. 1-3880)
|
|
|
|
|
Amendment to National Fuel Gas
Company and Participating Subsidiaries Executive Retirement
Plan, effective September 5, 2001 (Exhibit 10.4,
Form 10-K/A
for fiscal year ended September 30, 2001, in File
No. 1-3880)
|
|
|
|
|
National Fuel Gas Company and
Participating Subsidiaries 1996 Executive Retirement Plan Trust
Agreement (II), dated May 10, 1996 (Exhibit 10.13,
Form 10-K
for fiscal year ended September 30, 1996 in File No.
1-3880)
|
119
|
|
|
|
|
Exhibit
|
|
Description of
|
Number
|
|
Exhibits
|
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National Fuel Gas Company
Participating Subsidiaries Executive Retirement Plan 2003 Trust
Agreement (I), dated September 1, 2003 (Exhibit 10.2,
Form 10-K
for fiscal year ended September 30, 2004 in File No. 1-3880)
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National Fuel Gas Company
Performance Incentive Program (Exhibit 10.1,
Form 8-K
dated June 3, 2005 in File No. 1-3880)
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Excerpts of Minutes from the
National Fuel Gas Company Board of Directors Meeting of
March 20, 1997 regarding the Retainer Policy for
Non-Employee Directors (Exhibit 10.11,
Form 10-K
for fiscal year ended September 30, 1997 in File
No. 1-3880)
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Retirement Benefit Agreement for
David F. Smith, dated September 22, 2003,between the
Company and David F. Smith (Exhibit 10.2,
Form10-K for
fiscal year ended September 30, 2003 in File
No. 1-3880)
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Amendment No. 1 to the
Retirement Benefit Agreement for David F. Smith, dated
September 8, 2005, between the Company and David F. Smith
(Exhibit 10.8,
Form 10-K
for fiscal year ended September 30, 2005 in File No. 1-3880)
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Description of performance goals
for certain executive officers (Exhibit 10.1,
Form 10-Q
for the quarterly period ended March 31, 2005 in File
No. 1-3880)
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Retirement Agreement, dated
August 1, 2005, between the Company and Bruce H. Hale
(Exhibit 10.9,
Form 10-K
for fiscal year ended September 30, 2005 in File
No. 1-3880)
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Commission Agreement, dated
August 1, 2005, between the Company and Bruce H. Hale
(Exhibit 10.10,
Form 10-K
for fiscal year ended September 30, 2005 in File
No. 1-3880)
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Description of bonuses awarded to
executive officer (Exhibit 10.1,
Form 10-Q
for the quarterly period ended March 31, 2006 in File
No. 1-3880)
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Description of performance goals
for certain executive officers (Exhibit 10.2,
Form 10-Q
for the quarterly period ended March 31, 2006 in File
No. 1-3880)
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Noncompete and Restrictive
Covenant Agreement, dated February 1, 2006, between the
Company and Dennis J. Seeley (Exhibit 10.3,
Form 10-Q
for the quarterly period ended March 31, 2006 in File
No. 1-3880)
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Description of salaries of certain
executive officers (Exhibit 10.4,
Form 10-Q
for the quarterly period ended March 31, 2006 in File
No. 1-3880)
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Description of assignment of
interests in certain life insurance policies (Exhibit 10.1,
Form 10-Q
for the quarterly period ended June 30, 2006 in File
No. 1-3880)
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Description of long-term
performance incentives under the National Fuel Gas Company
Performance Incentive Program (Exhibit 10.2,
Form 10-Q
for the quarterly period ended June 30, 2006 in File
No. 1-3880)
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Description of agreement between
the Company and Philip C. Ackerman regarding death benefit
(Exhibit 10.3,
Form 10-Q
for the quarterly period ended June 30, 2006 in File
No. 1-3880)
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10
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.1
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Agreement, dated
September 24, 2006, between the Company and Philip C.
Ackerman regarding death benefit
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Retirement Agreement, dated
July 1, 2006, between the Company and James A. Beck
(Exhibit 10.4,
Form 10-Q
for the quarterly period ended June 30, 2006 in File
No. 1-3880)
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Contract for Consulting Services,
dated July 1, 2006, between the Company and James A. Beck
(Exhibit 10.5,
Form 10-Q
for the quarterly period ended June 30, 2006 in File
No. 1-3880)
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12
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Statements regarding Computation
of Ratios: Ratio of Earnings to Fixed Charges for the fiscal
years ended September 30, 2002 through 2006
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21
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Subsidiaries of the Registrant:
See Item 1 of Part I of this Annual Report on
Form 10-K
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23
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Consents of Experts:
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23
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.1
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Consent of Ralph E. Davis
Associates, Inc. regarding Seneca Resources Corporation
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23
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.2
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Consent of Ralph E. Davis
Associates, Inc. regarding Seneca Energy Canada, Inc.
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23
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.3
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Consent of Independent Registered
Public Accounting Firm
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31
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Rule 13a-15(e)/15d-15(e)
Certifications
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120
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Exhibit
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Description of
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Number
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Exhibits
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31
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.1
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Written statements of Chief
Executive Officer pursuant to
Rule 13a-15(e)/15d-15(e)
of the Exchange Act.
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31
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.2
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Written statements of Principal
Financial Officer pursuant to
Rule 13a-15(e)/15d-15(e)
of the Exchange Act.
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32
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Certifications pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002
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99
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Additional Exhibits:
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99
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.1
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Report of Ralph E. Davis
Associates, Inc. regarding Seneca Resources Corporation
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99
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.2
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Report of Ralph E. Davis
Associates, Inc. regarding Seneca Energy Canada, Inc.
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99
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.3
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Company Maps
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The Company agrees to furnish to
the SEC upon request the following instruments with respect to
long-term debt that the Company has not filed as an exhibit
pursuant to the exemption provided by
Item 601(b)(4)(iii)(A):
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Secured Credit Agreement, dated as
of June 5, 1997, among the Empire State Pipeline, as
borrower, Empire State Pipeline, Inc., the Lenders party
thereto, JPMorgan Chase Bank (f/k/a The Chase Manhattan Bank),
as administrative agent, and Chase Securities, as arranger.
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First Amendment to Secured Credit
Agreement, dated as of May 28, 2002, among Empire State
Pipeline, as borrower, Empire State Pipeline, Inc., St. Clair
Pipeline Company, Inc., the Lenders party to the Secured Credit
Agreement, and JPMorgan Chase Bank, as administrative agent.
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Second Amendment to Secured Credit
Agreement, dated as of February 6, 2003, among Empire State
Pipeline, as borrower, Empire State Pipeline, Inc., St. Clair
Pipeline Company, Inc., the Lenders party to the Secured Credit
Agreement, as amended, and JPMorgan Chase Bank, as
administrative agent.
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Incorporated herein by reference
as indicated.
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All other exhibits are omitted
because they are not applicable or the required information is
shown elsewhere in this Annual Report on
Form 10-K.
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In accordance with
Item 601(b) (32) (ii) of
Regulation S-K
and SEC Release Nos.
33-8238 and
34-47986, Final Rule: Managements Reports on Internal
Control Over Financial Reporting and Certification of Disclosure
in Exchange Act Periodic Reports, the material contained in
Exhibit 32 is furnished and not deemed
filed with the SEC and is not to be
incorporated by reference into any filing of the Registrant
under the Securities Act of 1933 or the Exchange Act, whether
made before or after the date hereof and irrespective of any
general incorporation language contained in such filing, except
to the extent that the Registrant specifically incorporates it
by reference.
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121
Signatures
Pursuant to the requirements of Section 13 or 15(d) of the
Securities Exchange Act of 1934, the registrant has duly caused
this report to be signed on its behalf by the undersigned,
thereunto duly authorized.
National Fuel Gas Company
(Registrant)
P. C. Ackerman
Chairman of the Board and Chief Executive Officer
Date: December 7, 2006
Pursuant to the requirements of the Securities Exchange Act of
1934, this report has been signed below by the following persons
on behalf of the registrant and in the capacities and on the
dates indicated.
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Signature
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Title
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/s/ P.
C.
Ackerman P.
C. Ackerman
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Chairman of the Board, Chief
Executive Officer and Director
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Date: December 7, 2006
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/s/ R.
T.
Brady R.
T. Brady
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Director
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Date: December 7, 2006
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/s/ R.
D.
Cash R.
D. Cash
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Director
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Date: December 7, 2006
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/s/ R.
E.
Kidder R.
E. Kidder
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Director
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Date: December 7, 2006
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/s/ C.
G.
Matthews C.
G. Matthews
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Director
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Date: December 7 2006
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/s/ G.
L.
Mazanec G.
L. Mazanec
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Director
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Date: December 7, 2006
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/s/ R.
G.
Reiten R.
G. Reiten
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Director
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Date: December 7, 2006
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/s/ J.
F.
Riordan J.
F. Riordan
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Director
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Date: December 7, 2006
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/s/ R.
J.
Tanski R.
J. Tanski
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Treasurer and Principal Financial
Officer
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Date: December 7, 2006
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/s/ K.
M.
Camiolo K.
M. Camiolo
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Controller and Principal
Accounting Officer
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Date: December 7, 2006
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122