National Fuel Gas Company 10-k
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, 2007
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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
(State or other jurisdiction
of
incorporation or organization)
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13-1086010
(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. þ
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 $3,540,898,000 as of
March 31, 2007.
Common Stock, $1 Par Value, outstanding as of
October 31, 2007: 83,473,107 shares.
DOCUMENTS
INCORPORATED BY REFERENCE
Portions of the registrants definitive Proxy Statement for
its 2008 Annual Meeting of Stockholders are incorporated by
reference into Part III of this report.
Glossary
of Terms
Frequently used abbreviations,
acronyms, or terms used in this report:
National
Fuel Gas Companies
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.
Regulatory
Agencies
EPA
United States
Environmental Protection Agency
FASB
Financial Accounting
Standards Board
FERC
Federal Energy
Regulatory Commission
NTSB
National Transportation
Safety Board
NYDEC
New York State
Department of Environmental Conservation
NYPSC
State of New York Public
Service Commission
PaPUC
Pennsylvania Public
Utility Commission
SEC
Securities and Exchange
Commission
Other
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)
Bcfe (or Mcfe)
represents 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.
Exchange Act
Securities Exchange Act
of 1934, as amended
Expenditures for long-lived
assets Includes capital
expenditures, stock acquisitions and/or investments in
partnerships.
Exploitation
Development of a field,
including the location, drilling, completion and equipment of
wells necessary to produce the commercially recoverable oil and
gas in the field.
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.
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.
SAR
Stock-settled stock
appreciation right
SFAS Statement
of Financial Accounting Standards
SFAS 5
Statement of Financial
Accounting Standards No. 5, Accounting for Contingencies
SFAS 43
Statement of Financial
Accounting Standards No. 43, Accounting for Compensated
Absences
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 112
Statement of Financial
Accounting Standards No. 112, Employers Accounting
for Postemployment Benefits, an amendment of SFAS 5 and 43
SFAS 115
Statement of Financial
Accounting Standards No. 115, Accounting for Certain
Investments in Debt and Equity Securities
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 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
SFAS 159
Statement of Financial
Accounting Standards No. 159, The Fair Value Option for
Financial Assets and Financial Liabilities Including
an Amendment of SFAS 115
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, 2007
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, statements regarding future
prospects, plans, performance and capital structure, anticipated
capital expenditures, completion of construction projects,
projections for pension and other post-retirement benefit
obligations, impacts of the adoption of new accounting rules,
and possible outcomes of litigation or regulatory proceedings,
as well as statements that are identified by the use of the
words anticipates, estimates,
expects, forecasts, intends,
plans, predicts, projects,
believes, seeks, will, and
may and similar expressions.
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 725,000 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. Supply
Corporation is in the process of shutting down one of its
smallest storage fields, which accounts for less than one
percent of its marketable storage capacity. Empire, an
intrastate pipeline company acquired by the Company in February
2003, 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. Empire is constructing the Empire Connector project, which
consists of a compressor station and a
78-mile
pipeline extension from near Rochester, New York to an
interconnection near Corning, New York with the unaffiliated
Millennium Pipeline, which is also under construction. The
Millennium Pipeline is expected to serve the New York City area
upon its completion. Upon completion of the Empire and
Millennium construction projects, which is currently expected to
occur in November 2008, the Company expects that Empire will
become an interstate pipeline company and will merge into Empire
Pipeline, Inc. as described below.
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, in Wyoming, and in the Gulf Coast region of Texas,
Louisiana, and Alabama, including offshore areas in federal
waters and some state waters.
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In 2007, Seneca sold its subsidiary, Seneca Energy Canada Inc.
(SECI), which conducted Exploration and Production operations in
the provinces of Alberta, Saskatchewan and British Columbia in
Canada. At September 30, 2007, the Company had
U.S. reserves of 47,586 Mbbl of oil and 205,389 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.
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, 2007,
the Company owned 103,700 acres of timber property and
managed an additional 3,105 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 2007.
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.
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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.
The FERC has authorized Empire to construct and operate
additional facilities (the Empire Connector project) and to
become a FERC-regulated interstate pipeline company upon
placement of those facilities into service, which is currently
expected to occur in November 2008. 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 contributed approximately 25.2% of the
Companys 2007 income from continuing operations and 15.1%
of the Companys 2007 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 28.0%
of the Companys 2007 income from continuing operations and
16.7% of the Companys 2007 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. A majority of Supply Corporations storage and
transportation services is 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 2008, 66.9% of Supply Corporations total firm
storage capacity was committed under contracts that, subject to
2007 shipper or Supply Corporation notifications, could have
been terminated effective in 2008. Supply Corporation received
one termination notice in 2007, for a 1.5 Bcf storage contract.
Termination of that contract will be effective March 31,
2008, and Supply Corporation expects to remarket that capacity
for service commencing April 1, 2008, at maximum tariff
rates. The strong demand for market-area storage enabled Supply
Corporation to eliminate its remaining storage service rate
discounts in 2007. Supply Corporation anticipates that,
effective April 1, 2008, all of its storage services will
be contracted at the maximum tariff rates.
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
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point combinations. Supply Corporation currently has firm
transportation service agreements for approximately 2,001 MDth
per day (contracted transportation capacity). The Utility
segment accounts for approximately 1,093 MDth per day or 54.6%
of contracted transportation capacity, and the Energy Marketing
and Exploration and Production segments represent another 100
MDth per day or 5.0% of contracted transportation capacity. The
remaining 808 MDth or 40.4% of contracted transportation
capacity is subject to firm contracts with nonaffiliated
customers.
At the beginning of 2008, 58.0% of Supply Corporations
contracted transportation capacity was committed under affiliate
contracts that were scheduled to expire in 2008 or, subject to
2007 shipper or Supply Corporation notifications, could have
been terminated effective in 2008. Based on contract expirations
and termination notices received in 2007 for 2008 termination,
and taking into account any known contract additions, contracted
transportation capacity with affiliates is expected to decrease
2.5% in 2008. Similarly, 24.3% of contracted transportation
capacity was committed under unaffiliated shipper contracts that
were scheduled to expire in 2008 or, subject to 2007 shipper or
Supply Corporation notifications, could have been terminated
effective in 2008. Based on contract expirations and termination
notices received in 2007 for 2008 termination, and taking into
account any known contract additions, contracted transportation
capacity with unaffiliated shippers is expected to increase 2.1%
in 2008. Supply Corporation previously has been successful in
marketing and obtaining executed contracts for available
transportation capacity (at discounted rates when necessary),
and expects this success to continue.
Empire has service agreements for the
2007-2008
winter period for all of its firm transportation capacity, which
totals approximately 565 MDth per day. Empire provides service
under both annual contracts (service 12 months per year;
contract term one or more years) and seasonal contracts (service
during winter or summer only; contract term one or more partial
years). Approximately 90.8% of Empires firm contracted
capacity is under multi-year annual contracts that expire after
2008. Approximately 2.7% of Empires firm contracted
capacity is under multi-year seasonal contracts that expire
after 2008. The remaining capacity, which represents 6.5% of
Empires firm contracted capacity, is under single season
or annual contracts which will expire before the end of 2008.
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 7.7% of Empires firm
contracted capacity, and the Energy Marketing segment accounts
for approximately 2.0% of Empires firm contracted
capacity, with the remaining 90.3% 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
37.1% of the Companys 2007 income from continuing
operations and 62.4% of the Companys 2007 net income
available for common stock.
Additional discussion of the Exploration and Production segment
appears below under the headings Discontinued
Operations, 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 3.8% of
the Companys 2007 income from continuing operations and
2.3% of the Companys 2007 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.
6
The Timber segment contributed approximately 1.9% of the
Companys 2007 income from continuing operations and 1.1%
of the Companys 2007 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.
All
Other Category and Corporate Operations
The All Other category and Corporate operations contributed
approximately 4.0% of the Companys 2007 income from
continuing operations and 2.4% of the Companys
2007 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.
In August 2007, Seneca sold all of the issued and outstanding
shares of SECI. SECIs operations are presented in the
Companys financial statements as 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 2007, the Utility segment purchased 79.6 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 85% of these
purchases. Purchases of gas on the spot market (contracts for
one month or less) accounted for 15% of the Utility
segments 2007 purchases. Purchases from Chevron Natural
Gas (21%), ConocoPhillips Company (15%) and Total
Gas & Power North America Inc. (14%) accounted for 50%
of the Utilitys 2007 gas purchases. No other producer or
supplier provided the Utility segment with more than 10% of its
gas requirements in 2007.
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. Forty-nine percent of the timber processed during
2007 in Highlands sawmill operations came from land owned
by the Companys subsidiaries, and 51% came from outside
sources. Timber cut for gas well drilling locations, access
roads, and pipelines constituted an increasing portion of
Highlands timber supply, both from land owned by the
Companys subsidiaries and from outside sources. In
addition, Highland purchased approximately 6.5 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 2007, this segment
purchased 53 Bcf of natural gas, of which 51 Bcf
served core market demands. The remaining
7
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 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.
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, 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. A decision by the PaPUC on retail competition matters
remains pending.
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 in its most vulnerable markets (the
large commercial and industrial markets) by offering unbundled,
flexible services. The Utility segment continues to develop or
promote new sources and uses of natural gas or new services,
rates and contracts. The Utility segment also emphasizes and
provides 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.
8
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 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
constructing the Empire Connector project, which will expand its
natural gas pipeline and enable Empire 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.
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, Seneca 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.
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, which can have a moderate effect on its revenues.
Empires allowed rates currently 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. When Empire becomes a
FERC-regulated interstate pipeline company (which is currently
expected to occur in November 2008), Empires allowed
rates, like Supply Corporations, will be based on a
9
straight fixed-variable design. Under that rate design,
weather-related variations in transportation volumes will not
materially affect revenues.
Variations in weather conditions materially affect the volume of
gas consumed by customers of the Energy Marketing segment.
Volume variations 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 lower-grade or lower value trees from timber stands
to encourage the growth of higher-grade or higher value trees.
A discussion of capital expenditures by business segment is
included in Item 7, MD&A under the heading
Investing Cash Flow.
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.
The Company and its wholly owned or majority-owned subsidiaries
had a total of 1,952 full-time employees at
September 30, 2007. Excluding the 23 employees the
Company had in its Canadian operations at SECI, this is a
decrease of approximately one percent from the
1,970 employees in the Companys U.S. operations
at September 30, 2006.
Agreements covering employees in collective bargaining units in
New York are scheduled to expire in February 2008. The Company
has reached new agreements with the local leadership of those
collective bargaining units, and the members of each collective
bargaining unit have either approved their respective new
agreement or are scheduled to vote on their respective new
agreement in December 2007. The new agreements provide for an
effective date of February 2008 and an expiration date of
February 2013. 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.
10
Executive
Officers of the Company as of November 15, 2007 (except as
otherwise noted)(1)
|
|
|
|
|
Current Company
|
|
|
Positions and
|
|
|
Other Material
|
|
|
Business Experience
|
Name and Age (as of
|
|
During Past
|
November 15, 2007)
|
|
Five Years
|
|
Philip C. Ackerman
(63)
|
|
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.
|
David F. Smith
(54)
|
|
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.
|
Ronald J. Tanski
(55)
|
|
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;
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.
|
Matthew D. Cabell
(49)
|
|
President of Seneca since December 2006. Prior to joining
Seneca, Mr. Cabell served as Executive Vice President and
General Manager of Marubeni Oil & Gas (USA) Inc., an
exploration and production company, from June 2003 to December
2006. From January 2002 to June 2003, Mr. Cabell served as a
consultant assisting oil companies in upstream acquisition and
divestment transactions as well as Gulf of Mexico entry
strategy, first as an independent consultant and then as Vice
President of Randall & Dewey, Inc., a major oil and gas
transaction advisory firm. Mr. Cabells prior
employers are not subsidiaries or affiliates of the Company.
|
Karen M. Camiolo
(48)
|
|
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.
|
Anna Marie Cellino
(54)
|
|
Secretary of the Company since October 1995; Secretary of
Distribution Corporation since September 1999; Senior Vice
President of Distribution Corporation since July 2001.
|
Paula M. Ciprich
(47)
|
|
General Counsel of the Company since January 2005; Assistant
Secretary of Distribution Corporation since February 1997.
|
Donna L. DeCarolis
(48)
|
|
Vice President Business Development of the Company since October
2007. Ms. DeCarolis previously served as President of NFR
from January 2005 to October 2007; Secretary of NFR from March
2002 to October 2007; and Vice President of NFR from May 2001 to
January 2005.
|
John R. Pustulka
(55)
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Senior Vice President of Supply Corporation since July 2001.
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James D. Ramsdell
(52)
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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
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 relies upon shorter term
bank borrowings and commercial paper to finance a portion of its
operations. National Fuel is dependent on these capital sources
to provide capital to its subsidiaries to allow them to acquire,
maintain 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. 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 increased costs (including
costs that may be incurred in connection with governmental
investigations or
12
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, to
permit consumer choice of natural gas suppliers. The early
programs instituted to comply with the Act have not resulted in
significant change, 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,
and customer choice activities increased in Distribution
Corporations New York service territory. In April 2007,
the NYPSC, noting that the retail energy marketplace in New York
is established and continuing to expand, commenced a review to
determine if existing programs initially designed to promote
competition had outlived their usefulness and whether the cost
of programs currently funded by utility rate payers should be
shifted to market competitors. Increased retail choice
activities, to the extent they occur, 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.
(The FERC has authorized Empire to construct and operate
additional facilities (the Empire Connector project). When
Empire completes construction 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 although National Fuel expects to do so
in the future, it may not be able to access the markets for such
borrowings at attractive interest rates or at all. 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
13
have trouble paying the resulting higher bills, and Distribution
Corporations bad debt expenses may increase and ultimately
reduce earnings.
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 exploration and
production 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 as well as its fixed price
purchase and sale commitments.
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 80% 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, the Energy
Marketing segment enters into certain hedging arrangements,
primarily with respect to its fixed price purchase and sales
commitments and its volumes of gas stored underground. National
Fuels Pipeline and Storage segment enters into hedging
arrangements with respect to certain sales of efficiency gas,
and the All Other category has hedging arrangements in place
with respect to certain volumes of landfill gas committed for
sale.
Under the applicable accounting rules, the Companys
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,
assumptions regarding the levels of production that will be
achieved and, with regard to fixed price commitments,
assumptions regarding the creditworthiness of certain customers
and their forecasted consumption of natural gas. Depending on
market conditions for natural
14
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. These
parties might not be able to perform their obligations under the
hedge arrangements.
It is National Fuels policy that the use of commodity
derivatives contracts comply with various restrictions in effect
in respective business segments. For example, in the Exploration
and Production segment, commodity derivatives contracts must be
confined to the price hedging of existing and forecast
production, and in the Energy Marketing segment, commodity
derivatives with respect to fixed price purchase and sales
commitments must be matched against commitments reasonably
certain to be fulfilled. Similar restrictions apply in the
Pipeline and Storage segment and the All Other category.
National Fuel maintains a system of internal controls to monitor
compliance with its policy. However, unauthorized speculative
trades, if they were to occur, could expose National Fuel to
substantial losses to cover positions in its derivatives
contracts. In addition, in the event the Companys actual
production of oil and natural gas 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
15
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 and abandonment 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 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 oil and 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 (as adjusted for hedging). If, at
the end of any quarter, the amount of the unamortized investment
exceeds the net present value of the projected future cash
flows, 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. National Fuels Exploration and
Production segment last recorded an impairment charge under the
full cost method of accounting in 2006. 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 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
16
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 in its various segments are
subject to inherent hazards and risks such as: fires; natural
disasters; explosions; geological formations with abnormal
pressures; blowouts during well drilling; 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 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 the significant cost of insurance coverage for named
windstorms in the Gulf of Mexico, National Fuel determined that
it was not economical to purchase insurance to fully cover its
exposures related to such storms. It is possible that named
windstorms in the Gulf of Mexico could have a material adverse
effect on National Fuels results of operations, financial
condition and cash flows.
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
17
General
Information on Facilities
The net investment of the Company in property, plant and
equipment was $2.9 billion at September 30, 2007.
Approximately 62% 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 (34%), is
primarily located in California, in the Appalachian region of
the United States, in Wyoming, and in the Gulf Coast region of
Texas, Louisiana, and Alabama. The remaining net investment in
property, plant and equipment consisted 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
$33.7 million, or 1.2%, since 2002. During 2007, the
Company sold SECI, Senecas wholly owned subsidiary that
operated in Canada. The net property, plant and equipment of
SECI at the date of sale was $107.7 million. In addition,
during 2005, the Company 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, 2007. The
net investment in its gas distribution network (including
14,813 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, 2007.
The Pipeline and Storage segment had a net investment of
$681.9 million in property, plant and equipment at
September 30, 2007. Transmission pipeline represents 33% of
this segments total net investment and includes
2,495 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 441 miles of pipeline.
Net investment in storage facilities includes $89.8 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 75,404 installed
compressor horsepower that represent 14% 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 $982.7 million at
September 30, 2007.
The Timber segment had a net investment in property, plant and
equipment of $89.9 million at September 30, 2007.
Located primarily in northwestern Pennsylvania, the net
investment includes two sawmills, 103,700 acres of land and
timber, and 3,105 acres of timber rights.
The Utility and Pipeline and Storage segments facilities
provided the capacity to meet the Companys 2007 peak day
sendout, including transportation service, of 1,743 MMcf,
which occurred on February 5, 2007. Withdrawals from
storage of 779.3 MMcf provided approximately 44.7% of the
requirements on that day.
Company maps are included in exhibit 99.2 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, in
Wyoming, and in the Gulf Coast region of Texas, Louisiana, and
Alabama. Also, Exploration and Production operations were
conducted in the provinces of Alberta, Saskatchewan and British
Columbia in Canada, until the sale of these properties on
August 31, 2007. Further discussion of the sale of the
Canadian oil and gas properties is included in Item 8,
Note-I-Discontinued Operations. 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
18
and undeveloped reserve information for Seneca. Senecas
proved developed and undeveloped natural gas reserves decreased
from 233 Bcf at September 30, 2006 to 205 Bcf at
September 30, 2007. This decrease is attributed primarily
to the sale of the Canadian gas properties (40.1 Bcf) and
production of 26.3 Bcf. These decreases were partially
offset by extensions and discoveries of 34.6 Bcf, primarily
in the Appalachian region (29.7 Bcf). Senecas proved
developed and undeveloped oil reserves decreased from 58,018
Mbbl at September 30, 2006 to 47,586 Mbbl at
September 30, 2007. This decrease is attributed to
revisions of previous estimates (5,963 Mbbl), primarily
occurring in California, production (3,450 Mbbl) and the sale of
the Canadian oil properties (1,458 Mbbl). 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 is 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 is attributed mostly to
production.
Senecas oil and gas reserves reported in Item 8 at
Note O as of September 30, 2007 were estimated by
Senecas geologists and engineers and were audited by
independent petroleum engineers from Netherland, Sewell &
Associates, Inc. Seneca reports its oil and gas reserve
information on an annual basis to the Energy Information
Administration (EIA), a statistical agency of the
U.S. Department of Energy. The oil and gas reserve
information reported to the EIA showed 211 Bcf and 59,246
Mbbl of gas and oil reserves, respectively, which differs from
the reserve information summarized in Item 8 at
Note O. The reasons for this difference are as follows:
(a) reserves are reported to the EIA on a calendar year
basis, while reserves disclosed in Item 8 at Note O
are shown on a fiscal year basis; (b) reserves reported to
the EIA include only properties operated by Seneca, while
reserves disclosed in Item 8 at Note O included both
Seneca operated properties and non-operated properties in which
Seneca has an interest; and (c) reserves are reported to
the EIA on a gross basis verses the reserves disclosed in
Item 8 at Note O, which are reported on a net revenue
interest basis.
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
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
United States
|
|
|
|
|
|
|
|
|
|
|
|
|
Gulf Coast Region
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Sales Price per Mcf of Gas
|
|
$
|
6.58
|
|
|
$
|
8.01
|
|
|
$
|
7.05
|
|
Average Sales Price per Barrel of Oil
|
|
$
|
63.04
|
|
|
$
|
64.10
|
|
|
$
|
49.78
|
|
Average Sales Price per Mcf of Gas (after hedging)
|
|
$
|
6.87
|
|
|
$
|
5.89
|
|
|
$
|
6.01
|
|
Average Sales Price per Barrel of Oil (after hedging)
|
|
$
|
64.09
|
|
|
$
|
47.46
|
|
|
$
|
35.03
|
|
Average Production (Lifting) Cost per Mcf Equivalent of Gas and
Oil Produced
|
|
$
|
1.08
|
|
|
$
|
0.86
|
|
|
$
|
0.71
|
|
Average Production per Day (in MMcf Equivalent of Gas and Oil
Produced)
|
|
|
40
|
|
|
|
36
|
|
|
|
50
|
|
West Coast Region
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Sales Price per Mcf of Gas
|
|
$
|
6.54
|
|
|
$
|
7.93
|
|
|
$
|
6.85
|
|
Average Sales Price per Barrel of Oil
|
|
$
|
56.86
|
|
|
$
|
56.80
|
|
|
$
|
42.91
|
|
Average Sales Price per Mcf of Gas (after hedging)
|
|
$
|
6.82
|
|
|
$
|
7.19
|
|
|
$
|
6.15
|
|
Average Sales Price per Barrel of Oil (after hedging)
|
|
$
|
47.43
|
|
|
$
|
37.69
|
|
|
$
|
23.01
|
|
Average Production (Lifting) Cost per Mcf Equivalent of Gas and
Oil Produced
|
|
$
|
1.54
|
|
|
$
|
1.35
|
|
|
$
|
1.15
|
|
19
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For The Year Ended September 30
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
Average Production per Day (in MMcf Equivalent of Gas and Oil
Produced)
|
|
|
50
|
|
|
|
53
|
|
|
|
53
|
|
Appalachian Region
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Sales Price per Mcf of Gas
|
|
$
|
7.48
|
|
|
$
|
9.53
|
|
|
$
|
7.60
|
|
Average Sales Price per Barrel of Oil
|
|
$
|
62.26
|
|
|
$
|
65.28
|
|
|
$
|
48.28
|
|
Average Sales Price per Mcf of Gas (after hedging)
|
|
$
|
8.25
|
|
|
$
|
8.90
|
|
|
$
|
7.01
|
|
Average Sales Price per Barrel of Oil (after hedging)
|
|
$
|
62.26
|
|
|
$
|
65.28
|
|
|
$
|
48.28
|
|
Average Production (Lifting) Cost per Mcf Equivalent of Gas and
Oil Produced
|
|
$
|
0.69
|
|
|
$
|
0.69
|
|
|
$
|
0.63
|
|
Average Production per Day (in MMcf Equivalent of Gas and Oil
Produced)
|
|
|
17
|
|
|
|
15
|
|
|
|
13
|
|
Total United States
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Sales Price per Mcf of Gas
|
|
$
|
6.82
|
|
|
$
|
8.42
|
|
|
$
|
7.13
|
|
Average Sales Price per Barrel of Oil
|
|
$
|
58.43
|
|
|
$
|
58.47
|
|
|
$
|
44.87
|
|
Average Sales Price per Mcf of Gas (after hedging)
|
|
$
|
7.25
|
|
|
$
|
7.02
|
|
|
$
|
6.26
|
|
Average Sales Price per Barrel of Oil (after hedging)
|
|
$
|
51.68
|
|
|
$
|
40.26
|
|
|
$
|
26.59
|
|
Average Production (Lifting) Cost per Mcf Equivalent of Gas and
Oil Produced
|
|
$
|
1.23
|
|
|
$
|
1.09
|
|
|
$
|
0.90
|
|
Average Production per Day (in MMcf Equivalent of Gas and Oil
Produced)
|
|
|
108
|
|
|
|
104
|
|
|
|
117
|
|
Canada Discontinued Operations
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Sales Price per Mcf of Gas
|
|
$
|
6.09
|
|
|
$
|
7.14
|
|
|
$
|
6.15
|
|
Average Sales Price per Barrel of Oil
|
|
$
|
50.06
|
|
|
$
|
51.40
|
|
|
$
|
42.97
|
|
Average Sales Price per Mcf of Gas (after hedging)
|
|
$
|
6.17
|
|
|
$
|
7.47
|
|
|
$
|
6.14
|
|
Average Sales Price per Barrel of Oil (after hedging)
|
|
$
|
50.06
|
|
|
$
|
51.40
|
|
|
$
|
42.97
|
|
Average Production (Lifting) Cost per Mcf Equivalent of Gas and
Oil Produced
|
|
$
|
1.94
|
|
|
$
|
1.57
|
|
|
$
|
1.29
|
|
Average Production per Day (in MMcf Equivalent of Gas and Oil
Produced)
|
|
|
21
|
|
|
|
26
|
|
|
|
27
|
|
Total Company
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Sales Price per Mcf of Gas
|
|
$
|
6.64
|
|
|
$
|
8.04
|
|
|
$
|
6.86
|
|
Average Sales Price per Barrel of Oil
|
|
$
|
57.93
|
|
|
$
|
57.94
|
|
|
$
|
44.72
|
|
Average Sales Price per Mcf of Gas (after hedging)
|
|
$
|
6.98
|
|
|
$
|
7.15
|
|
|
$
|
6.23
|
|
Average Sales Price per Barrel of Oil (after hedging)
|
|
$
|
51.58
|
|
|
$
|
41.10
|
|
|
$
|
27.86
|
|
Average Production (Lifting) Cost per Mcf Equivalent of Gas and
Oil Produced
|
|
$
|
1.35
|
|
|
$
|
1.18
|
|
|
$
|
0.98
|
|
Average Production per Day (in MMcf Equivalent of Gas and Oil
Produced)
|
|
|
129
|
|
|
|
130
|
|
|
|
144
|
|
Productive
Wells
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gulf Coast
|
|
|
West Coast
|
|
|
Appalachian
|
|
|
|
|
|
|
Region
|
|
|
Region
|
|
|
Region
|
|
|
Total Company
|
|
At September 30, 2007
|
|
Gas
|
|
|
Oil
|
|
|
Gas
|
|
|
Oil
|
|
|
Gas
|
|
|
Oil
|
|
|
Gas
|
|
|
Oil
|
|
|
Productive Wells Gross
|
|
|
33
|
|
|
|
37
|
|
|
|
|
|
|
|
1,313
|
|
|
|
2,347
|
|
|
|
7
|
|
|
|
2,380
|
|
|
|
1,357
|
|
Productive Wells Net
|
|
|
19
|
|
|
|
16
|
|
|
|
|
|
|
|
1,305
|
|
|
|
2,274
|
|
|
|
6
|
|
|
|
2,293
|
|
|
|
1,327
|
|
20
Developed
and Undeveloped Acreage
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Golf
|
|
|
West
|
|
|
|
|
|
|
|
|
|
Coast
|
|
|
Coast
|
|
|
Appalachian
|
|
|
Total
|
|
At September 30, 2007
|
|
Region
|
|
|
Region
|
|
|
Region
|
|
|
Company
|
|
|
Developed Acreage
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross
|
|
|
141,425
|
|
|
|
11,058
|
|
|
|
515,400
|
|
|
|
667,883
|
|
Net
|
|
|
97,756
|
|
|
|
10,688
|
|
|
|
488,907
|
|
|
|
597,351
|
|
Undeveloped Acreage
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross
|
|
|
148,960
|
|
|
|
|
|
|
|
472,407
|
|
|
|
621,367
|
|
Net
|
|
|
89,921
|
|
|
|
|
|
|
|
447,802
|
|
|
|
537,723
|
|
As of September 30, 2007, the aggregate amount of gross
undeveloped acreage expiring in the next three years and
thereafter are as follows: 23,332 acres in 2008
(12,707 net acres), 38,741 acres in 2009
(23,219 net acres), 23,038 acres in 2010
(11,491 net acres), and 536,256 acres thereafter
(490,306 net acres).
Drilling
Activity
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive
|
|
|
Dry
|
|
For the Year Ended September 30
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
United States
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gulf Coast Region
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Wells Completed
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploratory
|
|
|
1.31
|
|
|
|
2.94
|
|
|
|
1.30
|
|
|
|
1.42
|
|
|
|
0.85
|
|
|
|
0.47
|
|
Development
|
|
|
1.00
|
|
|
|
0.78
|
|
|
|
0.23
|
|
|
|
0.67
|
|
|
|
|
|
|
|
|
|
West Coast Region
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Wells Completed
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploratory
|
|
|
0.50
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Development
|
|
|
58.99
|
|
|
|
92.98
|
|
|
|
116.97
|
|
|
|
2.00
|
|
|
|
1.00
|
|
|
|
|
|
Appalachian Region
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Wells Completed
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploratory
|
|
|
8.10
|
|
|
|
3.88
|
|
|
|
3.00
|
|
|
|
|
|
|
|
|
|
|
|
4.00
|
|
Development
|
|
|
184.00
|
|
|
|
140.58
|
|
|
|
45.00
|
|
|
|
2.00
|
|
|
|
1.75
|
|
|
|
1.00
|
|
Total United States
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Wells Completed
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploratory
|
|
|
9.91
|
|
|
|
6.82
|
|
|
|
4.30
|
|
|
|
1.42
|
|
|
|
0.85
|
|
|
|
4.47
|
|
Development
|
|
|
243.99
|
|
|
|
234.34
|
|
|
|
162.20
|
|
|
|
4.67
|
|
|
|
2.75
|
|
|
|
1.00
|
|
Canada Discontinued Operations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Wells Completed
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploratory
|
|
|
6.38
|
|
|
|
12.60
|
|
|
|
21.14
|
|
|
|
|
|
|
|
1.35
|
|
|
|
2.00
|
|
Development
|
|
|
1.80
|
|
|
|
2.50
|
|
|
|
3.50
|
|
|
|
|
|
|
|
1.00
|
|
|
|
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Wells Completed
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploratory
|
|
|
16.29
|
|
|
|
19.42
|
|
|
|
25.44
|
|
|
|
1.42
|
|
|
|
2.20
|
|
|
|
6.47
|
|
Development
|
|
|
245.79
|
|
|
|
236.84
|
|
|
|
165.70
|
|
|
|
4.67
|
|
|
|
3.75
|
|
|
|
1.00
|
|
21
Present
Activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gulf
|
|
|
West
|
|
|
|
|
|
|
|
|
|
Coast
|
|
|
Coast
|
|
|
Appalachian
|
|
|
Total
|
|
At September 30, 2007
|
|
Region
|
|
|
Region
|
|
|
Region
|
|
|
Company
|
|
|
Wells in Process of Drilling(1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross
|
|
|
2.00
|
|
|
|
4.00
|
|
|
|
90.00
|
|
|
|
96.00
|
|
Net
|
|
|
1.30
|
|
|
|
4.00
|
|
|
|
88.00
|
|
|
|
93.30
|
|
|
|
|
(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 failure to initiate natural gas service,
despite an attempt to do so, at an apartment leased 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.
Trial was scheduled to begin October 15, 2007. However, the
parties resolved the action.
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.
On November 8, 2007, Distribution Corporation filed a complaint
with the PaPUC requesting that the PaPUC commence an
investigation to determine whether New Mountain Vantage GP,
L.L.C. (New Mountain), and others acting in concert with it,
have violated Pennsylvania law by acquiring control of
Distribution Corporation without the prior approval of the
PaPUC. In the event the PaPUC finds that New Mountain and others
acting in concert with it have not yet acquired control of
Distribution Corporation, Distribution Corporation petitioned
the PaPUC for an order requiring New Mountain to show cause why
it should not be required to apply for and receive a certificate
of public convenience prior to acquiring control of Distribution
Corporation, and requiring that the certificate of public
convenience be obtained prior to any vote of stockholders of the
Company which could result in the acquisition of control over
Distribution Corporation. According to a November 6, 2007
filing with the SEC, New Mountain and certain other holders
acknowledging acting with New Mountain as part of a group for
purposes of the federal securities laws collectively own 9.7% of
the outstanding shares of the Company. Distribution Corporation
alleges in its filing with the PaPUC that New Mountain and
others acting in concert with it have acquired or are seeking to
acquire control of the Company, which results or would result in
the acquisition of indirect control over Distribution
Corporation. On November 21, 2007, New Mountain filed
preliminary objections to Distribution Corporations
complaint and petition and requested that the PaPUC rule on the
preliminary objections at its December 20, 2007 public
meeting. In addition, two agencies of the Commonwealth of
Pennsylvania, the Office of Consumer Advocate and the Office of
Small Business Advocate, petitioned the PaPUC to intervene in
the proceeding, and the Office of Small Business Advocate
requested evidentiary hearings. Distribution Corporation
anticipates that its response to New Mountains preliminary
objections will request that the PaPUC, at its December 20,
2007 public meeting, initiate an investigation by issuing an
order for New Mountain to show cause why it should not be
required to apply for and receive a certificate of public
convenience prior to acquiring control of Distribution
Corporation.
The resolution of the Fordham-Coleman action described above
will not have a material effect on the consolidated financial
condition, results of operations, or cash flow of the Company.
The Company believes, based on the information presently known,
that the ultimate resolution of the matters before the PaPUC
22
described above 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
outcomes of those matters, and it is possible that the outcomes
could be material to the consolidated financial condition,
results of operations or cash flow of the Company.
For a discussion of various environmental and other matters,
refer to Part II, 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, 2007.
|
|
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 2, 2007, the Company issued a total of 2,400
unregistered shares of Company common stock to the eight
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, 2007, 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.
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, 2007
|
|
|
7,317
|
|
|
$
|
44.75
|
|
|
|
|
|
|
|
4,278,122
|
|
Aug. 1-31, 2007
|
|
|
124,254
|
|
|
$
|
41.93
|
|
|
|
113,000
|
|
|
|
4,165,122
|
|
Sept. 1-30, 2007
|
|
|
22,622
|
|
|
$
|
44.97
|
|
|
|
|
|
|
|
4,165,122
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
154,193
|
|
|
$
|
42.51
|
|
|
|
113,000
|
|
|
|
4,165,122
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(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 |
23
|
|
|
|
|
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 7,317 in July 2007, 11,254 in August
2007 and 22,622 in September 2007 (a three-month total of
41,193). Of those shares, 23,498 were purchased for the
Companys 401(k) plans and 17,695 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
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
2003
|
|
|
|
(Thousands)
|
|
|
Summary of Operations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Revenues
|
|
$
|
2,039,566
|
|
|
$
|
2,239,675
|
|
|
$
|
1,860,774
|
|
|
$
|
1,867,875
|
|
|
$
|
1,821,899
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchased Gas
|
|
|
1,018,081
|
|
|
|
1,267,562
|
|
|
|
959,827
|
|
|
|
949,452
|
|
|
|
963,567
|
|
Operation and Maintenance
|
|
|
396,408
|
|
|
|
395,289
|
|
|
|
388,094
|
|
|
|
374,010
|
|
|
|
330,316
|
|
Property, Franchise and Other Taxes
|
|
|
70,660
|
|
|
|
69,202
|
|
|
|
68,164
|
|
|
|
68,378
|
|
|
|
72,073
|
|
Depreciation, Depletion and Amortization
|
|
|
157,919
|
|
|
|
151,999
|
|
|
|
156,502
|
|
|
|
159,184
|
|
|
|
154,634
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,643,068
|
|
|
|
1,884,052
|
|
|
|
1,572,587
|
|
|
|
1,551,024
|
|
|
|
1,520,590
|
|
Gain (Loss) on Sale of Timber Properties
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,252
|
)
|
|
|
168,787
|
|
Operating Income
|
|
|
396,498
|
|
|
|
355,623
|
|
|
|
288,187
|
|
|
|
315,599
|
|
|
|
470,096
|
|
Other Income (Expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from Unconsolidated Subsidiaries
|
|
|
4,979
|
|
|
|
3,583
|
|
|
|
3,362
|
|
|
|
805
|
|
|
|
535
|
|
Impairment of Investment in Partnership
|
|
|
|
|
|
|
|
|
|
|
(4,158
|
)
|
|
|
|
|
|
|
|
|
Interest Income
|
|
|
1,550
|
|
|
|
9,409
|
|
|
|
6,236
|
|
|
|
1,771
|
|
|
|
2,427
|
|
Other Income
|
|
|
4,936
|
|
|
|
2,825
|
|
|
|
12,744
|
|
|
|
2,908
|
|
|
|
2,204
|
|
Interest Expense on Long-Term Debt
|
|
|
(68,446
|
)
|
|
|
(72,629
|
)
|
|
|
(73,244
|
)
|
|
|
(82,989
|
)
|
|
|
(91,381
|
)
|
Other Interest Expense
|
|
|
(6,029
|
)
|
|
|
(5,952
|
)
|
|
|
(9,069
|
)
|
|
|
(6,354
|
)
|
|
|
(11,010
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from Continuing Operations Before Income Taxes
|
|
|
333,488
|
|
|
|
292,859
|
|
|
|
224,058
|
|
|
|
231,740
|
|
|
|
372,871
|
|
Income Tax Expense
|
|
|
131,813
|
|
|
|
108,245
|
|
|
|
85,621
|
|
|
|
89,820
|
|
|
|
116,795
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from Continuing Operations
|
|
|
201,675
|
|
|
|
184,614
|
|
|
|
138,437
|
|
|
|
141,920
|
|
|
|
256,076
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Discontinued Operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (Loss) from Operations, Net of Tax
|
|
|
15,479
|
|
|
|
(46,523
|
)
|
|
|
25,277
|
|
|
|
24,666
|
|
|
|
(68,240
|
)
|
Gain on Disposal, Net of Tax
|
|
|
120,301
|
|
|
|
|
|
|
|
25,774
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (Loss) from Discontinued Operations, Net of Tax
|
|
|
135,780
|
|
|
|
(46,523
|
)
|
|
|
51,051
|
|
|
|
24,666
|
|
|
|
(68,240
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
24
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended September 30
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
2003
|
|
|
|
(Thousands)
|
|
|
Income Before Cumulative Effect of Changes in Accounting
|
|
|
337,455
|
|
|
|
138,091
|
|
|
|
189,488
|
|
|
|
166,586
|
|
|
|
187,836
|
|
Cumulative Effect of Changes in Accounting
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(8,892
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income Available for Common Stock
|
|
$
|
337,455
|
|
|
$
|
138,091
|
|
|
$
|
189,488
|
|
|
$
|
166,586
|
|
|
$
|
178,944
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Per Common Share Data
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic Earnings from Continuing Operations per Common Share
|
|
$
|
2.43
|
|
|
$
|
2.20
|
|
|
$
|
1.66
|
|
|
$
|
1.73
|
|
|
$
|
3.17
|
|
Diluted Earnings from Continuing Operations per Common Share
|
|
$
|
2.37
|
|
|
$
|
2.15
|
|
|
$
|
1.63
|
|
|
$
|
1.71
|
|
|
$
|
3.15
|
|
Basic Earnings per Common Share(2)
|
|
$
|
4.06
|
|
|
$
|
1.64
|
|
|
$
|
2.27
|
|
|
$
|
2.03
|
|
|
$
|
2.21
|
|
Diluted Earnings per Common Share(2)
|
|
$
|
3.96
|
|
|
$
|
1.61
|
|
|
$
|
2.23
|
|
|
$
|
2.01
|
|
|
$
|
2.20
|
|
Dividends Declared
|
|
$
|
1.22
|
|
|
$
|
1.18
|
|
|
$
|
1.14
|
|
|
$
|
1.10
|
|
|
$
|
1.06
|
|
Dividends Paid
|
|
$
|
1.21
|
|
|
$
|
1.17
|
|
|
$
|
1.13
|
|
|
$
|
1.09
|
|
|
$
|
1.05
|
|
Dividend Rate at Year-End
|
|
$
|
1.24
|
|
|
$
|
1.20
|
|
|
$
|
1.16
|
|
|
$
|
1.12
|
|
|
$
|
1.08
|
|
At September 30:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Number of Registered Shareholders
|
|
|
16,989
|
|
|
|
17,767
|
|
|
|
18,369
|
|
|
|
19,063
|
|
|
|
19,217
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Property, Plant and Equipment
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Utility
|
|
$
|
1,099,280
|
|
|
$
|
1,084,080
|
|
|
$
|
1,064,588
|
|
|
$
|
1,048,428
|
|
|
$
|
1,028,393
|
|
Pipeline and Storage
|
|
|
681,940
|
|
|
|
674,175
|
|
|
|
680,574
|
|
|
|
696,487
|
|
|
|
705,927
|
|
Exploration and Production(3)
|
|
|
982,698
|
|
|
|
1,002,265
|
|
|
|
974,806
|
|
|
|
923,730
|
|
|
|
925,833
|
|
Energy Marketing
|
|
|
102
|
|
|
|
59
|
|
|
|
97
|
|
|
|
80
|
|
|
|
171
|
|
Timber
|
|
|
89,902
|
|
|
|
90,939
|
|
|
|
94,826
|
|
|
|
82,838
|
|
|
|
87,600
|
|
All Other
|
|
|
16,735
|
|
|
|
17,394
|
|
|
|
18,098
|
|
|
|
21,172
|
|
|
|
22,042
|
|
Corporate(4)
|
|
|
7,748
|
|
|
|
8,814
|
|
|
|
6,311
|
|
|
|
234,029
|
|
|
|
221,082
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Net Plant
|
|
$
|
2,878,405
|
|
|
$
|
2,877,726
|
|
|
$
|
2,839,300
|
|
|
$
|
3,006,764
|
|
|
$
|
2,991,048
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Assets
|
|
$
|
3,888,412
|
|
|
$
|
3,763,748
|
|
|
$
|
3,749,753
|
|
|
$
|
3,738,103
|
|
|
$
|
3,740,944
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capitalization
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive Shareholders Equity
|
|
$
|
1,630,119
|
|
|
$
|
1,443,562
|
|
|
$
|
1,229,583
|
|
|
$
|
1,253,701
|
|
|
$
|
1,137,390
|
|
Long-Term Debt, Net of Current Portion
|
|
|
799,000
|
|
|
|
1,095,675
|
|
|
|
1,119,012
|
|
|
|
1,133,317
|
|
|
|
1,147,779
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Capitalization
|
|
$
|
2,429,119
|
|
|
$
|
2,539,237
|
|
|
$
|
2,348,595
|
|
|
$
|
2,387,018
|
|
|
$
|
2,285,169
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(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 SECI discontinued operations as follows:
$0 for 2007, $88,023 for 2006, $170,929 for 2005, $142,860 for
2004, and $116,487 for 2003. |
|
(4) |
|
Includes net plant of the former international segment as
follows: $38 for 2007, $27 for 2006, $20 for 2005, $227,905 for
2004, and $219,199 for 2003. |
25
|
|
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 1, 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) 2007 and 2008 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.
The event that had the most significant earnings impact in 2007,
and the main reason for the significant earnings increase over
2006, was the Companys sale of SECI, Senecas wholly
owned subsidiary that operated in Canada. SECI was engaged in
the exploration for, and the development and purchase of,
natural gas and oil reserves in the provinces of Alberta,
Saskatchewan and British Columbia in Canada. This sale resulted
in a $120.3 million gain, net of tax. The decision to sell
SECI was based on lower than expected returns from the Canadian
oil and gas properties combined with difficulty in finding
significant new reserves. As a result of the decision to sell
SECI, the Company began presenting all SECI operations as
discontinued operations in September 2007. Also contributing to
the increase in earnings over 2006 was the non-recurrence of
impairment charges of $68.6 million related to the
Exploration and Production segments Canadian oil and gas
assets recognized during 2006 under the full cost method of
accounting, which is discussed below under Critical Accounting
Estimates. Seneca intends to continue its exploration and
development activities in the Gulf of Mexico, in California and
in Appalachia, subject to regular re-evaluation of its efforts
and opportunities in each region.
The Company spent $247.6 million on capital expenditures
related to continuing operations during 2007, with approximately
59% being spent in the Exploration and Production segment. This
was in line with the Companys expectations. As mentioned
above, Seneca will continue its exploration and development
activities in Appalachia, in California and in the Gulf of
Mexico. In Appalachia, drilling will be accelerated. Seneca
intends to commence drilling of 280 wells for shallow tight
sand targets in fiscal 2008, a 20% increase over the 233 such
wells drilled in 2007. In addition, Seneca anticipates continued
drilling in the deeper Marcellus Shale formation in Appalachia
with its joint venture partner, EOG Resources, Inc. Seneca
expects that as many as eighteen Marcellus Shale wells will be
drilled on its acreage in 2008, ten of which are expected to be
horizontal wells. In the Gulf of Mexico, Senecas strategy
will be to follow a focused drilling plan in the specific areas
where the Company has expertise and past success.
The Company took a significant step forward this year regarding
the Empire Connector project. In June 2007, Empire signed a firm
transportation service agreement with KeySpan Gas East
Corporation, thereby obligating Empire to provide transportation
service that will require construction of the Empire Connector
project. Construction of the Empire Connector began in September
2007 and 20 miles will be completed by December 2007. The
Company expects to complete the project by November 1,
2008. The total cost to the Company of the Empire Connector
project is estimated at $177 million, after giving effect
to sales tax
26
exemptions. The Company expects the expansion of the Pipeline
and Storage segment to remain a major strategic priority. Supply
Corporation has verified that there is substantial market
interest in transporting gas produced in the Rocky Mountain area
to the Northeast. In order to serve this anticipated demand,
Supply Corporation has proposed a new
324-mile
pipeline that would commence at Clarington, Ohio, the proposed
terminus of the Rockies Express pipeline, and extend to the
Millennium Pipeline under construction at Corning, New York.
From Corning, Rocky Mountain gas will be able to get to the New
York City area and to New England. The proposed pipeline would
be designed to move approximately 550 to 750 MDth of gas per
day, as well as accommodate volumes from local production areas.
These projects are discussed further in the Capital Resources
and Liquidity and Rates and Regulatory Matters sections that
follow.
The Company is currently evaluating the appropriateness of
establishing a Master Limited Partnership (MLP) for its pipeline
and storage assets, and another MLP for certain of its
exploration and production assets. If this evaluation determined
that the MLP structure is sound and in the shareholders
interest, the Company would pursue the MLP structure for the
appropriate Company assets. Potential impediments to
establishing MLPs include: (a) the low tax basis of our
pipeline and storage assets, which substantially mitigates the
tax advantages of an MLP structure; (b) the highly
integrated operations of the Companys Pipeline and Storage
and Utility business segments; and (c) the sustainability
of an exploration and production MLP given the natural decline
curve of production from all oil and gas properties. As a
result, new long-lived reserves must be constantly added to an
exploration and production MLP in order to sustain the
MLPs cash distributions. Acquisitions of long-lived
reserves could be very costly given the significant premiums
that are currently being paid for long-lived reserves.
The Company also began repurchasing outstanding shares of common
stock during fiscal 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, 2007, the
Company had repurchased 3,834,878 shares for
$133.2 million under this program, including
1,308,328 shares for $48.1 million during the year
ended September 30, 2007. These matters are discussed
further in the Capital Resources and Liquidity section that
follows.
On January 29, 2007, the Company commenced a rate case in
the New York jurisdiction of the Utility segment by filing
proposed tariff amendments and supporting testimony requesting
approval to increase its annual revenues by $52.0 million
annually. The Company explained in the filing that its request
for rate relief is necessitated by decreased revenues resulting
from customer conservation efforts and increased customer
uncollectibles, among other things. The rate filing also
includes a proposal for an aggressive efficiency and
conservation initiative with a revenue decoupling mechanism
designed to render the Company indifferent to throughput
reductions resulting from conservation. In September 2007, the
NYPSC issued an order approving the Companys conservation
program, and the administrative law judge assigned to the
proceeding issued a recommended decision, which recommends a
rate increase designed to provide additional annual revenues of
$2.5 million as well as a bill surcharge that would collect
up to $10.8 million to recover expenses arising from the
conservation program. The recommended decision also recommends
approval of the unopposed revenue decoupling mechanism. The
NYPSC is not bound to accept the recommended decision. This
matter 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
27
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 does not
recognize any gain or loss on the sale or other disposition of
oil and gas properties unless the gain or loss would
significantly alter the relationship between capitalized costs
and proved reserves of oil and gas attributable to a cost center.
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). Unproved properties are excluded
from the depletion calculation until proved reserves are found
or it is determined that the unproved properties are impaired.
All costs related to unproved properties are reviewed quarterly
to determine if impairment has occurred. The amount of any
impairment is transferred to the pool of capitalized costs being
amortized.
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 , which is performed each quarter, determines a
limit, or ceiling, on a
country-by-country
basis on 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 cash flows, excluding future cash outflows associated
with settling asset retirement obligations that have been
accrued on the balance sheet, 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 tax effects related to the differences between
the book and tax basis of the properties. 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 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. These impairment charges are now included in
the loss from discontinued operations for 2006 due to the sale
of SECI during 2007.
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.
28
Upon the adoption of SFAS 143 on October 1, 2002, 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
and capitalized such costs in property, plant and equipment
(i.e. the full cost pool). Prior to the adoption of
SFAS 143, plugging and abandonment costs were accounted for
solely through the Companys units-of-production depletion
calculation. An estimate of such costs was added to the
depletion base, which also included capitalized costs in the
full cost pool and estimated future expenditures to be incurred
in developing proved reserves. With the adoption of
SFAS 143, plugging and abandonment costs are already
included in capitalized costs and the units-of-production
depletion calculation has been modified to exclude from the
depletion base any estimate of future plugging and abandonment
costs that are already recorded in the full cost pool.
Prior to the adoption of SFAS 143, in calculating the full
cost ceiling, the Company reduced the future net cash flows from
proved oil and gas reserves by the estimated plugging and
abandonment costs. Such future net cash flows would then be
compared to capitalized costs in the full cost pool, with any
excess capitalized costs being expensed. With the adoption of
SFAS 143, since the full cost pool now includes an amount
associated with plugging and abandoning the wells, the
calculation of the full cost ceiling has been changed so that
future net cash flows from proved oil and gas reserves are no
longer reduced by the estimated plugging and abandonment costs.
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 and futures contracts. The
Company, in its Pipeline and Storage segment, previously used an
interest rate collar to limit interest rate fluctuations on
certain variable rate debt. In accordance with the provisions of
SFAS 133, the Company accounted for these instruments as
effective cash flow hedges or fair value hedges. In 2007, the
Company discontinued hedge accounting for the interest rate
collar, which resulted in a gain being recognized. 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 in the Exploration and
Production segment, resulting in a charge to earnings in 2005.
The Company uses both exchange-traded and non exchange-traded
derivative financial instruments. The fair values 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.
29
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 expected timing of anticipated future
benefit payments (approximately 12 years). The Company also
utilizes a yield curve model to determine the discount rate. The
yield curve is a spot rate yield curve that provides a
zero-coupon interest rate for each year into the future. Each
years anticipated benefit payments are discounted at the
associated spot interest rate back to the measurement date. The
discount rate is then determined based on the spot interest rate
that results in the same present value when applied to the same
anticipated benefit payments. 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 93% and 94%, 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, 2007 and 2006.
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, while the discount rate used to determine benefit
obligations did not change from 2006 to 2007, the discount rate
was changed from 5.0% in 2005 to 6.25% in 2006. The change in
the discount rate from 2005 to 2006 reduced the pension plan
projected benefit obligation by $113.1 million and the
accumulated post-retirement benefit obligation by
$77.5 million. 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 2007, 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 $68.4 million and $38.6 million, respectively.
The actual versus expected benefit payments for 2007 caused a
decrease of $1.3 million and $1.8 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 is 9 years for both the Retirement Plan
and the Post-Retirement Plan. For further discussion of the
Companys pension and other post-retirement benefits, refer
to Other Matters in this Item 7, which includes a
discussion of funding for the current year and the adoption of
SFAS 158, and to Item 8 at Note G
Retirement Plan and Other Post Retirement Benefits.
30
RESULTS
OF OPERATIONS
EARNINGS
2007
Compared with 2006
The Companys earnings were $337.5 million in 2007
compared with earnings of $138.1 million in 2006. As
previously discussed, the Company has presented its Canadian
operations in the Exploration and Production segment (in
conjunction with the sale of SECI) as discontinued operations.
The Companys earnings from continuing operations were
$201.7 million in 2007 compared with $184.6 million in
2006. The Companys earnings from discontinued operations
were $135.8 million in 2007 compared with a loss of
$46.5 million in 2006. The increase in earnings from
continuing operations of $17.1 million is primarily the
result of higher earnings in the Exploration and Production,
Utility, Pipeline and Storage, and Energy Marketing segments and
the Corporate and All Other categories, slightly offset by lower
earnings in the Timber segment, as shown in the table below. The
increase in earnings from discontinued operations primarily
resulted from the gain on the sale of SECI recognized in 2007 as
well as the non-recurrence of $68.6 million of impairment
charges recognized in 2006 related to the Exploration and
Production segments Canadian oil and gas assets. In the
discussion that follows, note that all amounts used in the
earnings discussions are after-tax amounts, unless otherwise
noted. Earnings from continuing operations and discontinued
operations were impacted by several events in 2007 and 2006,
including:
2007
Events
|
|
|
|
|
A $120.3 million gain on the sale of SECI, which was
completed in August 2007. This amount is included in earnings
from discontinued operations;
|
|
|
|
A $4.8 million benefit to earnings in the Pipeline and
Storage segment due to the reversal of a reserve established for
all costs incurred related to the Empire Connector project
recognized during June 2007;
|
|
|
|
A $1.9 million benefit to earnings in the Pipeline and
Storage segment associated with the discontinuance of hedge
accounting for Empires interest rate collar; and
|
|
|
|
A $2.3 million benefit to earnings in the Energy Marketing
segment related to the resolution of a purchased gas contingency.
|
2006
Events
|
|
|
|
|
$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 ($6.1 million in continuing operations
and $5.1 million in discontinued operations) 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 Distribution Corporations
calculation of the symmetrical sharing component of New
Yorks gas adjustment rate.
|
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 has presented its Canadian
operations in the Exploration and Production segment (in
conjunction with the sale of SECI) as well as for its Czech
Republic operations (in conjunction with the sale of U.E.) as
discontinued operations. The Companys earnings from
continuing operations were $184.6 million in 2006 compared
with $138.4 million in 2005. The Company recorded a loss
from discontinued operations of $46.5 million in 2006
compared with earnings from discontinued operations of
$51.1 million in 2005. The increase in earnings from
continuing operations of $46.2 million is primarily the
result of higher earnings in the Exploration and Production,
Utility, Energy Marketing, and Timber segments, combined with
31
higher earnings in the All Other category and a lower loss in
the Corporate category. These were offset somewhat by lower
earnings in the Pipeline and Storage segment, as shown in the
table below. The loss from discontinued operations in 2006
compared to earnings from discontinued operations in 2005
reflects the recognition of $68.6 million of impairment
charges in 2006 related to the Exploration and Production
segments Canadian oil and gas assets as well as the
non-recurrence of the gain on the sale of U.E. recognized in
2005. Earnings from continuing operations and discontinued
operations were impacted by several events discussed above and
the following 2005 events:
2005
Events
|
|
|
|
|
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.
|
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
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(Thousands)
|
|
|
Utility
|
|
$
|
50,886
|
|
|
$
|
49,815
|
|
|
$
|
39,197
|
|
Pipeline and Storage
|
|
|
56,386
|
|
|
|
55,633
|
|
|
|
60,454
|
|
Exploration and Production
|
|
|
74,889
|
|
|
|
67,494
|
|
|
|
35,581
|
|
Energy Marketing
|
|
|
7,663
|
|
|
|
5,798
|
|
|
|
5,077
|
|
Timber
|
|
|
3,728
|
|
|
|
5,704
|
|
|
|
5,032
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Reportable Segments
|
|
|
193,552
|
|
|
|
184,444
|
|
|
|
145,341
|
|
All Other
|
|
|
2,564
|
|
|
|
359
|
|
|
|
(2,616
|
)
|
Corporate(1)
|
|
|
5,559
|
|
|
|
(189
|
)
|
|
|
(4,288
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Earnings from Continuing Operations
|
|
|
201,675
|
|
|
|
184,614
|
|
|
|
138,437
|
|
Earnings (Loss) from Discontinued Operations
|
|
|
135,780
|
|
|
|
(46,523
|
)
|
|
|
51,051
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Consolidated
|
|
$
|
337,455
|
|
|
$
|
138,091
|
|
|
$
|
189,488
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Includes earnings from the former International segments
activity other than the activity from the Czech Republic
operations included in Earnings from Discontinued Operations. |
32
UTILITY
Revenues
Utility
Operating Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended September 30
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(Thousands)
|
|
|
Retail Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
Residential
|
|
$
|
848,693
|
|
|
$
|
993,928
|
|
|
$
|
868,292
|
|
Commercial
|
|
|
136,863
|
|
|
|
166,779
|
|
|
|
145,393
|
|
Industrial
|
|
|
8,271
|
|
|
|
13,484
|
|
|
|
13,998
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
993,827
|
|
|
|
1,174,191
|
|
|
|
1,027,683
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Off-System Sales
|
|
|
9,751
|
|
|
|
|
|
|
|
|
|
Transportation
|
|
|
102,534
|
|
|
|
92,569
|
|
|
|
83,669
|
|
Other
|
|
|
14,612
|
|
|
|
14,003
|
|
|
|
5,715
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
1,120,724
|
|
|
$
|
1,280,763
|
|
|
$
|
1,117,067
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Utility
Throughput million cubic feet (MMcf)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended September 30
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
Retail Sales:
|
|
|
|
|
|
|
|
|
|
|
|
|
Residential
|
|
|
60,236
|
|
|
|
59,443
|
|
|
|
66,903
|
|
Commercial
|
|
|
10,713
|
|
|
|
10,681
|
|
|
|
11,984
|
|
Industrial
|
|
|
727
|
|
|
|
985
|
|
|
|
1,387
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
71,676
|
|
|
|
71,109
|
|
|
|
80,274
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Off-System Sales
|
|
|
1,355
|
|
|
|
|
|
|
|
|
|
Transportation
|
|
|
62,240
|
|
|
|
57,950
|
|
|
|
59,770
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
135,271
|
|
|
|
129,059
|
|
|
|
140,044
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Degree
Days
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Percent (Warmer)
|
|
|
|
|
|
|
|
|
|
|
|
|
Colder Than
|
|
Year Ended September 30
|
|
|
|
|
Normal
|
|
|
Actual
|
|
|
Normal
|
|
|
Prior Year
|
|
|
2007:
|
|
|
Buffalo
|
|
|
|
6,692
|
|
|
|
6,271
|
|
|
|
(6.3
|
)%
|
|
|
5.1
|
%
|
|
|
|
Erie
|
|
|
|
6,243
|
|
|
|
6,007
|
|
|
|
(3.8
|
)%
|
|
|
5.6
|
%
|
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
|
%
|
2007
Compared with 2006
Operating revenues for the Utility segment decreased
$160.0 million in 2007 compared with 2006. This decrease
largely resulted from a $180.4 million decrease in retail
gas sales revenues. This decrease was primarily offset by a
$10.0 million increase in transportation revenues and a
$9.8 million increase in off-system sales revenues.
33
The decrease in retail gas sales revenues for the Utility
segment was largely a function of the recovery of lower gas
costs (gas costs are recovered dollar for dollar in revenues),
which more than offset the revenue impact of higher retail sales
volumes, as shown in the table above. See further discussion of
purchased gas below under the heading Purchased Gas.
This decrease was offset slightly by a base rate increase in the
Pennsylvania jurisdiction, effective January 2007, which
increased operating revenues by $8.5 million for 2007. The
increase is included within both retail and transportation
revenues in the table above.
The increase in transportation revenues was primarily due to a
4.3 Bcf increase in transportation throughput, largely due
to the migration of retail sales customers to transportation
service. The corresponding $10.0 million increase in
transportation revenues would have been greater if not for a
$3.9 million out-of-period adjustment recorded in the first
quarter of 2006 to correct Distribution Corporations
calculation of the symmetrical sharing component of New
Yorks gas adjustment rate.
As reported in 2006, on November 17, 2006 the
U.S. Court of Appeals vacated and remanded FERCs
Order No. 2004, its latest affiliate standards of conduct,
with respect to natural gas pipelines. The courts decision
became effective on January 5, 2007, and on January 9,
2007, FERC issued Order No. 690, its Interim Rule, designed
to respond to the courts decision. In Order No. 690,
as clarified by FERC on March 21, 2007, the FERC readopted,
on an interim basis, certain provisions that existed prior to
the issuance of Order No. 2004 that had made it possible
for the Utility to engage in certain off-system sales without
triggering the adverse consequences that would otherwise arise
under the standards of conduct. As such, the Utility resumed
engaging in off-system sales on non-affiliated pipelines as of
May 2007, resulting in total off-system sales revenues of
$9.8 million for 2007. Due to profit sharing with retail
customers, the margins resulting from off-system sales are
minimal and there was not a material impact to margins in 2007.
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 agreement 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 agreement 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 rate agreement 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
$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
34
in 2006. Other operating revenues were 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 rate 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.
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 $10.04 per Mcf in 2007, a decrease of 17% from the average
cost of $12.07 per Mcf in 2006. The average cost of purchased
gas in 2006 was 31% higher than the average cost of $9.19 per
Mcf in 2005. Additional discussion of the Utility segments
gas purchases appears under the heading Sources and
Availability of Raw Materials in Item 1.
Earnings
2007
Compared with 2006
The Utility segments earnings in 2007 were
$50.9 million, an increase of $1.1 million when
compared with earnings of $49.8 million in 2006.
In the New York jurisdiction, earnings decreased by
$6.2 million. This was primarily due to lower interest
income ($4.5 million). The New York divisions current
rate agreement with the NYPSC allows the Company to accrue
interest on a pension-related regulatory asset. The amount of
interest that can be accrued is reduced as the funded status of
the pension plan improves. The fair market value of the pension
plan assets exceeded the accumulated benefit obligation at
September 30, 2007 resulting in a significant reduction in
the interest accrual on this regulatory asset. The out-of-period
symmetrical sharing adjustment discussed above
($2.6 million), higher bad debt and other operating costs
($0.8 million), higher property taxes ($0.6 million)
and higher interest expense ($0.5 million) also contributed
to this decrease. The positive impact associated with a lower
effective tax rate ($1.9 million) and increased usage per
account ($1.9 million) partially offset the overall
decrease.
In the Pennsylvania jurisdiction, earnings increased by
$7.3 million. This was primarily due to a base rate
increase ($5.5 million) that became effective January 2007,
colder weather ($2.5 million), and the positive impact
associated with a lower effective tax rate ($1.1 million).
Higher intercompany and other interest expense
($0.8 million), coupled with a decrease in normalized usage
($0.3 million), partially offset these increases.
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
35
Utility segments New York customers. In 2007 and 2006, the
WNC preserved earnings of approximately $2.3 million and
$6.2 million, respectively, as the weather was warmer than
normal.
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 agreement 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 agreement, 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.
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.
36
PIPELINE
AND STORAGE
Revenues
Pipeline
and Storage Operating Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended September 30
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(Thousands)
|
|
|
Firm Transportation
|
|
$
|
118,771
|
|
|
$
|
118,551
|
|
|
$
|
117,146
|
|
Interruptible Transportation
|
|
|
4,161
|
|
|
|
4,858
|
|
|
|
4,413
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
122,932
|
|
|
|
123,409
|
|
|
|
121,559
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Firm Storage Service
|
|
|
66,966
|
|
|
|
66,718
|
|
|
|
65,320
|
|
Interruptible Storage Service
|
|
|
169
|
|
|
|
39
|
|
|
|
267
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
67,135
|
|
|
|
66,757
|
|
|
|
65,587
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
|
|
|
21,899
|
|
|
|
24,186
|
|
|
|
28,713
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
211,966
|
|
|
$
|
214,352
|
|
|
$
|
215,859
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pipeline
and Storage Throughput (MMcf)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended September 30
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
Firm Transportation
|
|
|
351,113
|
|
|
|
363,379
|
|
|
|
357,585
|
|
Interruptible Transportation
|
|
|
4,975
|
|
|
|
11,609
|
|
|
|
14,794
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
356,088
|
|
|
|
374,988
|
|
|
|
372,379
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007
Compared with 2006
Operating revenues for the Pipeline and Storage segment
decreased $2.4 million in 2007 as compared with 2006, which
was due mostly to a decrease in other revenues
($2.3 million). The decrease in other revenues is primarily
due to a $4.2 million decrease in efficiency gas revenues.
This decrease was due to the Companys recent settlement
with the FERC, which decreased efficiency gas retainage
allowances. Offsetting this decrease, there was a
$1.4 million increase in other revenues attributable to the
lease termination fee adjustment in 2006 (an intercompany
transaction) for the Companys former headquarters, which
did not recur in 2007. While Supply Corporations
transportation volumes decreased 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.
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 efficiency gas revenues due to
lower natural gas prices, a $0.7 million decrease in
cashout revenues, and a $1.4 million decrease in revenue
attributable to a lease termination fee adjustment (an
intercompany transaction) for the Companys former
headquarters. 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
37
Corporations straight fixed-variable rate design. The
increase in storage revenues reflects the renewal of storage
contracts at higher rates.
Earnings
2007
Compared with 2006
The Pipeline and Storage segments earnings in 2007 were
$56.4 million, an increase of $0.8 million when
compared with earnings of $55.6 million in 2006. The main
factor contributing to this increase was the reversal of a
reserve for preliminary survey costs ($4.8 million) related
to the Empire Connector project. Based on the signing of a
service agreement with KeySpan Gas East Corporation during the
quarter ended June 30, 2007, management determined that it
was probable that the project would go forward and that such
preliminary survey costs were properly capitalizable in
accordance with the FERCs Uniform System of Accounts and
SFAS 71. In addition, there was a $2.5 million
increase in earnings associated with the decrease in
depreciation expense as a result of the most recent settlement
with the FERC, which reduced depreciation rates. There was also
a $1.9 million positive earnings impact associated with the
discontinuance of hedge accounting for Empires interest
rate collar. On December 8, 2006, Empire repaid
$22.8 million of secured debt. The interest costs of this
secured debt were hedged by the interest rate collar. Since the
hedged transaction was settled and there will be no future cash
flows associated with the secured debt, the unrealized gain in
accumulated other comprehensive income associated with the
interest rate collar was reclassified to the income statement.
These earnings increases were offset by higher interest expense
($3.2 million), lower efficiency gas revenues
($2.7 million), a $1.5 million increase in operating
costs (primarily post-retirement benefit costs), and the
earnings decrease associated with a higher effective tax rate
($0.9 million).
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 efficiency gas revenues ($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).
EXPLORATION
AND PRODUCTION
Revenues
Exploration
and Production Operating Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended September 30
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(Thousands)
|
|
|
Gas (after Hedging) from Continuing Operations
|
|
$
|
143,785
|
|
|
$
|
126,969
|
|
|
$
|
132,528
|
|
Oil (after Hedging) from Continuing Operations
|
|
|
167,627
|
|
|
|
134,307
|
|
|
|
94,925
|
|
Gas Processing Plant from Continuing Operations
|
|
|
37,528
|
|
|
|
42,252
|
|
|
|
36,350
|
|
Other from Continuing Operations
|
|
|
1,147
|
|
|
|
3,072
|
|
|
|
(3,447
|
)
|
Intrasegment Elimination from Continuing Operations(1)
|
|
|
(26,050
|
)
|
|
|
(31,704
|
)
|
|
|
(29,706
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Revenues from Continuing Operations
|
|
$
|
324,037
|
|
|
$
|
274,896
|
|
|
$
|
230,650
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Revenues from Canada Discontinued
Operations
|
|
$
|
50,495
|
|
|
$
|
71,984
|
|
|
$
|
62,775
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
38
|
|
|
(1) |
|
Represents the elimination of certain West Coast gas production
revenue included in Gas (after Hedging) from Continuing
Operations 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
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
Gas Production (MMcf)
|
|
|
|
|
|
|
|
|
|
|
|
|
Gulf Coast
|
|
|
10,356
|
|
|
|
9,110
|
|
|
|
12,468
|
|
West Coast
|
|
|
3,929
|
|
|
|
3,880
|
|
|
|
4,052
|
|
Appalachia
|
|
|
5,555
|
|
|
|
5,108
|
|
|
|
4,650
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Production from Continuing Operations
|
|
|
19,840
|
|
|
|
18,098
|
|
|
|
21,170
|
|
Canada Discontinued Operations
|
|
|
6,426
|
|
|
|
7,673
|
|
|
|
8,009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Production
|
|
|
26,266
|
|
|
|
25,771
|
|
|
|
29,179
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil Production (Mbbl)
|
|
|
|
|
|
|
|
|
|
|
|
|
Gulf Coast
|
|
|
717
|
|
|
|
685
|
|
|
|
989
|
|
West Coast
|
|
|
2,403
|
|
|
|
2,582
|
|
|
|
2,544
|
|
Appalachia
|
|
|
124
|
|
|
|
69
|
|
|
|
36
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Production from Continuing Operations
|
|
|
3,244
|
|
|
|
3,336
|
|
|
|
3,569
|
|
Canada Discontinued Operations
|
|
|
206
|
|
|
|
272
|
|
|
|
300
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Production
|
|
|
3,450
|
|
|
|
3,608
|
|
|
|
3,869
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average
Prices
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended September 30
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
Average Gas Price/Mcf
|
|
|
|
|
|
|
|
|
|
|
|
|
Gulf Coast
|
|
$
|
6.58
|
|
|
$
|
8.01
|
|
|
$
|
7.05
|
|
West Coast
|
|
$
|
6.54
|
|
|
$
|
7.93
|
|
|
$
|
6.85
|
|
Appalachia
|
|
$
|
7.48
|
|
|
$
|
9.53
|
|
|
$
|
7.60
|
|
Weighted Average for Continuing Operations
|
|
$
|
6.82
|
|
|
$
|
8.42
|
|
|
$
|
7.13
|
|
Weighted Average After Hedging for Continuing Operations(1)
|
|
$
|
7.25
|
|
|
$
|
7.02
|
|
|
$
|
6.26
|
|
Canada Discontinued Operations
|
|
$
|
6.09
|
|
|
$
|
7.14
|
|
|
$
|
6.15
|
|
Average Oil Price/Barrel (bbl)
|
|
|
|
|
|
|
|
|
|
|
|
|
Gulf Coast
|
|
$
|
63.04
|
|
|
$
|
64.10
|
|
|
$
|
49.78
|
|
West Coast(2)
|
|
$
|
56.86
|
|
|
$
|
56.80
|
|
|
$
|
42.91
|
|
Appalachia
|
|
$
|
62.26
|
|
|
$
|
65.28
|
|
|
$
|
48.28
|
|
Weighted Average for Continuing Operations
|
|
$
|
58.43
|
|
|
$
|
58.47
|
|
|
$
|
44.87
|
|
Weighted Average After Hedging for Continuing Operations(1)
|
|
$
|
51.68
|
|
|
$
|
40.26
|
|
|
$
|
26.59
|
|
Canada Discontinued Operations
|
|
$
|
50.06
|
|
|
$
|
51.40
|
|
|
$
|
42.97
|
|
|
|
|
(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. |
39
2007
Compared with 2006
Operating revenues from continuing operations for the
Exploration and Production segment increased $49.1 million
in 2007 as compared with 2006. Oil production revenue after
hedging increased $33.3 million due primarily to an $11.42
per barrel increase in weighted average prices after hedging,
which more than offset a slight decrease in oil production of
92,000 barrels. Gas production revenue after hedging
increased $16.8 million in 2007 as compared with 2006. An
increase in gas production of 1,742 MMcf and an increase in
weighted average prices after hedging of $0.23 per Mcf both
contributed to the increase. The increase in gas production
occurred primarily in the Gulf Coast region (1,246 MMcf).
During the quarter ended December 31, 2005, Seneca
experienced significant production delays due largely to the
impact of hurricane damage to pipeline infrastructure in the
Gulf of Mexico. Seneca had substantially all of its
pre-hurricane Gulf of Mexico production back on line at the
beginning of fiscal 2007. Production also increased in this
segments Appalachian region (447 MMcf), primarily due
to increased drilling in this region during 2007, as highlighted
in Item 2 under Exploration and Production
Activities.
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.
2006
Compared with 2005
Operating revenues from continuing operations for the
Exploration and Production segment increased $44.2 million
in 2006 as compared with 2005. Oil production revenue after
hedging increased $39.4 million due primarily to higher
weighted average prices after hedging ($13.67 per barrel). This
increase was offset slightly by a decrease in production
(233,000 barrels). Gas production revenue after hedging
decreased $5.6 million. A decrease in gas production
(3,072 MMcf) more than offset an increase in the weighted
average price of gas after hedging ($0.76 per Mcf). The decrease
in gas production occurred primarily in the Gulf Coast (a
3,358 MMcf decline), which is partly attributable to the
fall 2005 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.
Earnings
2007
Compared with 2006
The Exploration and Production segments earnings from
continuing operations for 2007 were $74.9 million, an
increase of $7.4 million when compared with earnings from
continuing operations of $67.5 million for 2006. Higher
crude oil prices, higher natural gas production and higher
natural gas prices increased earnings by $24.1 million,
$7.9 million and $3.0 million, respectively. These
increases were partly offset by the non-recurrence of
$6.1 million of tax benefits recognized during 2006,
discussed below, as well as by higher depletion expense and
higher lease operating expense of $7.2 million and
$4.6 million, respectively. Slightly lower crude oil
production and higher general and administrative expenses also
decreased earnings by $2.4 million and $0.6 million,
respectively. Earnings were also negatively impacted by a higher
effective tax rate ($6.3 million).
2006
Compared with 2005
The Exploration and Production segments earnings from
continuing operations in 2006 were $67.5 million, an
increase of $31.9 million when compared with earnings from
continuing operations of $35.6 million in 2005. The
increase is primarily the result of higher oil and gas prices,
which increased earnings by $29.6 million and
$8.9 million, respectively. 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
40
income ($2.2 million). 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. Partly offsetting these increases,
lower gas and oil production decreased earnings by
$12.5 million and $4.0 million, respectively. Further
contributing to the decrease were higher general and
administrative and other operating costs ($2.0 million) and
higher lease operating expenses ($1.9 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 were 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.
ENERGY
MARKETING
Revenues
Energy
Marketing Operating Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended September 30
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(Thousands)
|
|
|
Natural Gas (after Hedging)
|
|
$
|
413,405
|
|
|
$
|
496,769
|
|
|
$
|
329,560
|
|
Other
|
|
|
207
|
|
|
|
300
|
|
|
|
154
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
413,612
|
|
|
$
|
497,069
|
|
|
$
|
329,714
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy
Marketing Volumes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended September 30
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
Natural Gas (MMcf)
|
|
|
50,775
|
|
|
|
45,270
|
|
|
|
40,683
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007
Compared with 2006
Operating revenues for the Energy Marketing segment decreased
$83.5 million in 2007 as compared with 2006. The decrease
primarily reflects lower gas sales revenue due to a decrease in
natural gas commodity prices for the period that were recovered
through revenues, offset in part by an increase in throughput.
The increase in throughput was due to the addition of certain
large, low-margin commercial and industrial customers, an
increase in sales to wholesale customers, and colder weather.
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
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.
Earnings
2007
Compared with 2006
The Energy Marketing segments earnings in 2007 were
$7.7 million, an increase of $1.9 million when
compared with earnings of $5.8 million in 2006. Higher
margins of $2.3 million are responsible for the increase in
earnings. The increase in margin is mainly the result of a
$2.3 million reversal of an accrual for purchased gas
expense related to the resolution of a contingency during 2007.
While throughput increased, as noted above, much of this
increase in volume is related to sales to low margin customers.
41
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.
TIMBER
Revenues
Timber
Operating Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended September 30
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(Thousands)
|
|
|
Log Sales
|
|
$
|
21,927
|
|
|
$
|
23,077
|
|
|
$
|
22,478
|
|
Green Lumber Sales
|
|
|
5,097
|
|
|
|
7,123
|
|
|
|
7,296
|
|
Kiln-dried Lumber Sales
|
|
|
27,908
|
|
|
|
32,809
|
|
|
|
29,651
|
|
Other
|
|
|
3,965
|
|
|
|
2,020
|
|
|
|
1,861
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
58,897
|
|
|
$
|
65,029
|
|
|
$
|
61,286
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Timber
Board Feet
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended September 30
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(Thousands)
|
|
|
Log Sales
|
|
|
8,660
|
|
|
|
9,527
|
|
|
|
7,601
|
|
Green Lumber Sales
|
|
|
9,358
|
|
|
|
10,454
|
|
|
|
10,489
|
|
Kiln-dried Lumber Sales
|
|
|
14,778
|
|
|
|
16,862
|
|
|
|
15,491
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
32,796
|
|
|
|
36,843
|
|
|
|
33,581
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007
Compared with 2006
Operating revenues for the Timber segment decreased
$6.1 million in 2007 as compared with 2006. This decrease
is attributed to unfavorable weather conditions primarily during
the fall of 2006 and the spring of 2007 that greatly limited the
harvesting of logs. These conditions consisted of warm, wet
weather that made it difficult to bring logging trucks into the
forests. Weather conditions were significantly more favorable
throughout fiscal 2006. These unfavorable conditions for
harvesting resulted in a decline in log sales of
$1.2 million or 867,000 board feet. There was also a
decline in both green lumber and kiln-dried lumber sales of
$2.0 million and $4.9 million, respectively, primarily
because there were fewer logs available for processing. Declines
in market prices for the cherry and maple species also
contributed to the decrease in green lumber and kiln-dried
lumber sales. Additionally, the processing of a greater amount
of lumber species other than cherry (due to the mix of species
on the areas being harvested) contributed to the decline in
kiln-dried lumber sales since lumber species other than cherry
are sold at a lower price than kiln-dried cherry lumber. With
the addition of two new kilns placed into service in June 2007
that allow for greater processing capacity, the Company plans to
continue to focus on increasing cherry kiln-dried lumber sales
since cherry kiln-dried lumber commands a higher price in the
overall mix of lumber. Offsetting the decreases discussed above,
other revenues increased $1.9 million largely due to the
sale of 3.1 million board feet of timber rights
($1.6 million).
42
2006
Compared with 2005
Operating revenues for the Timber segment increased
$3.7 million in 2006 as compared with 2005. This increase
is attributed to an increase in kiln-dried lumber sales of
$3.2 million primarily due to an increase in kiln-dried
cherry lumber sales volumes of 2.0 million board feet.
Other kiln-dried lumber sales volumes 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.
Earnings
2007
Compared with 2006
The Timber segment earnings in 2007 were $3.7 million, a
decrease of $2.0 million when compared with earnings of
$5.7 million in 2006. The decrease was primarily due to
lower margins from lumber and log sales ($2.5 million) as a
result of the decline in revenues noted above, as well as higher
general and administrative expenses of $0.3 million.
Partially offsetting this decrease was a decline in depletion
expense of $1.2 million. The decrease in depletion expense
reflects the cutting of more low cost or no cost basis timber
from Company owned land as well as the overall decrease in logs
harvested.
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-dried lumber
sales and cherry export log sales accounted for the earnings
increase.
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
Income from Unconsolidated Subsidiaries on the Consolidated
Statements 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 assets. The former International
segment activity primarily consists of project development
activities in Italy and Bulgaria.
Earnings
2007
Compared with 2006
All Other and Corporate operations had earnings of
$8.1 million in 2007, an increase of $7.9 million
compared with earnings of $0.2 million for 2006. This
improvement was largely due to an increase in interest income of
$4.1 million (primarily intercompany interest). In the All
Other category, Horizon LFGs earnings benefited from
higher margins of $1.0 million in 2007 as compared to 2006,
and Horizon Powers income from unconsolidated subsidiaries
increased $0.9 million, also contributing to the increase
in earnings. The Corporate and All Other categories also had an
earnings benefit associated with a lower effective tax rate
($2.0 million).
43
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. 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. The Company 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. 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).
INTEREST
INCOME
Interest income was $7.9 million lower in 2007 as compared
to 2006. As discussed in the Utility earnings section above, the
main reason for this decrease was lower interest income of
$7.4 million on a pension-related regulatory asset in
accordance with the 2005 New York rate agreement. The New York
divisions 2005 rate agreement with the NYPSC allows the
Company to accrue interest on a pension-related regulatory
asset. The amount of the interest that can be accrued is reduced
as the funded status of the pension plan improves. The fair
market value of the pension plan assets exceeded the accumulated
benefit obligation at September 30, 2007 resulting in a
significant reduction in the interest accrual related to this
regulatory asset in 2007.
Interest income was $3.2 million higher in 2006 as 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 regulatory
asset in accordance with the New York rate agreement increased
by $0.5 million.
OTHER
INCOME
Other income was $2.1 million higher in 2007 as compared to
2006. The increase is attributed to a death benefit gain on life
insurance proceeds of $1.9 million recognized in the
Corporate category.
Other income was $9.9 million lower in 2006 as 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.
INTEREST
CHARGES
Although most of the variances in Interest Charges are discussed
in the earnings discussion by segment above, the following is a
summary on a consolidated basis:
Interest on long-term debt decreased $4.2 million in 2007
and $0.6 million in 2006. The decrease in 2007 was
primarily the result of a lower average amount of long-term debt
outstanding. In addition, the Company recognized a
$1.9 million benefit to interest expense as a result of the
discontinuance of hedge accounting for Empires interest
rate collar, as discussed above under Pipeline and Storage. The
underlying long-term debt associated with this interest rate
collar was repaid in December 2006 and the unrealized gain
recorded in accumulated other comprehensive income associated
with the interest rate collar was reclassified to interest
expense during the quarter ended December 31, 2006.
Other interest charges were $0.1 million higher in 2007 and
$3.1 million lower in 2006. The decrease in 2006 resulted
primarily from the non-recurrence of $2.1 million of
interest expense recorded by the Utility segment in 2005 and a
lower average amount of short-term debt outstanding during 2006.
The $2.1 million of interest expense recorded in 2005
related to an adjustment to a regulatory liability for previous
over-collections of New York State gross receipts tax.
44
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
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(Millions)
|
|
|
Provided by Operating Activities
|
|
$
|
394.2
|
|
|
$
|
471.4
|
|
|
$
|
317.3
|
|
Capital Expenditures
|
|
|
(276.7
|
)
|
|
|
(294.2
|
)
|
|
|
(219.5
|
)
|
Investment in Partnership
|
|
|
(3.3
|
)
|
|
|
|
|
|
|
|
|
Net Proceeds from Sale of Foreign Subsidiaries
|
|
|
232.1
|
|
|
|
|
|
|
|
111.6
|
|
Cash Held in Escrow
|
|
|
(58.2
|
)
|
|
|
|
|
|
|
|
|
Net Proceeds from Sale of Oil and Gas Producing Properties
|
|
|
5.1
|
|
|
|
|
|
|
|
1.4
|
|
Other Investing Activities
|
|
|
(0.8
|
)
|
|
|
(3.2
|
)
|
|
|
3.2
|
|
Change in Short-Term Debt
|
|
|
|
|
|
|
|
|
|
|
(115.4
|
)
|
Reduction of Long-Term Debt
|
|
|
(119.6
|
)
|
|
|
(9.8
|
)
|
|
|
(13.3
|
)
|
Issuance of Common Stock
|
|
|
17.5
|
|
|
|
23.3
|
|
|
|
20.3
|
|
Dividends Paid on Common Stock
|
|
|
(100.6
|
)
|
|
|
(98.2
|
)
|
|
|
(94.1
|
)
|
Dividends Paid to Minority Interest
|
|
|
|
|
|
|
|
|
|
|
(12.7
|
)
|
Excess Tax Benefits Associated with Stock- Based Compensation
Awards
|
|
|
13.7
|
|
|
|
6.5
|
|
|
|
|
|
Shares Repurchased under Repurchase Plan
|
|
|
(48.1
|
)
|
|
|
(85.2
|
)
|
|
|
|
|
Effect of Exchange Rates on Cash
|
|
|
(0.1
|
)
|
|
|
1.4
|
|
|
|
1.3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Increase in Cash and Temporary Cash Investments
|
|
$
|
55.2
|
|
|
$
|
12.0
|
|
|
$
|
0.1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 and
gain on 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 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 and futures
contracts in an attempt to manage this energy commodity price
risk.
Net cash provided by operating activities totaled
$394.2 million in 2007, a decrease of $77.2 million
compared with the $471.4 million provided by operating
activities in 2006. Higher working capital requirements in the
Exploration and Production, Utility, and Pipeline and Storage
segments were partially offset by lower working capital
requirements in the Energy Marketing segment.
45
INVESTING
CASH FLOW
Expenditures
for Long-Lived Assets
The Companys expenditures for long-lived assets associated
with continuing operations totaled $250.9 million in 2007.
The table below presents these expenditures:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended September 30, 2007
|
|
|
|
|
|
|
|
|
|
Total Expenditures
|
|
|
|
Capital
|
|
|
Investment
|
|
|
For Long-Lived
|
|
|
|
Expenditures
|
|
|
in Partnership
|
|
|
Assets
|
|
|
|
(Millions)
|
|
|
Utility
|
|
$
|
54.2
|
|
|
$
|
|
|
|
$
|
54.2
|
|
Pipeline and Storage
|
|
|
43.2
|
|
|
|
|
|
|
|
43.2
|
|
Exploration and Production
|
|
|
146.7
|
|
|
|
|
|
|
|
146.7
|
|
Timber
|
|
|
3.7
|
|
|
|
|
|
|
|
3.7
|
|
All Other and Corporate
|
|
|
(0.2
|
)
|
|
|
3.3
|
|
|
|
3.1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Expenditures from Continuing Operations(1)
|
|
$
|
247.6
|
|
|
$
|
3.3
|
|
|
$
|
250.9
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Excludes expenditures for long-lived assets associated with
discontinued operations of $29.1 million. |
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. It also reflects $15.5 million of costs related to
the Empire Connector project that were added to Construction
Work in Progress during 2007. The Empire Connector project is
discussed below under Estimated Capital Expenditures.
Exploration
and Production
The Exploration and Production segments capital
expenditures were primarily well drilling and completion
expenditures and included approximately $66.2 million for
the Gulf Coast region ($65.7 million for the off-shore
program in the Gulf of Mexico), $41.4 million for the West
Coast region and $39.1 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 projected royalty relief. These
amounts included approximately $30.3 million spent to
develop proved undeveloped reserves.
Timber
The majority of the Timber segment capital expenditures were for
the construction of two new kilns that were placed into service
during the quarter ended June 30, 2007, as well as
construction of a lumber sorter for Highlands sawmill
operations, which was placed into service in October 2007.
All Other
and Corporate
The majority of the All Other and Corporate category
expenditures for long-lived assets consisted of a
$3.3 million capital contribution to Seneca Energy by
Horizon Power, $1.65 million in each of the first and
second quarters of fiscal 2007. Seneca Energy generates and
sells electricity using methane gas obtained from landfills
owned by outside parties. Seneca Energy is in the process of
expanding its generating capacity from 11.2 megawatts to 17.6
megawatts. Horizon Power has funded its capital contributions
with short-term borrowings.
46
Estimated
Capital Expenditures
The Companys estimated capital expenditures for the next
three years are:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended September 30
|
|
|
|
2008
|
|
|
2009
|
|
|
2010
|
|
|
|
(Millions)
|
|
|
Utility
|
|
$
|
59.0
|
|
|
$
|
57.0
|
|
|
$
|
56.0
|
|
Pipeline and Storage
|
|
|
152.0
|
|
|
|
96.0
|
|
|
|
40.0
|
|
Exploration and Production(1)
|
|
|
154.0
|
|
|
|
146.0
|
|
|
|
143.0
|
|
Timber
|
|
|
1.0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
366.0
|
|
|
$
|
299.0
|
|
|
$
|
239.0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Includes estimated expenditures for the years ended
September 30, 2008, 2009 and 2010 of approximately
$33 million, $36 million and $27 million,
respectively, to develop proved undeveloped reserves. |
Estimated capital expenditures for the Utility segment in 2008
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 2008 includes $122.9 million for the Empire
Connector project as discussed below. Other capital expenditures
will be concentrated in the replacement of transmission and
storage lines, reconditioning of storage wells and improvements
of compressor stations.
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
asked that Empires existing business and facilities be
brought under FERC jurisdiction, and that the FERC approve rates
for Empires existing and proposed services. The Empire
Connector will provide an upstream supply link for the
Millennium Pipeline, which began construction in June 2007, and
will transport Canadian and other natural gas supplies to
downstream customers. The Empire Connector is designed to move
up to approximately 250 MDth of natural gas per day. On
December 21, 2006, the FERC issued an order granting a
Certificate of Public Convenience and Necessity authorizing the
construction and operation of the Empire Connector and various
other related pipeline projects by other unaffiliated companies,
which has been accepted by Empire and the other applicants. In
June 2007, Empire and KeySpan Gas East Corporation (KeySpan)
executed a binding firm transportation service agreement for
150.75 MDth per day, obligating Empire to provide transportation
service that will require construction of the Empire Connector
project. Construction of the Empire Connector began in September
2007 and the planned in-service date is November 2008. 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 two years are as follows:
$122.9 million in 2008 and $34.4 million in 2009.
These expenditures are included as Pipeline and Storage
estimated capital expenditures in the table above. The total
cost to the Company of the Empire Connector project is estimated
at $177 million, after giving effect to sales tax
exemptions worth approximately $3.7 million. The Company
anticipates financing this project with cash on hand
and/or
through the use of the Companys lines of credit. As of
September 30, 2007, the Company had incurred approximately
$19.7 million in costs related to this project. Of this
amount, $13.7 million, $2.0 million and
$3.4 million were incurred during the years ended
September 30, 2007, 2006 and 2005, respectively. During the
quarter ended June 30, 2007, the Company reversed the
reserve established for these costs, as discussed above under
Results of Operations, following the execution of the KeySpan
service agreement. As of September 30, 2007, all of the
costs incurred to date related to this project have been
capitalized as either Construction Work in Progress
($15.5 million) or Materials and Supplies Inventory
($4.2 million), as per the accounting guidance in the
FERCs Uniform System of Accounts and SFAS 71.
47
Supply Corporation continues to view its potential Tuscarora
Extension project as an important link to Millennium and
potential storage development in the Corning, New York area.
This 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, could 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. Supply Corporation is also developing a
project to meet the results of an Open Season
seeking customers for new capacity from the Rockies Express
Project, Appalachian production, storage and other points to
Leidy and to interconnections with Millennium and Empire at
Corning. This new project (the West to East Project)
could include the Tuscarora Extension, or could be a second
phase following the development of that project. The timeline of
both of these projects depends 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 lines of credit. The
capital cost of the West to East project could amount to
$700 million, which would be financed by a combination of
debt and equity. There have been no costs incurred by the
Company related to either project as of September 30, 2007,
and the forecasted expenditures for the Tuscarora Extension
Project over the next three years are as follows: $0 in 2008,
$34.0 million in 2009, and $15.0 million in 2010.
These expenditures are included as Pipeline and Storage
estimated capital expenditures in the table above. The Company
has not yet forecast any expenditures for the West to East
Project. The Company has not yet filed an application with the
FERC for the authority to build either project.
Estimated capital expenditures in 2008 for the Exploration and
Production segment include approximately $50.0 million for
the Gulf Coast region ($48.0 million on the off-shore
program in the Gulf of Mexico), $46.0 million for the West
Coast region and $58.0 million for the Appalachian region.
Estimated capital expenditures in 2008 in the Timber segment
will be concentrated on the purchase of new equipment, vehicles
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, 2007.
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, repurchases of stock, 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 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 $455.0 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, 2007, the Companys debt to
capitalization ratio (as calculated under the facility) was .38.
The constraints specified in the committed credit facility would
permit an additional $2.02 billion in short-term
48
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, 2007, the Company would have been permitted
to issue up to a maximum of $1.4 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 40%) of the Companys long-term
debt (as of September 30, 2007) 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 any of 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, 2007, 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, 2007 and September 30, 2006. 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 these securities if warranted by market conditions
and the Companys capital requirements. Any offer and sale
of these 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 April 30, 2007, the Company redeemed $96.3 million
of 6.5% unsecured notes, plus accrued interest. These notes were
redeemable by the Company at par at any time after
September 15, 2006. On December 8, 2006, the Company
repaid $22.8 million of Empires secured debt. Such
amount was classified as Current Portion of Long-Term Debt on
the Companys Consolidated Balance Sheet at
September 30, 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. As of
September 30, 2007, the Company has repurchased
3,834,878 shares for $133.2 million under this
program, including 1,308,328 shares for $48.1 million
during fiscal 2007. These share repurchases were funded with
cash provided by operating activities
and/or
through the use of the Companys lines of credit. 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 lines of credit. It is
expected that open market repurchases will continue from time to
time depending on market conditions.
49
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 $35.5 million.
These leases have been entered into for the use of buildings,
vehicles, construction tools, meters 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
$4.8 million. The Company has guaranteed 50%, or
$2.4 million, of these capital lease commitments.
CONTRACTUAL
OBLIGATIONS
The following table summarizes the Companys expected
future contractual cash obligations as of September 30,
2007, and the twelve-month periods over which they occur:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payments by Expected Maturity Dates
|
|
|
|
2008
|
|
|
2009
|
|
|
2010
|
|
|
2011
|
|
|
2012
|
|
|
Thereafter
|
|
|
Total
|
|
|
|
(Millions)
|
|
|
Long-Term Debt, including interest expense(1)
|
|
$
|
259.8
|
|
|
$
|
148.4
|
|
|
$
|
45.5
|
|
|
$
|
232.7
|
|
|
$
|
171.8
|
|
|
$
|
439.3
|
|
|
$
|
1,297.5
|
|
Operating Lease Obligations
|
|
$
|
6.7
|
|
|
$
|
5.8
|
|
|
$
|
4.4
|
|
|
$
|
2.9
|
|
|
$
|
2.6
|
|
|
$
|
13.1
|
|
|
$
|
35.5
|
|
Capital Lease Obligations
|
|
$
|
0.9
|
|
|
$
|
0.5
|
|
|
$
|
0.4
|
|
|
$
|
0.4
|
|
|
$
|
0.2
|
|
|
$
|
|
|
|
$
|
2.4
|
|
Purchase Obligations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas Purchase Contracts(2)
|
|
$
|
718.1
|
|
|
$
|
67.2
|
|
|
$
|
7.1
|
|
|
$
|
2.8
|
|
|
$
|
2.8
|
|
|
$
|
16.2
|
|
|
$
|
814.2
|
|
Transportation and Storage Contracts
|
|
$
|
48.4
|
|
|
$
|
47.3
|
|
|
$
|
43.7
|
|
|
$
|
19.3
|
|
|
$
|
6.0
|
|
|
$
|
7.1
|
|
|
$
|
171.8
|
|
Empire Connector Project Obligations(3)
|
|
$
|
118.3
|
|
|
$
|
0.6
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
118.9
|
|
Other
|
|
$
|
20.5
|
|
|
$
|
9.6
|
|
|
$
|
6.0
|
|
|
$
|
4.2
|
|
|
$
|
3.7
|
|
|
$
|
14.2
|
|
|
$
|
58.2
|
|
|
|
|
(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. |
|
(3) |
|
The Empire Connector is scheduled to be placed in service by
November 2008, at an estimated cost of $177 million. The
Company has only committed itself to $118.9 million for the
project at September 30, 2007. |
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 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 could have a
material effect on earnings and cash flows in the period in
which they are resolved, they are not
50
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 73%
of the Companys 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 2007, the Company contributed
$24.9 million to the Retirement Plan. The Company
anticipates that the annual contribution to the Retirement Plan
in 2008 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
a majority of its 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 2007, the Company
contributed $42.3 million to the Post-Retirement Plan. The
Company anticipates that the annual contribution to the
Post-Retirement Plan in 2008 will be in the range of
$25.0 million to $35.0 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 which existed at September 30,
2006, was fully utilized in 2007 in connection with the gain
recognized on the sale of SECI.
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
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, 2007 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 various national natural gas
publications 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 settlement prices by expected maturity date as
of September 30, 2007. At September 30, 2007, 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
|
|
|
|
2008
|
|
|
2009
|
|
|
Total
|
|
|
Notional Quantities (Equivalent Bcf)
|
|
|
12.2
|
|
|
|
1.0
|
|
|
|
13.2
|
|
Weighted Average Fixed Rate (per Mcf)
|
|
$
|
8.15
|
|
|
$
|
8.82
|
|
|
$
|
8.20
|
|
Weighted Average Variable Rate (per Mcf)
|
|
$
|
7.77
|
|
|
$
|
9.08
|
|
|
$
|
7.86
|
|
51
Crude
Oil Price Swap Agreements
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expected Maturity Dates
|
|
|
|
2008
|
|
|
2009
|
|
|
Total
|
|
|
Notional Quantities (Equivalent bbls)
|
|
|
1,305,000
|
|
|
|
180,000
|
|
|
|
1,485,000
|
|
Weighted Average Fixed Rate (per bbl)
|
|
$
|
57.72
|
|
|
$
|
54.70
|
|
|
$
|
57.35
|
|
Weighted Average Variable Rate (per bbl)
|
|
$
|
78.69
|
|
|
$
|
74.31
|
|
|
$
|
78.16
|
|
At September 30, 2007, the Company would have received from
its respective counterparties an aggregate of approximately
$2.8 million to terminate the natural gas price swap
agreements outstanding at that date. The Company would have had
to pay an aggregate of approximately $11.2 million to its
counterparties to terminate the crude oil price swap agreements
outstanding at September 30, 2007.
At September 30, 2006, the Company had natural gas price
swap agreements covering 7.4 Bcf at a weighted average
fixed rate of $7.24 per Mcf. The Company also had crude oil
price swap agreements covering 900,000 bbls at a weighted
average fixed rate of $37.13 per bbl. The increase in natural
gas price swap agreements from September 2006 to September 2007
is largely attributable to managements decision to utilize
fewer collars and more swaps. This decision was as a result of
market conditions being less conducive to using collars than
they were in the prior year. The increase in crude oil price
swap agreements is primarily due to an increased availability of
counterparties willing to enter into new swap agreements with
terms that match the delivery points of its West Coast crude oil
production.
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, 2007, the Company had not
entered into any natural gas or crude oil no cost collars
extending beyond 2008.
No
Cost Collars
|
|
|
|
|
|
|
Expected
|
|
|
|
Maturity
|
|
|
|
Date
|
|
|
|
2008
|
|
|
Natural Gas
|
|
|
|
|
Notional Quantities (Equivalent Bcf)
|
|
|
1.4
|
|
Weighted Average Ceiling Price (per Mcf)
|
|
$
|
16.45
|
|
Weighted Average Floor Price (per Mcf)
|
|
$
|
8.83
|
|
At September 30, 2007, the Company would have received an
aggregate of approximately $1.9 million to terminate the
natural gas no cost collars outstanding at that date.
At September 30, 2006, the Company had natural gas no cost
collars covering 7.1 Bcf at a weighted average floor price
of $8.26 per Mcf and a weighted average ceiling price of $17.25
per Mcf. The Company also had crude oil no cost collars covering
180,000 bbls at 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 decrease in natural gas collars
from September 2006 to September 2007 is due to
managements decision to utilize fewer collars and more
swaps. This is due to the market conditions discussed in the
Swap Agreements section.
52
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, 2007, the Company held no futures contracts
with maturity dates extending beyond 2012.
Futures
Contracts
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expected Maturity Dates
|
|
|
|
2008
|
|
|
2009
|
|
|
2010
|
|
|
2011
|
|
|
2012
|
|
|
Total
|
|
|
Net Contract Volumes Purchased (Sold)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Equivalent Bcf)
|
|
|
2.9
|
|
|
|
(0.1
|
)
|
|
|
|
|
|
|
|
(1)
|
|
|
|
(1)
|
|
|
2.8
|
|
Weighted Average Contract Price (per Mcf)
|
|
$
|
9.08
|
|
|
$
|
9.50
|
|
|
|
NA
|
|
|
$
|
6.99
|
|
|
$
|
8.68
|
|
|
$
|
9.11
|
|
Weighted Average Settlement Price (per Mcf)
|
|
$
|
8.94
|
|
|
$
|
9.13
|
|
|
|
NA
|
|
|
$
|
6.31
|
|
|
$
|
9.00
|
|
|
$
|
8.96
|
|
|
|
|
(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, 2007, the Company would have received
$2.2 million to terminate these futures contracts.
At September 30, 2006, the Company had futures contracts
covering 7.0 Bcf (net long position) at a weighted average
contract price of $9.67 per Mcf.
The decrease in net long positions at September 30, 2007 as
compared to September 30, 2006 is attributed to fewer
customers entering into fixed price sales commitments at
September 30, 2007 as compared to September 30, 2006.
Management believes this is due to the lack of a significant
decrease in natural gas prices at the end of 2007 as compared to
2006, sufficient natural gas in storage throughout the United
States, and forecasts for a mild winter. As a result, the Energy
Marketing segment had purchased fewer futures contracts as of
September 30, 2007 as compared to September 30, 2006
to hedge against a lower number of fixed price sales commitments.
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 many of the parent companies of the respective
counterparties to its derivatives. At September 30, 2007,
the Company used nine counterparties for its over-the-counter
derivatives. At September 30, 2007, no individual
counterparty represented greater than 32% 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, 2007.
Exchange
Rate Risk
The Exploration and Production segments investment in
Canada was valued in Canadian dollars, and, as such, this
investment was 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
resulted in increases or decreases to the CTA, a component of
Accumulated Other Comprehensive Income (Loss) on the
Consolidated Balance Sheets. When the foreign currency increased
in value in relation to the U.S. dollar, there was a
positive adjustment to CTA. When the foreign currency decreased
in value in relation to the U.S. dollar, there was a
negative adjustment to CTA. In August 2007, the Exploration and
Production segments investment in Canada was sold,
eliminating the Companys major foreign operations. Of the
$232.1 million in net proceeds received, $58.0 million
was placed in escrow (denominated in Canadian dollars) pending
receipt of a tax clearance certificate from the Canadian
government. To hedge against foreign currency exchange risk, the
Company entered into a $58.0 million forward contract to
sell Canadian dollars. At September 30, 2007, due to the
increase in the strength of the Canadian dollar versus the
U.S. dollar, the Company had a $2.7 million derivative
53
liability related to the collar. The Company records gains or
losses associated with this forward contract directly to the
income statement.
Interest
Rate Risk
On December 8, 2006, the Company repaid $22.8 million
of Empires secured debt. The interest costs of this
secured debt were hedged by an interest rate collar. Since the
hedged transaction was settled and there will be no future cash
flows associated with the secured debt, hedge accounting for the
interest rate collar was discontinued and the unrealized gain in
accumulated other comprehensive income associated with the
interest rate collar was reclassified to the Consolidated
Statement of Income.
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, 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Principal Amounts by Expected Maturity Dates
|
|
|
|
2008
|
|
|
2009
|
|
|
2010
|
|
|
2011
|
|
|
2012
|
|
|
Thereafter
|
|
|
Total
|
|
|
|
(Dollars in millions)
|
|
|
Long-Term Fixed Rate Debt
|
|
$
|
200.0
|
(1)
|
|
$
|
100.0
|
|
|
$
|
|
|
|
$
|
200.0
|
|
|
$
|
150.0
|
|
|
$
|
349.0
|
|
|
$
|
999.0
|
|
Weighted Average Interest Rate Paid
|
|
|
6.3
|
%
|
|
|
6.0
|
%
|
|
|
|
|
|
|
7.5
|
%
|
|
|
6.7
|
%
|
|
|
5.9
|
%
|
|
|
6.4
|
%
|
Fair Value = $1,024.4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
These notes have been classified as Current Portion of Long-Term
Debt on the Companys Consolidated Balance Sheet. |
RATE AND
REGULATORY MATTERS
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 rate agreement,
substantially as filed, for an effective date of August 1,
2005. The rate agreement provided 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
until new rates should go into effect, the return on equity
level above which earnings must be shared with rate payers is
11.5%.
On January 29, 2007, Distribution Corporation commenced a
rate case by filing proposed tariff amendments and supporting
testimony requesting approval to increase its annual revenues by
$52.0 million. Following standard procedure, the NYPSC
suspended the proposed tariff amendments to enable its staff and
intervenors to conduct a routine investigation and hold
hearings. Distribution Corporation explained in the filing that
its request for rate relief is necessitated by decreased
revenues resulting from customer conservation efforts and
increased customer uncollectibles, among other things. The rate
filing also includes a proposal for an aggressive efficiency and
conservation initiative with a revenue decoupling mechanism
designed to render the Company indifferent to throughput
reductions resulting from conservation. On September 20,
2007, the NYPSC issued an order approving, with modifications,
the Companys conservation program for implementation on an
accelerated basis. Associated ratemaking issues, however, were
reserved for consideration in the rate case. On
September 28, 2007, an administrative law judge assigned to
the proceeding issued a
54
recommended decision (RD) based on a review and analysis of the
evidence presented in the case. The RD recommends a rate
increase designed to provide additional annual revenues of
$2.5 million, together with a bill surcharge that would
collect up to $10.8 million to recover expenses arising
from the conservation program. The recommended cost of equity,
subject to updates, is 9.4%. The RD also recommends approval of
the unopposed revenue decoupling mechanism. The NYPSC is not
bound to accept the RD, and may accept, reject or modify the
Companys filing. Assuming standard procedure, rates would
become effective in late December 2007. The outcome of the
proceeding cannot be ascertained at this time.
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 annual 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 the new rates became
effective January 1, 2007.
On June 8, 2006, the NTSB issued safety recommendations to
Distribution Corporation, the PaPUC and certain other parties 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.
Without admitting liability, Distribution Corporation settled
all significant third-party claims against it related to the
explosion.
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 implemented
those recommendations. In December 2006, the NTSB classified its
recommendations as closed after determining that
Distribution Corporation took acceptable action with respect to
the recommendations.
The NTSBs 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 has worked cooperatively with the Staff
of the PaPUC to permit the PaPUC to undertake the analysis
recommended by the NTSB.
In late November 2007, Distribution Corporation reached a
Settlement Agreement with the Law Bureau Prosecutory Staff of
the PaPUC (the Law Bureau) regarding the explosion
and the PaPUCs subsequent investigation. The Law Bureau
and Distribution Corporation will jointly submit this Settlement
Agreement to the PaPUC for approval. In the Settlement
Agreement, Distribution Corporation agrees, without admitting
liability, to pay a $50,000 fine and to fund an additional
$30,000 of safety-related activities. Distribution Corporation
also agrees to make various improvements to its butt-fusion
procedures and to implement a program to review existing
butt-fusions.
Pipeline
and Storage
Supply Corporation currently does not have a rate case on file
with the FERC. The rate settlement approved by the FERC on
February 9, 2007 requires Supply Corporation to make a
general rate filing to be effective December 1, 2011, and
bars Supply Corporation from making a general rate filing before
then, with some exceptions specified in the settlement.
55
Empire currently does not have a rate case on file with the
NYPSC. Among the issues resolved in connection with
Empires FERC application to build the Empire Connector are
the rates and terms of service that will become applicable to
all of Empires business, effective upon Empire
constructing and placing its new facilities into service
(currently expected for November 2008). At that time, Empire
will become an interstate pipeline subject to FERC regulation.
The order described in the following paragraph requires Empire
to make a filing at FERC within three years after the in-service
date justifying Empires existing recourse rates or
proposing alternative rates.
The FERC issued on December 21, 2006 an order granting a
Certificate of Public Convenience and Necessity authorizing the
construction and operation of the Empire Connector and various
other related pipeline projects by other unaffiliated companies.
The Empire Certificate contains various environmental and other
conditions. Empire has accepted that Certificate. Additional
environmental permits from the U.S. Army Corps of Engineers
and state environmental agencies have been received. Empire has
also received, from all six upstate New York counties in which
it would build the Empire Connector project, final approval of
sales tax exemptions and temporary partial property tax
abatements necessary to enable the Empire Connector to generate
a fair return. In June 2007, Empire signed a firm transportation
service agreement with KeySpan Gas East Corporation, under which
Empire is obligated to provide transportation service that will
require construction of this project. Construction began in
September 2007 and is planned to be complete by November 1,
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 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. At September 30, 2007, the
Company has estimated its remaining
clean-up
costs related to former manufactured gas plant sites and third
party waste disposal sites will be in the range of
$12.1 million to $15.8 million. The minimum estimated
liability of $12.1 million has been recorded on the
Consolidated Balance Sheet at September 30, 2007. 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 June 2006, the FASB issued FIN 48. FIN 48
clarifies the accounting for income taxes by prescribing a
minimum probability threshold that a tax position must meet
before a financial statement benefit is recognized. The minimum
threshold is defined in FIN 48 as a tax position that is
more likely than not to be sustained upon examination by the
applicable taxing authority, including resolution of any related
appeals or litigation processes, based on the technical merits
of the position. If a tax benefit meets this threshold, it is
measured and recognized based on an analysis of the cumulative
probability of the tax benefit being ultimately sustained. The
cumulative effect of applying FIN 48 at adoption, if any,
is reported as an adjustment to opening retained earnings for
the year of adoption. FIN 48 is effective for the first
quarter of the Companys 2008 fiscal year and it is
expected that this pronouncement will not have a material effect
on the Companys consolidated financial statements.
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. SFAS 157 is to be applied whenever
another standard requires or allows assets
56
or liabilities to be measured at fair value. The pronouncement
will be 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 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. Under SFAS 158, certain
previously unrecognized actuarial gains and losses and
previously unrecognized prior service costs for both the pension
and other post-retirement benefit plans as well as a previously
unrecognized transition obligation for the other post-retirement
benefit plan are required to be recognized. These amounts were
not required to be recorded on the Companys Consolidated
Balance Sheet before the adoption of SFAS 158, but were
instead amortized over a period of time. In accordance with
SFAS 158, the Company has recognized the funded status of
its benefit plans and implemented the disclosure requirements of
SFAS 158 at September 30, 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. Currently, the Company
measures its plan assets and benefit obligations using a
June 30th measurement date. At September 30,
2007, in order to recognize the funded status of its pension and
post-retirement benefit plans in accordance with SFAS 158,
the Company recorded additional liabilities or reduced assets by
a cumulative amount of $78.7 million ($71.1 million
net of deferred tax benefits recognized for the portion recorded
as an increase to Accumulated Other Comprehensive Loss). Of the
$71.1 million recognized, $61.9 million was recorded
as an increase to Other Regulatory Assets in the Companys
Utility and Pipeline and Storage segments, $12.5 million
(net of deferred tax benefits of $7.6 million) was recorded
as an increase to Accumulated Other Comprehensive Loss, and
$3.3 million was recorded as an increase to Other
Regulatory Liabilities in the Companys Utility segment.
The Company has recorded amounts to Other Regulatory Assets or
Other Regulatory Liabilities in the Utility and Pipeline and
Storage segments in accordance with the provisions of
SFAS 71. The Company, in those segments, has certain
regulatory commission authorizations, which allow the Company to
defer as a regulatory asset or liability the difference between
pension and post-retirement benefit costs as calculated in
accordance with SFAS 87 and SFAS 106 and what is
collected in rates. Refer to Item 8 at
Note G Retirement Plan and Other
Post-Retirement Benefits for further disclosures regarding the
impact of SFAS 158 on the Companys consolidated
financial statements.
In February 2007, the FASB issued
SFAS 159. SFAS 159 permits entities to choose to
measure many financial instruments and certain other items at
fair value that are not otherwise required to be measured at
fair value under GAAP. A company that elects the fair value
option for an eligible item will be required to recognize in
current earnings any changes in that items fair value in
reporting periods subsequent to the date of adoption.
SFAS 159 will be effective as of the Companys first
quarter of fiscal 2009. The Company is currently evaluating the
impact, if any, that the adoption of SFAS 159 will have on
its consolidated financial statements.
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
57
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, statements regarding future prospects, plans,
performance and capital structure, anticipated capital
expenditures, completion of construction projects, projections
for pension and other post-retirement benefit obligations,
impacts of the adoption of new accounting rules, and possible
outcomes of litigation or regulatory proceedings, as well as
statements that are identified by the use of the words
anticipates, estimates,
expects, forecasts, intends,
plans, predicts, projects,
believes, seeks, will and
may 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 economic conditions, including economic disruptions
caused by terrorist activities, acts of war or major accidents;
|
|
2.
|
Changes in demographic patterns and weather conditions,
including the occurrence of severe weather such as hurricanes;
|
|
3.
|
Changes in the availability
and/or price
of natural gas or oil and the effect of such changes on the
accounting treatment of derivative financial instruments or the
valuation of the Companys natural gas and oil reserves;
|
|
4.
|
Uncertainty of oil and gas reserve estimates;
|
|
5.
|
Ability to successfully identify, drill for and produce
economically viable natural gas and oil reserves;
|
|
6.
|
Significant changes from expectations in the Companys
actual production levels for natural gas or oil;
|
|
7.
|
Changes in the availability
and/or price
of derivative financial instruments;
|
|
8.
|
Changes in the price differentials between various types of oil;
|
|
9.
|
Inability to obtain new customers or retain existing ones;
|
|
10.
|
Significant changes in competitive factors affecting the Company;
|
|
11.
|
Changes in laws and regulations to which the Company is subject,
including changes in tax, environmental, safety and employment
laws and regulations;
|
|
12.
|
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;
|
|
13.
|
Unanticipated impacts of restructuring initiatives in the
natural gas and electric industries;
|
|
14.
|
Significant changes from expectations in actual capital
expenditures and operating expenses and unanticipated project
delays or changes in project costs or plans;
|
|
15.
|
The nature and projected profitability of pending and potential
projects and other investments, and the ability to obtain
necessary governmental approvals and permits;
|
|
16.
|
Occurrences affecting the Companys ability to obtain funds
from operations, from borrowings under our credit lines or other
credit facilities or from issuances of other short-term notes or
debt or equity securities to finance needed capital expenditures
and other investments, including any downgrades in the
Companys credit ratings;
|
|
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;
|
58
|
|
18.
|
Impairments under the SECs full cost ceiling test for
natural gas and oil reserves;
|
|
19.
|
Significant changes in tax rates or policies or in rates of
inflation or interest;
|
|
20.
|
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;
|
|
21.
|
Changes in accounting principles or the application of such
principles to the Company;
|
|
22.
|
The cost and effects of legal and administrative claims against
the Company;
|
|
23.
|
Changes in actuarial assumptions and the return on assets with
respect to the Companys retirement plan and
post-retirement benefit plans;
|
|
24.
|
Increasing health care costs and the resulting effect on health
insurance premiums and on the obligation to provide
post-retirement benefits; or
|
|
25.
|
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
|
|
|
|
|
62
|
|
|
|
|
63
|
|
|
|
|
64
|
|
|
|
|
65
|
|
|
|
|
66
|
|
Financial Statement Schedules:
|
|
|
|
|
For the three years ended September 30, 2007
|
|
|
|
|
|
|
|
117
|
|
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
(unaudited), 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:
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, 2007 and 2006, and the
results of their operations and their cash flows for each of the
three years in the period ended September 30, 2007 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. Also in our opinion, the
Company maintained, in all material respects, effective internal
control over financial reporting as of September 30, 2007,
based on criteria established in Internal Control
Integrated Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission (COSO). The
Companys management is responsible for these financial
statements and financial statement schedule, for maintaining
effective internal control over financial reporting and for its
assessment of the effectiveness of internal control over
financial reporting, included in Managements Report
on Internal Control Over Financial Reporting appearing
under Item 9A. Our responsibility is to express opinions on
these financial statements, on the financial statement schedule,
and on the Companys internal control over financial
reporting based on our integrated audits. We conducted our
audits in accordance with the standards of the Public Company
Accounting Oversight Board (United States). Those standards
require that we plan and perform the audits to obtain reasonable
assurance about whether the financial statements are free of
material misstatement and whether effective internal control
over financial reporting was maintained in all material
respects. Our audits of the financial statements included
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. Our audit of internal control over financial
reporting included obtaining an understanding of internal
control over financial reporting, assessing the risk that a
material weakness exists, and testing and evaluating the design
and operating effectiveness of internal control based on the
assessed risk. Our audits also included performing such other
procedures as we considered necessary in the circumstances. We
believe that our audits provide 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 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
November 29, 2007
61
NATIONAL
FUEL GAS COMPANY
CONSOLIDATED STATEMENTS OF INCOME AND EARNINGS
REINVESTED
IN THE BUSINESS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended September 30
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(Thousands of dollars, except per common
|
|
|
|
share amounts)
|
|
|
INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Revenues
|
|
$
|
2,039,566
|
|
|
$
|
2,239,675
|
|
|
$
|
1,860,774
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchased Gas
|
|
|
1,018,081
|
|
|
|
1,267,562
|
|
|
|
959,827
|
|
Operation and Maintenance
|
|
|
396,408
|
|
|
|
395,289
|
|
|
|
388,094
|
|
Property, Franchise and Other Taxes
|
|
|
70,660
|
|
|
|
69,202
|
|
|
|
68,164
|
|
Depreciation, Depletion and Amortization
|
|
|
157,919
|
|
|
|
151,999
|
|
|
|
156,502
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,643,068
|
|
|
|
1,884,052
|
|
|
|
1,572,587
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Income
|
|
|
396,498
|
|
|
|
355,623
|
|
|
|
288,187
|
|
Other Income (Expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from Unconsolidated Subsidiaries
|
|
|
4,979
|
|
|
|
3,583
|
|
|
|
3,362
|
|
Impairment of Investment in Partnership
|
|
|
|
|
|
|
|
|
|
|
(4,158
|
)
|
Other Income
|
|
|
4,936
|
|
|
|
2,825
|
|
|
|
12,744
|
|
Interest Income
|
|
|
1,550
|
|
|
|
9,409
|
|
|
|
6,236
|
|
Interest Expense on Long-Term Debt
|
|
|
(68,446
|
)
|
|
|
(72,629
|
)
|
|
|
(73,244
|
)
|
Other Interest Expense
|
|
|
(6,029
|
)
|
|
|
(5,952
|
)
|
|
|
(9,069
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from Continuing Operations Before Income Taxes
|
|
|
333,488
|
|
|
|
292,859
|
|
|
|
224,058
|
|
Income Tax Expense
|
|
|
131,813
|
|
|
|
108,245
|
|
|
|
85,621
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from Continuing Operations
|
|
|
201,675
|
|
|
|
184,614
|
|
|
|
138,437
|
|
Discontinued Operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (Loss) from Operations, Net of Tax
|
|
|
15,479
|
|
|
|
(46,523
|
)
|
|
|
25,277
|
|
Gain on Disposal, Net of Tax
|
|
|
120,301
|
|
|
|
|
|
|
|
25,774
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (Loss) from Discontinued Operations, Net of Tax
|
|
|
135,780
|
|
|
|
(46,523
|
)
|
|
|
51,051
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income Available for Common Stock
|
|
|
337,455
|
|
|
|
138,091
|
|
|
|
189,488
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EARNINGS REINVESTED IN THE BUSINESS
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at Beginning of Year
|
|
|
786,013
|
|
|
|
813,020
|
|
|
|
718,926
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,123,468
|
|
|
|
951,111
|
|
|
|
908,414
|
|
Share Repurchases
|
|
|
38,196
|
|
|
|
66,269
|
|
|
|
|
|
Dividends on Common Stock
|
|
|
101,496
|
|
|
|
98,829
|
|
|
|
95,394
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at End of Year
|
|
$
|
983,776
|
|
|
$
|
786,013
|
|
|
$
|
813,020
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings Per Common Share:
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic:
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from Continuing Operations
|
|
$
|
2.43
|
|
|
$
|
2.20
|
|
|
$
|
1.66
|
|
Income (Loss) from Discontinued Operations
|
|
|
1.63
|
|
|
|
(0.56
|
)
|
|
|
0.61
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income Available for Common Stock
|
|
$
|
4.06
|
|
|
$
|
1.64
|
|
|
$
|
2.27
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted:
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from Continuing Operations
|
|
$
|
2.37
|
|
|
$
|
2.15
|
|
|
$
|
1.63
|
|
Income (Loss) from Discontinued Operations
|
|
|
1.59
|
|
|
|
(0.54
|
)
|
|
|
0.60
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income Available for Common Stock
|
|
$
|
3.96
|
|
|
$
|
1.61
|
|
|
$
|
2.23
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted Average Common Shares Outstanding:
|
|
|
|
|
|
|
|
|
|
|
|
|
Used in Basic Calculation
|
|
|
83,141,640
|
|
|
|
84,030,118
|
|
|
|
83,541,627
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Used in Diluted Calculation
|
|
|
85,301,361
|
|
|
|
86,028,466
|
|
|
|
85,029,131
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See Notes to Consolidated Financial Statements
62
NATIONAL
FUEL GAS COMPANY
CONSOLIDATED BALANCE SHEETS
|
|
|
|
|
|
|
|
|
|
|
At September 30
|
|
|
|
2007
|
|
|
2006
|
|
|
|
(Thousands of dollars)
|
|
|
ASSETS
|
Property, Plant and Equipment
|
|
$
|
4,461,586
|
|
|
$
|
4,703,040
|
|
Less Accumulated Depreciation, Depletion and
Amortization
|
|
|
1,583,181
|
|
|
|
1,825,314
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,878,405
|
|
|
|
2,877,726
|
|
|
|
|
|
|
|
|
|
|
Current Assets
|
|
|
|
|
|
|
|
|
Cash and Temporary Cash Investments
|
|
|
124,806
|
|
|
|
69,611
|
|
Cash Held in Escrow
|
|
|
61,964
|
|
|
|
|
|
Hedging Collateral Deposits
|
|
|
4,066
|
|
|
|
19,676
|
|
Receivables Net of Allowance for Uncollectible
Accounts of $28,654 and $31,427, Respectively
|
|
|
172,380
|
|
|
|
173,671
|
|
Unbilled Utility Revenue
|
|
|
20,682
|
|
|
|
25,538
|
|
Gas Stored Underground
|
|
|
66,195
|
|
|
|
59,461
|
|
Materials and Supplies at average cost
|
|
|
35,669
|
|
|
|
36,693
|
|
Unrecovered Purchased Gas Costs
|
|
|
14,769
|
|
|
|
12,970
|
|
Other Current Assets
|
|
|
45,057
|
|
|
|
63,723
|
|
Deferred Income Taxes
|
|
|
8,550
|
|
|
|
23,402
|
|
|
|
|
|
|
|
|
|
|
|
|
|
554,138
|
|
|
|
484,745
|
|
|
|
|
|
|
|
|
|
|
Other Assets
|
|
|
|
|
|
|
|
|
Recoverable Future Taxes
|
|
|
83,954
|
|
|
|
79,511
|
|
Unamortized Debt Expense
|
|
|
12,070
|
|
|
|
15,492
|
|
Other Regulatory Assets
|
|
|
137,577
|
|
|
|
76,917
|
|
Deferred Charges
|
|
|
5,545
|
|
|
|
3,558
|
|
Other Investments
|
|
|
85,902
|
|
|
|
88,414
|
|
Investments in Unconsolidated Subsidiaries
|
|
|
18,256
|
|
|
|
11,590
|
|
Goodwill
|
|
|
5,476
|
|
|
|
5,476
|
|
Intangible Assets
|
|
|
28,836
|
|
|
|
31,498
|
|
Prepaid Pension and Post-Retirement Benefit Costs
|
|
|
61,006
|
|
|
|
64,125
|
|
Fair Value of Derivative Financial Instruments
|
|
|
9,188
|
|
|
|
11,305
|
|
Deferred Income Taxes
|
|
|
|
|
|
|
9,003
|
|
Other
|
|
|
8,059
|
|
|
|
4,388
|
|
|
|
|
|
|
|
|
|
|
|
|
|
455,869
|
|
|
|
401,277
|
|
|
|
|
|
|
|
|
|
|
Total Assets
|
|
$
|
3,888,412
|
|
|
$
|
3,763,748
|
|
|
|
|
|
|
|
|
|
|
|
CAPITALIZATION AND LIABILITIES
|
Capitalization:
|
|
|
|
|
|
|
|
|
Comprehensive Shareholders Equity
|
|
|
|
|
|
|
|
|
Common Stock, $1 Par Value
|
|
|
|
|
|
|
|
|
Authorized 200,000,000 Shares; Issued and
Outstanding 83,461,308 Shares and
83,402,670 Shares, Respectively
|
|
$
|
83,461
|
|
|
$
|
83,403
|
|
Paid In Capital
|
|
|
569,085
|
|
|
|
543,730
|
|
Earnings Reinvested in the Business
|
|
|
983,776
|
|
|
|
786,013
|
|
|
|
|
|
|
|
|
|
|
Total Common Shareholders Equity Before Items Of
Other Comprehensive Income (Loss)
|
|
|
1,636,322
|
|
|
|
1,413,146
|
|
Accumulated Other Comprehensive Income (Loss)
|
|
|
(6,203
|
)
|
|
|
30,416
|
|
|
|
|
|
|
|
|
|
|
Total Comprehensive Shareholders Equity
|
|
|
1,630,119
|
|
|
|
1,443,562
|
|
Long-Term Debt, Net of Current Portion
|
|
|
799,000
|
|
|
|
1,095,675
|
|
|
|
|
|
|
|
|
|
|
Total Capitalization
|
|
|
2,429,119
|
|
|
|
2,539,237
|
|
|
|
|
|
|
|
|
|
|
Current and Accrued Liabilities
|
|
|
|
|
|
|
|
|
Notes Payable to Banks and Commercial Paper
|
|
|
|
|
|
|
|
|
Current Portion of Long-Term Debt
|
|
|
200,024
|
|
|
|
22,925
|
|
Accounts Payable
|
|
|
109,757
|
|
|
|
133,034
|
|
Amounts Payable to Customers
|
|
|
10,409
|
|
|
|
23,935
|
|
Dividends Payable
|
|
|
25,873
|
|
|
|
25,008
|
|
Interest Payable on Long-Term Debt
|
|
|
18,158
|
|
|
|
18,420
|
|
Customer Advances
|
|
|
22,863
|
|
|
|
29,417
|
|
Other Accruals and Current Liabilities
|
|
|
36,062
|
|
|
|
27,040
|
|
Fair Value of Derivative Financial Instruments
|
|
|
16,200
|
|
|
|
39,983
|
|
|
|
|
|
|
|
|
|
|
|
|
|
439,346
|
|
|
|
319,762
|
|
|
|
|
|
|
|
|
|
|
Deferred Credits
|
|
|
|
|
|
|
|
|
Deferred Income Taxes
|
|
|
575,356
|
|
|
|
544,502
|
|
Taxes Refundable to Customers
|
|
|
14,026
|
|
|
|
10,426
|
|
Unamortized Investment Tax Credit
|
|
|
5,392
|
|
|
|
6,094
|
|
Cost of Removal Regulatory Liability
|
|
|
91,226
|
|
|
|
85,076
|
|
Other Regulatory Liabilities
|
|
|
76,659
|
|
|
|
75,456
|
|
Post-Retirement Liabilities
|
|
|
70,555
|
|
|
|
32,918
|
|
Asset Retirement Obligations
|
|
|
75,939
|
|
|
|
77,392
|
|
Other Deferred Credits
|
|
|
110,794
|
|
|
|
72,885
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,019,947
|
|
|
|
904,749
|
|
|
|
|
|
|
|
|
|
|
Commitments and Contingencies
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Capitalization and Liabilities
|
|
$
|
3,888,412
|
|
|
$
|
3,763,748
|
|
|
|
|
|
|
|
|
|
|
See Notes to Consolidated Financial Statements
63
NATIONAL
FUEL GAS COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended September 30
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(Thousands of dollars)
|
|
|
Operating Activities
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income Available for Common Stock
|
|
$
|
337,455
|
|
|
$
|
138,091
|
|
|
$
|
189,488
|
|
Adjustments to Reconcile Net Income to Net Cash Provided by
Operating Activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Gain on Sale of Discontinued Operations
|
|
|
(159,873
|
)
|
|
|
|
|
|
|
(27,386
|
)
|
Impairment of Oil and Gas Producing Properties
|
|
|
|
|
|
|
104,739
|
|
|
|
|
|
Depreciation, Depletion and Amortization
|
|
|
170,803
|
|
|
|
179,615
|
|
|
|
193,144
|
|
Deferred Income Taxes
|
|
|
52,847
|
|
|
|
(5,230
|
)
|
|
|
40,388
|
|
Income from Unconsolidated Subsidiaries, Net of Cash
Distributions
|
|
|
(3,366
|
)
|
|
|
1,067
|
|
|
|
(1,372
|
)
|
Impairment of Investment in Partnership
|
|
|
|
|
|
|
|
|
|
|
4,158
|
|
Minority Interest in Foreign Subsidiaries
|
|
|
|
|
|
|
|
|
|
|
2,645
|
|
Excess Tax Benefits Associated with Stock-Based Compensation
Awards
|
|
|
(13,689
|
)
|
|
|
(6,515
|
)
|
|
|
|
|
Other
|
|
|
16,399
|
|
|
|
4,829
|
|
|
|
7,390
|
|
Change in:
|
|
|
|
|
|
|
|
|
|
|
|
|
Hedging Collateral Deposits
|
|
|
15,610
|
|
|
|
58,108
|
|
|
|
(69,172
|
)
|
Receivables and Unbilled Utility Revenue
|
|
|
5,669
|
|
|
|
(12,343
|
)
|
|
|
(25,828
|
)
|
Gas Stored Underground and Materials and Supplies
|
|
|
(5,714
|
)
|
|
|
1,679
|
|
|
|
1,934
|
|
Unrecovered Purchased Gas Costs
|
|
|
(1,799
|
)
|
|
|
1,847
|
|
|
|
(7,285
|
)
|
Prepayments and Other Current Assets
|
|
|
18,800
|
|
|
|
(39,572
|
)
|
|
|
(42,409
|
)
|
Accounts Payable
|
|
|
(26,002
|
)
|
|
|
(23,144
|
)
|
|
|
48,089
|
|
Amounts Payable to Customers
|
|
|
(13,526
|
)
|
|
|
22,777
|
|
|
|
(1,996
|
)
|
Customer Advances
|
|
|
(6,554
|
)
|
|
|
4,946
|
|
|
|
3,971
|
|
Other Accruals and Current Liabilities
|
|
|
8,950
|
|
|
|
(17,754
|
)
|
|
|
18,715
|
|
Other Assets
|
|
|
4,109
|
|
|
|
(22,700
|
)
|
|
|
(13,461
|
)
|
Other Liabilities
|
|
|
(5,922
|
)
|
|
|
80,960
|
|
|
|
(3,667
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Cash Provided by Operating Activities
|
|
|
394,197
|
|
|
|
471,400
|
|
|
|
317,346
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investing Activities
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital Expenditures
|
|
|
(276,728
|
)
|
|
|
(294,159
|
)
|
|
|
(219,530
|
)
|
Investment in Partnership
|
|
|
(3,300
|
)
|
|
|
|
|
|
|
|
|
Net Proceeds from Sale of Foreign Subsidiaries
|
|
|
232,092
|
|
|
|
|
|
|
|
111,619
|
|
Cash Held in Escrow
|
|
|
(58,248
|
)
|
|
|
|
|
|
|
|
|
Net Proceeds from Sale of Oil and Gas Producing Properties
|
|
|
5,137
|
|
|
|
13
|
|
|
|
1,349
|
|
Other
|
|
|
(725
|
)
|
|
|
(3,230
|
)
|
|
|
3,238
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Cash Used in Investing Activities
|
|
|
(101,772
|
)
|
|
|
(297,376
|
)
|
|
|
(103,324
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Financing Activities
|
|
|
|
|
|
|
|
|
|
|
|
|
Change in Notes Payable to Banks and Commercial Paper
|
|
|
|
|
|
|
|
|
|
|
(115,359
|
)
|
Excess Tax Benefits Associated with Stock-Based Compensation
Awards
|
|
|
13,689
|
|
|
|
6,515
|
|
|
|
|
|
Shares Repurchased under Repurchase Plan
|
|
|
(48,070
|
)
|
|
|
(85,168
|
)
|
|
|
|
|
Reduction of Long-Term Debt
|
|
|
(119,576
|
)
|
|
|
(9,805
|
)
|
|
|
(13,317
|
)
|
Net Proceeds from Issuance of Common Stock
|
|
|
17,498
|
|
|
|
23,339
|
|
|
|
20,279
|
|
Dividends Paid on Common Stock
|
|
|
(100,632
|
)
|
|
|
(98,266
|
)
|
|
|
(94,159
|
)
|
Dividends Paid to Minority Interest
|
|
|
|
|
|
|
|
|
|
|
(12,676
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Cash Used in Financing Activities
|
|
|
(237,091
|
)
|
|
|
(163,385
|
)
|
|
|
(215,232
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Effect of Exchange Rates on Cash
|
|
|
(139
|
)
|
|
|
1,365
|
|
|
|
1,276
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Increase in Cash and Temporary Cash Investments
|
|
|
55,195
|
|
|
|
12,004
|
|
|
|
66
|
|
Cash and Temporary Cash Investments At Beginning of Year
|
|
|
69,611
|
|
|
|
57,607
|
|
|
|
57,541
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and Temporary Cash Investments At End of Year
|
|
$
|
124,806
|
|
|
$
|
69,611
|
|
|
$
|
57,607
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Supplemental Disclosure of Cash Flow Information
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash Paid For:
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
|
|
$
|
75,987
|
|
|
$
|
78,003
|
|
|
$
|
84,455
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income Taxes
|
|
$
|
97,961
|
|
|
$
|
54,359
|
|
|
$
|
83,542
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See Notes to Consolidated Financial Statements
64
NATIONAL
FUEL GAS COMPANY
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended September 30
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(Thousands of dollars)
|
|
|
Net Income Available for Common Stock
|
|
$
|
337,455
|
|
|
$
|
138,091
|
|
|
$
|
189,488
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Comprehensive Income (Loss), Before Tax:
|
|
|
|
|
|
|
|
|
|
|
|
|
Minimum Pension Liability Adjustment
|
|
|
|
|
|
|
165,914
|
|
|
|
(83,379
|
)
|
Foreign Currency Translation Adjustment
|
|
|
7,874
|
|
|
|
7,408
|
|
|
|
14,286
|
|
Reclassification Adjustment for Realized Foreign Currency
Translation Gain in Net Income
|
|
|
(42,658
|
)
|
|
|
(716
|
)
|
|
|
(37,793
|
)
|
Unrealized Gain on Securities Available for Sale Arising During
the Period
|
|
|
4,747
|
|
|
|
2,573
|
|
|
|
2,891
|
|
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
|
|
|
8,495
|
|
|
|
90,196
|
|
|
|
(206,847
|
)
|
Reclassification Adjustment for Realized Loss on Derivative
Financial Instruments in Net Income
|
|
|
5,106
|
|
|
|
91,743
|
|
|
|
97,689
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Comprehensive Income (Loss), Before Tax
|
|
|
(16,436
|
)
|
|
|
357,118
|
|
|
|
(213,804
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income Tax Expense (Benefit) Related to Minimum Pension
Liability Adjustment
|
|
|
|
|
|
|
58,070
|
|
|
|
(29,183
|
)
|
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
|
|
|
1,724
|
|
|
|
894
|
|
|
|
1,012
|
|
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
|
|
|
3,153
|
|
|
|
34,772
|
|
|
|
(79,059
|
)
|
Reclassification Adjustment for Income Tax Benefit on Realized
Loss on Derivative Financial Instruments In Net Income
|
|
|
2,824
|
|
|
|
35,338
|
|
|
|
36,507
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income Taxes Net
|
|
|
7,701
|
|
|
|
129,074
|
|
|
|
(70,951
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Comprehensive Income (Loss)
|
|
|
(24,137
|
)
|
|
|
228,044
|
|
|
|
(142,853
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive Income
|
|
$
|
313,318
|
|
|
$
|
366,135
|
|
|
$
|
46,635
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See Notes to Consolidated Financial Statements
65
NATIONAL
FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
|
|
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 Company uses proportionate consolidation when
accounting for drilling arrangements related to oil and gas
producing properties accounted for under the full cost method of
accounting.
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 Energy Marketing segment records revenue as
bills are rendered for service supplied on a calendar month
basis.
The Companys Pipeline and Storage segment records revenue
for natural gas transportation and storage services. Revenue
from reservation charges on firm contracted capacity is
recognized through equal monthly charges over the contract
period regardless of the amount of gas that is transported or
stored. Commodity charges on firm contracted capacity and
interruptible contracts are recognized as revenue when physical
deliveries of natural gas are made at the agreed upon delivery
point or when gas is injected or withdrawn from the storage
field. The point of delivery into the pipeline or injection or
withdrawal from storage is the point at which ownership and risk
of loss transfers to the buyer of such transportation and
storage services.
The Companys Timber segment records revenue on lumber and
log sales as products are shipped, which is the point at which
ownership and risk of loss transfers to the buyer of lumber
products or logs.
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
66
NATIONAL
FUEL GAS COMPANY
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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.
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.
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 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 does not recognize any gain or loss on
the sale or other disposition of oil and gas properties unless
the gain or loss would significantly alter the relationship
between capitalized costs and proved reserves of oil and gas
attributable to a cost center.
Capitalized costs include costs related to unproved properties,
which are excluded from amortization until proved reserves are
found or it is determined that the unproved properties are
impaired. All costs related to unproved properties are reviewed
quarterly to determine if impairment has occurred. The amount of
any impairment is transferred to the pool of capitalized costs
being amortized.
67
NATIONAL
FUEL GAS COMPANY
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Capitalized costs are subject to the SEC full cost ceiling test.
The ceiling test, which is performed each quarter, determines a
limit, or ceiling, on a
country-by-country
basis on 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 cash flows, excluding future cash outflows associated
with settling asset retirement obligations that have been
accrued on the balance sheet, 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 tax effects related to the differences between
the book and tax basis of the properties. If capitalized costs,
net of accumulated depreciation, depletion and amortization and
related deferred income taxes, exceed the ceiling at the end of
any quarter, a permanent impairment is required to be charged to
earnings in that quarter. In adjusting estimated future net cash
flows for hedging under the ceiling test at September 30,
2007, 2006, and 2005, estimated future net cash flows were
increased by $2.2 million, increased by $4.7 million,
and decreased by $175.3 million, respectively. 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. These impairment
charges are included in loss from discontinued operations for
2006 due to the sale of SECI during 2007.
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.
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 unproved 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
|
|
|
|
2007
|
|
|
2006
|
|
|
|
(Thousands)
|
|
|
Utility
|
|
$
|
1,539,808
|
|
|
$
|
1,493,991
|
|
Pipeline and Storage
|
|
|
976,316
|
|
|
|
962,831
|
|
Exploration and Production(1)
|
|
|
1,577,745
|
|
|
|
1,899,777
|
|
Energy Marketing
|
|
|
1,199
|
|
|
|
1,123
|
|
Timber
|
|
|
119,237
|
|
|
|
116,281
|
|
All Other and Corporate
|
|
|
32,806
|
|
|
|
33,338
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
4,247,111
|
|
|
$
|
4,507,341
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Fiscal 2006 includes the depreciable plant of SECI discontinued
operations of $469,810. |
68
NATIONAL
FUEL GAS COMPANY
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Average depreciation, depletion and amortization rates are as
follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended September 30
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
Utility
|
|
|
2.8
|
%
|
|
|
2.8
|
%
|
|
|
2.8
|
%
|
Pipeline and Storage
|
|
|
3.5
|
%
|
|
|
4.0
|
%
|
|
|
4.1
|
%
|
Exploration and Production, per Mcfe(1)
|
|
$
|
1.94
|
|
|
$
|
2.00
|
|
|
$
|
1.74
|
|
Energy Marketing
|
|
|
2.8
|
%
|
|
|
4.8
|
%
|
|
|
7.6
|
%
|
Timber
|
|
|
4.0
|
%
|
|
|
5.6
|
%
|
|
|
6.2
|
%
|
All Other and Corporate
|
|
|
4.6
|
%
|
|
|
4.1
|
%
|
|
|
4.3
|
%
|
|
|
|
(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 $1.92, $1.98 and $1.72 per Mcfe of
production in 2007, 2006 and 2005, respectively. Depletion of
oil and gas producing properties in the United States amounted
to $1.97, $1.74 and $1.58 per Mcfe of production in 2007, 2006
and 2005, respectively. Depletion of oil and gas producing
properties in Canada amounted to $1.67, $2.95 and $2.36 per Mcfe
of production in 2007, 2006 and 2005, respectively. |
Goodwill
The Company has recognized goodwill of $5.5 million as of
September 30, 2007 and 2006 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, 2007 and 2006, 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.
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 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. 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. Any ineffectiveness associated with the cash flow hedges
is recorded in the Consolidated Statements of Income. In
December 2006, the Company repaid $22.8 million of
Empires secured debt. The interest costs of this secured
debt were hedged by an interest rate collar. Since the hedged
transaction was settled and there will be no future cash flows
associated with the secured debt, hedge accounting for the
interest rate collar was discontinued and the unrealized gain of
$1.9 million in accumulated other comprehensive income
associated with the interest rate collar was reclassified to the
Consolidated Statement of Income. The Company did not experience
any material ineffectiveness with regard to its cash flow hedges
during 2006.
69
NATIONAL
FUEL GAS COMPANY
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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 2007, 2006 or 2005.
Accumulated
Other Comprehensive Income (Loss)
The components of Accumulated Other Comprehensive Income (Loss)
are as follows:
|
|
|
|
|
|
|
|
|
|
|
Year Ended September 30
|
|
|
|
2007
|
|
|
2006
|
|
|
|
(Thousands)
|
|
|
Funded Position of the Pension and Other Post-Retirement Benefit
Plans Adjustment
|
|
$
|
(12,482
|
)(1)
|
|
$
|
|
|
Cumulative Foreign Currency Translation Adjustment
|
|
|
(83
|
)
|
|
|
34,701
|
|
Net Unrealized Loss on Derivative Financial Instruments
|
|
|
(3,886
|
)
|
|
|
(11,510
|
)
|
Net Unrealized Gain on Securities Available for Sale
|
|
|
10,248
|
|
|
|
7,225
|
|
|
|
|
|
|
|
|
|
|
Accumulated Other Comprehensive Income (Loss)
|
|
$
|
(6,203
|
)
|
|
$
|
30,416
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
In accordance with the transition recognition provisions of
SFAS 158, the adjustment to recognize the funded positions
of the Pension and Other Post-retirement Benefit Plans are shown
as an adjustment to the ending balance of accumulated other
comprehensive income (loss). The adjustment is not shown as
other comprehensive income (loss) in the Consolidated Statements
of Comprehensive Income. |
At September 30, 2007, it is estimated that of the
$3.9 million net unrealized loss on derivative financial
instruments shown in the table above, $2.4 million will be
reclassified into the Consolidated Statement of Income during
2008. The remaining unrealized loss on derivative financial
instruments of $1.5 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.
Gas
Stored Underground Current
In the Utility segment, gas stored underground
current in the amount of $33.0 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 2007, 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
$129.3 million at September 30, 2007. 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.
70
NATIONAL
FUEL GAS COMPANY
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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
|
|
|
|
2007
|
|
|
2006
|
|
|
|
(Thousands)
|
|
|
Materials and Supplies
|
|
$
|
8,925
|
|
|
$
|
13,174
|
|
Other Assets
|
|
|
5,641
|
|
|
|
3,218
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
14,566
|
|
|
$
|
16,392
|
|
|
|
|
|
|
|
|
|
|
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). With the sale of SECI on August 31, 2007,
the Company has eliminated its major foreign operation. While
the Company is in the process of winding up or selling certain
power development projects in Europe, the investment in such
projects is not significant and the Company does not expect to
have any significant foreign currency translation adjustments in
the future.
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.
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.
71
NATIONAL
FUEL GAS COMPANY
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Cash
Held in Escrow
On August 31, 2007, the Company received approximately
$232.1 million of proceeds from the sale of SECI, of which
$58.0 million was placed in escrow pending receipt of a tax
clearance certificate from the Canadian government. The escrow
account is a Canadian dollar denominated account. On a
U.S. dollar basis, the value of this account was
$62.0 million at September 30, 2007.
Other
Current Assets
Other Current Assets consist of prepayments in the amounts of
$14.1 million and $12.0 million at September 30,
2007 and 2006, respectively, prepaid property and other taxes of
$14.1 million and $13.7 million at September 30,
2007 and 2006, respectively, federal income taxes receivable in
the amounts of $8.7 million and $7.5 million at
September 30, 2007 and 2006, respectively, state income
taxes receivable in the amounts of zero and $7.4 million at
September 30, 2007 and 2006, respectively, and fair values
of firm commitments in the amounts of $8.2 million and
$23.1 million at September 30, 2007 and 2006,
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 and stock-settled SARs. The diluted weighted average
shares outstanding shown on the Consolidated Statements of
Income reflects the potential dilution as a result of these
stock options and stock-settled SARs as determined using the
Treasury Stock Method. Stock options and stock-settled SARs that
are antidilutive are excluded from the calculation of diluted
earnings per common share. For 2007, no stock options or
stock-settled SARs were excluded as being antidilutive. For
2006, 119,241 stock options were excluded as being antidilutive.
There were no stock-settled SARs excluded as being antidilutive
for 2006. There were no stock options or stock-settled SARs
excluded as being antidilutive for 2005.
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, stock-settled SARs, restricted
stock, performance units or performance shares. Stock options
and stock-settled SARs under all plans have exercise prices
equal to the average market price of Company common stock on the
date of grant, and generally no stock option or stock-settled
SAR 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.
72
NATIONAL
FUEL GAS COMPANY
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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.
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 and stock-settled SARs. The Company has
chosen to use the modified version of prospective application,
as allowed by SFAS 123R. Using the modified prospective
application, the Company recorded compensation cost for the
portion of awards granted prior to October 1, 2005 for
which the requisite service had not been rendered and recognized
such compensation cost as the requisite service was 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 448,000, 317,000 and 700,000
stock options granted during the years ended September 30,
2007, 2006 and 2005, respectively. The Company granted 50,000
stock-settled SARs during the year ended September 30,
2007. There were no stock-settled SARs granted during the years
ended September 30, 2006 and 2005. The accounting treatment
for such stock-settled SARs is the same under SFAS 123R as
the accounting for stock options under SFAS 123R. The
Company also granted 25,000 and 16,000 restricted share awards
(non-vested stock as defined by SFAS 123R) during the years
ended September 30, 2007 and 2006, respectively. There were
no restricted share awards granted during the year ended
September 30, 2005. Stock-based compensation expense for
the years ended September 30, 2007, 2006 and 2005 was
approximately $3,727,000, $1,705,000, and $517,000,
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,
2007, 2006 and 2005 was approximately $1,488,000, $653,000 and
$206,000, respectively. There were no capitalized stock-based
compensation costs during the years ended September 30,
2007 and 2006.
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,
2007, the amount of compensation expense recognized by the
Company using the non-substantive vesting approach was $280,000
($182,000 net of tax) less than if the nominal vesting
period approach had been used. 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 as
opposed to the nominal vesting period 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. 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 year ended
September 30, 2005:
|
|
|
|
|
|
|
Year Ended
|
|
|
|
September 30,
|
|
|
|
2005
|
|
|
|
(Thousands, except
|
|
|
|
per share amounts)
|
|
|
Net Income, Available for Common Stock, As Reported
|
|
$
|
189,488
|
|
Add: Stock-Based Employee Compensation Expense Included in
Reported Net Income, Net of Tax(1)
|
|
|
336
|
|
Deduct: Total Stock-Based Employee Compensation Expense
Determined Under Fair Value Based Methods for all Awards, Net of
Related Tax Effects
|
|
|
(2,782
|
)
|
|
|
|
|
|
Pro Forma Net Income Available for Common Stock
|
|
$
|
187,042
|
|
|
|
|
|
|
Earnings Per Common Share:
|
|
|
|
|
Basic As Reported
|
|
$
|
2.27
|
|
Basic Pro Forma
|
|
$
|
2.24
|
|
Diluted As Reported
|
|
$
|
2.23
|
|
Diluted Pro Forma
|
|
$
|
2.20
|
|
|
|
|
(1) |
|
Stock-based compensation expense in 2005 represented
compensation expense related to restricted stock awards. The
pre-tax expense was $517,000 for the year ended
September 30, 2005. |
Stock
Options
The total intrinsic value of stock options exercised during the
years ended September 30, 2007, 2006 and 2005 totaled
approximately $38.7 million, $30.9 million, and
$19.8 million, respectively. For 2007, 2006 and 2005, the
amount of cash received by the Company from the exercise of such
stock options was approximately $26.0 million,
$30.1 million, and $24.8 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, 2006, 2005, and 2004, the
Company realized a tax benefit of $3.2 million,
$0.9 million, and $1.1 million, respectively. For
stock options exercised during the period of January 1,
2007 through September 30, 2007, the Company will realize a
tax benefit of approximately $12.0 million in the quarter
ended December 31, 2007. For stock options exercised during
the period of January 1, 2006 through September 30,
2006, the Company realized 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. The weighted average grant date fair
value of options granted in 2007, 2006 and 2005 is $7.27 per
share, $6.68 per share, and $4.59 per share, respectively. For
the years ended September 30, 2007, 2006 and 2005, 327,501,
89,665 and 1,375,105 stock options became fully vested,
respectively. The total fair value of these stock options was
approximately $2.1 million, $0.4 million and
$6.2 million, respectively, for the years ended
September 30, 2007, 2006 and 2005. As of September 30,
2007, unrecognized compensation expense related to stock options
totaled approximately $0.9 million, which will be
recognized over a weighted average period of 10.6 months.
For a summary of transactions during 2007 involving option
shares for all plans, refer to Note E
Capitalization and Short-Term Borrowings.
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
74
NATIONAL
FUEL GAS COMPANY
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
Risk Free Interest Rate
|
|
|
4.46
|
%
|
|
|
5.08
|
%
|
|
|
4.46
|
%
|
Expected Life (Years)
|
|
|
7.0
|
|
|
|
7.0
|
|
|
|
7.0
|
|
Expected Volatility
|
|
|
17.73
|
%
|
|
|
17.71
|
%
|
|
|
17.76
|
%
|
Expected Dividend Yield (Quarterly)
|
|
|
0.76
|
%
|
|
|
0.83
|
%
|
|
|
1.00
|
%
|
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 years
ended September 30, 2007 and 2006, it was assumed that
there would be no forfeitures, based on the vesting term and the
number of grantees.
Stock-settled
SARs
There were no stock-settled SARs exercised during the years
ended September 30, 2007, 2006 and 2005 as none of the
stock-settled SARs granted have vested. The weighted average
grant date fair value of stock-settled SARs granted in 2007 is
$7.81 per share. There were no stock-settled SARs granted during
2006 or 2005. For the years ended September 30, 2007, 2006
and 2005, there were no stock-settled SARs that became fully
vested. As of September 30, 2007, unrecognized compensation
expense related to stock-settled SARs totaled approximately
$0.3 million, which will be recognized over a weighted
average period of 1.4 years. For a summary of transactions
during 2007 involving stock-settled SARs for all plans, refer to
Note E Capitalization and
Short-Term
Borrowings.
The fair value of stock-settled SARs at the date of grant was
estimated using the Black-Scholes-Merton closed form model. The
following weighted average assumptions were used in estimating
the fair value of options at the date of grant:
|
|
|
|
|
|
|
Year Ended
|
|
|
|
September 30,
|
|
|
|
2007
|
|
|
Risk Free Interest Rate
|
|
|
4.53
|
%
|
Expected Life (Years)
|
|
|
7.0
|
|
Expected Volatility
|
|
|
17.55
|
%
|
Expected Dividend Yield (Quarterly)
|
|
|
0.73
|
%
|
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 during the year ended September 30, 2007, it was
assumed that there would be no forfeitures, based on the vesting
term and the number of grantees.
75
NATIONAL
FUEL GAS COMPANY
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Restricted
Share Awards
The weighted average fair value of restricted share awards
granted in 2007 and 2006 is $40.18 per share and $34.94 per
share, respectively. There were no restricted share awards
granted during 2005. As of September 30, 2007, unrecognized
compensation expense related to restricted share awards totaled
approximately $1.0 million, which will be recognized over a
weighted average period of 1.7 years. For a summary of
transactions during 2007 involving restricted share awards,
refer to Note E Capitalization and Short-Term
Borrowings.
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 June 2006, the FASB issued FIN 48, Accounting for
Uncertainty in Income Taxes. FIN 48 clarifies the
accounting for income taxes by prescribing a minimum probability
threshold that a tax position must meet before a financial
statement benefit is recognized. The minimum threshold is
defined in FIN 48 as a tax position that is more likely
than not to be sustained upon examination by the applicable
taxing authority, including resolution of any related appeals or
litigation processes, based on the technical merits of the
position. If a tax benefit meets this threshold, it is measured
and recognized based on an analysis of the cumulative
probability of the tax benefit being ultimately sustained. The
cumulative effect of applying FIN 48 at adoption, if any,
is reported as an adjustment to opening retained earnings for
the year of adoption. FIN 48 is effective for the
first quarter of the Companys 2008 fiscal year and it
is expected that this pronouncement will not have a material
effect on the Companys 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. In accordance with SFAS 158, the Company has
recognized the funded status of its benefit plans and
implemented the disclosure requirements of SFAS 158 at
September 30, 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. Currently, the Company measures its plan assets and
benefit obligations using a June 30th measurement
date. At September 30, 2007, in order to recognize the
funded status of its pension and post-retirement benefit plans
in accordance with SFAS 158, the Company recorded
additional liabilities or reduced assets by a cumulative amount
of $78.7 million ($71.1 million net of deferred tax
benefits recognized for the portion recorded as an increase to
Accumulated Other Comprehensive Loss). Of the $71.1 million
recognized, $61.9 million was recorded as an increase to
Other Regulatory Assets in the Companys Utility and
Pipeline and Storage segments, $12.5 million (net of
deferred tax benefits of $7.6 million) was recorded as an
increase to Accumulated Other Comprehensive Loss, and
$3.3 million was recorded as an increase to Other
Regulatory
76
NATIONAL
FUEL GAS COMPANY
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Liabilities in the Companys Utility segment. The Company
has recorded amounts to Other Regulatory Assets or Other
Regulatory Liabilities in the Utility and Pipeline and Storage
segments in accordance with the provisions of SFAS 71. The
Company, in those segments, has certain regulatory commission
authorizations, which allow the Company to defer as a regulatory
asset or liability the difference between pension and
post-retirement benefit costs as calculated in accordance with
SFAS 87 and SFAS 106 and what is collected in rates.
Refer to Note G Retirement Plan and Other
Post-Retirement Benefits for further disclosures regarding the
impact of SFAS 158 on the Companys consolidated
financial statements.
In February 2007, the FASB issued SFAS 159, The Fair
Value Option for Financial Assets and Financial
Liabilities Including an Amendment of
SFAS 115. SFAS 159 permits entities to choose to
measure many financial instruments and certain other items at
fair value that are not otherwise required to be measured at
fair value under GAAP. A company that elects the fair value
option for an eligible item will be required to recognize in
current earnings any changes in that items fair value in
reporting periods subsequent to the date of adoption.
SFAS 159 is effective as of the Companys first
quarter of fiscal 2009. The Company is currently evaluating the
impact, if any, that the adoption of SFAS 159 will have on
its consolidated financial statements.
|
|
Note B
|
Asset
Retirement Obligations
|
The Company accounts for asset retirement obligations in
accordance with the provisions of 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.
As previously disclosed, the Company follows the full cost
method of accounting for its exploration and production costs.
Upon the adoption of SFAS 143 on October 1, 2002, 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
and capitalized such costs in property, plant and equipment
(i.e. the full cost pool). Prior to the adoption of
SFAS 143, plugging and abandonment costs were accounted for
solely through the Companys units-of-production depletion
calculation. An estimate of such costs was added to the
depletion base, which also included capitalized costs in the
full cost pool and estimated future expenditures to be incurred
in developing proved reserves. With the adoption of
SFAS 143, plugging and abandonment costs are already
included in capitalized costs and the units-of-production
depletion calculation has been modified to exclude from the
depletion base any estimate of future plugging and abandonment
costs that are already recorded in the full cost pool.
The full cost method of accounting provides a limit to the
amount of costs that can be capitalized in the full cost pool.
This limit is referred to as the full cost ceiling. Prior to the
adoption of SFAS 143, in calculating the full cost ceiling,
the Company reduced the future net cash flows from proved oil
and gas reserves by the estimated plugging and abandonment
costs. Such future net cash flows would then be compared to
capitalized costs in the full cost pool, with any excess
capitalized costs being expensed. With the adoption of
SFAS 143, since the full cost pool now includes an amount
associated with plugging and abandoning the wells, the
calculation of the full cost ceiling has been changed so that
future net cash flows from proved oil and gas reserves are no
longer reduced by the estimated plugging and abandonment costs.
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
77
NATIONAL
FUEL GAS COMPANY
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
would have sufficient information to reasonably estimate the
fair value of a conditional asset retirement obligation.
Upon the adoption of FIN 47, the Company recorded 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.
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, 2007 and 2006, the costs of removal
reclassified to other regulatory liabilities amounted to
$91.2 million and $85.1 million, respectively.
A reconciliation of the Companys asset retirement
obligation calculated in accordance with SFAS 143 is shown
below ($000s):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended September 30
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(Thousands)
|
|
|
Balance at Beginning of Year
|
|
$
|
77,392
|
|
|
$
|
41,411
|
|
|
$
|
32,292
|
|
Additions Adoption of FIN 47
|
|
|
|
|
|
|
23,234
|
|
|
|
|
|
Liabilities Incurred and Revisions of Estimates
|
|
|
(932
|
)
|
|
|
11,244
|
|
|
|
8,343
|
|
Liabilities Settled
|
|
|
(6,108
|
)
|
|
|
(1,303
|
)
|
|
|
(1,938
|
)
|
Accretion Expense
|
|
|
5,394
|
|
|
|
2,671
|
|
|
|
2,448
|
|
Exchange Rate Impact
|
|
|
193
|
|
|
|
135
|
|
|
|
266
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at End of Year
|
|
$
|
75,939
|
|
|
$
|
77,392
|
|
|
$
|
41,411
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
October 1, 2005.
78
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
|
|
|
|
2007
|
|
|
2006
|
|
|
|
(Thousands)
|
|
|
Regulatory Assets(1):
|
|
|
|
|
|
|
|
|
Pension and Post-Retirement Benefit Costs(2) (Note G)
|
|
$
|
98,787
|
|
|
$
|
47,368
|
|
Recoverable Future Taxes (Note D)
|
|
|
83,954
|
|
|
|
79,511
|
|
Environmental Site Remediation Costs(2) (Note H)
|
|
|
20,738
|
|
|
|
12,937
|
|
Unrecovered Purchased Gas Costs (See Regulatory Mechanisms in
Note A)
|
|
|
14,769
|
|
|
|
12,970
|
|
Unamortized Debt Expense (Note A)
|
|
|
8,470
|
|
|
|
8,399
|
|
Asset Retirement Obligations(2) (Note B)
|
|
|
8,315
|
|
|
|
9,018
|
|
Recoverable Worker Compensation Expense(2)
|
|
|
4,445
|
|
|
|
3,691
|
|
Other(2)
|
|
|
5,292
|
|
|
|
3,903
|
|
|
|
|
|
|
|
|
|
|
Total Regulatory Assets
|
|
|
244,770
|
|
|
|
177,797
|
|
|
|
|
|
|
|
|
|
|
Regulatory Liabilities:
|
|
|
|
|
|
|
|
|
Cost of Removal Regulatory Liability (Note B)
|
|
|
91,226
|
|
|
|
85,076
|
|
New York Rate Settlements(3)
|
|
|
27,964
|
|
|
|
40,881
|
|
Pension and Post-Retirement Benefit Costs(3) (Note G)
|
|
|
21,676
|
|
|
|
13,063
|
|
Tax Benefit on Medicare Part D Subsidy(3)
|
|
|
19,147
|
|
|
|
13,791
|
|
Taxes Refundable to Customers (Note D)
|
|
|
14,026
|
|
|
|
10,426
|
|
Amounts Payable to Customers (See Regulatory Mechanisms in
Note A)
|
|
|
10,409
|
|
|
|
23,935
|
|
Deferred Insurance Proceeds(3)
|
|
|
7,422
|
|
|
|
7,516
|
|
Other(3)
|
|
|
450
|
|
|
|
205
|
|
|
|
|
|
|
|
|
|
|
Total Regulatory Liabilities
|
|
|
192,320
|
|
|
|
194,893
|
|
|
|
|
|
|
|
|
|
|
Net Regulatory Position
|
|
$
|
52,450
|
|
|
$
|
(17,096
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
(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.
79
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, 2007 and 2006 of $6.7 million and
$19.8 million, respectively. Under the terms of its 2005
rate agreement, Distribution Corporation has been passing back
that regulatory liability to rate payers since 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
agreement, 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, 2007 and 2006
amounted to $7.4 million and $7.6 million,
respectively.
Other The 2005 agreement also established a reserve
to fund area development projects. The balance in the area
development projects reserve at September 30, 2007 and 2006
amounted to $3.6 million and $3.9 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 $10.3 million and
$9.6 million at September 30, 2007 and 2006,
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
ratepayer funds the Companys post-retirement benefit
plans. As such, any tax benefit received under the Act must be
flowed-through to the ratepayer. 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
In 2006, 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 ratepayers funded the premiums on the former insurance
policies. Deferred insurance proceeds amounted to
$7.4 million at September 30, 2007.
Recoverable
Worker Compensation Expense
The Company has established a liability in its Utility segment
in accordance with the provisions of SFAS 112 for future
worker compensation liabilities. Such amounts have been deferred
as a regulatory asset because the Company is allowed to recover
worker compensation expense in rates.
80
NATIONAL
FUEL GAS COMPANY
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The components of federal, state and foreign income taxes
included in the Consolidated Statements of Income are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended September 30
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(Thousands)
|
|
|
Current Income Taxes
|
|
|
|
|
|
|
|
|
|
|
|
|
Federal
|
|
$
|
99,608
|
|
|
$
|
65,593
|
|
|
$
|
45,571
|
|
State
|
|
|
21,700
|
|
|
|
13,511
|
|
|
|
14,413
|
|
Foreign
|
|
|
22
|
|
|
|
2,212
|
|
|
|
4,104
|
|
Deferred Income Taxes
|
|
|
|
|
|
|
|
|
|
|
|
|
Federal
|
|
|
39,340
|
|
|
|
19,111
|
|
|
|
27,412
|
|
State
|
|
|
10,751
|
|
|
|
9,024
|
|
|
|
2,280
|
|
Foreign
|
|
|
2,756
|
|
|
|
(33,365
|
)
|
|
|
10,120
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
174,177
|
|
|
|
76,086
|
|
|
|
103,900
|
|
Deferred Investment Tax Credit
|
|
|
(697
|
)
|
|
|
(697
|
)
|
|
|
(697
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Income Taxes
|
|
$
|
173,480
|
|
|
$
|
75,389
|
|
|
$
|
103,203
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Presented as Follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Income
|
|
$
|
(697
|
)
|
|
$
|
(697
|
)
|
|
$
|
(697
|
)
|
Income Tax Expense Continuing Operations
|
|
|
131,813
|
|
|
|
108,245
|
|
|
|
85,621
|
|
Discontinued Operations
|
|
|
|
|
|
|
|
|
|
|
|
|
Income From Operations
|
|
|
2,792
|
|
|
|
(32,159
|
)
|
|
|
16,667
|
|
Gain on Disposal
|
|
|
39,572
|
|
|
|
|
|
|
|
1,612
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Income Taxes
|
|
$
|
173,480
|
|
|
$
|
75,389
|
|
|
$
|
103,203
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The U.S. and foreign components of income (loss) before
income taxes are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended September 30
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(Thousands)
|
|
|
U.S.
|
|
$
|
496,074
|
|
|
$
|
293,887
|
|
|
$
|
223,113
|
|
Foreign
|
|
|
14,861
|
|
|
|
(80,407
|
)
|
|
|
69,578
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
510,935
|
|
|
$
|
213,480
|
|
|
$
|
292,691
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
81
NATIONAL
FUEL GAS COMPANY
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(Thousands)
|
|
|
Income Tax Expense, Computed at U.S. Federal Statutory Rate of
35%
|
|
$
|
178,827
|
|
|
$
|
74,718
|
|
|
$
|
102,442
|
|
Increase in Taxes Resulting from:
|
|
|
|
|
|
|
|
|
|
|
|
|
State Income Taxes
|
|
|
21,093
|
|
|
|
14,648
|
|
|
|
10,850
|
|
Foreign Tax Differential
|
|
|
(20,980
|
)
|
|
|
(3,718
|
)
|
|
|
(4,845
|
)
|
Reversal of Capital Loss Valuation Allowance
|
|
|
|
|
|
|
(2,877
|
)
|
|
|
|
|
Miscellaneous
|
|
|
(5,460
|
)
|
|
|
(7,382
|
)
|
|
|
(5,244
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Income Taxes
|
|
$
|
173,480
|
|
|
$
|
75,389
|
|
|
$
|
103,203
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The foreign tax differential amount shown above for 2007
includes tax effects relating to the gain on disposition of a
foreign subsidiary. Also, 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 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
|
|
|
|
2007
|
|
|
2006
|
|
|
|
(Thousands)
|
|
|
Deferred Tax Liabilities:
|
|
|
|
|
|
|
|
|
Property, Plant and Equipment
|
|
$
|
612,648
|
|
|
$
|
569,677
|
|
Other
|
|
|
61,616
|
|
|
|
37,865
|
|
|
|
|
|
|
|
|
|
|
Total Deferred Tax Liabilities
|
|
|
674,264
|
|
|
|
607,542
|
|
|
|
|
|
|
|
|
|
|
Deferred Tax Assets:
|
|
|
|
|
|
|
|
|
Other
|
|
|
(107,458
|
)
|
|
|
(95,445
|
)
|
|
|
|
|
|
|
|
|
|
Total Deferred Tax Assets
|
|
|
(107,458
|
)
|
|
|
(95,445
|
)
|
|
|
|
|
|
|
|
|
|
Total Net Deferred Income Taxes
|
|
$
|
566,806
|
|
|
$
|
512,097
|
|
|
|
|
|
|
|
|
|
|
Presented as Follows:
|
|
|
|
|
|
|
|
|
Net Deferred Tax Asset Current
|
|
$
|
(8,550
|
)
|
|
$
|
(23,402
|
)
|
Net Deferred Tax Asset Non-Current
|
|
|
|
|
|
|
(9,003
|
)
|
Net Deferred Tax Liability Non-Current
|
|
|
575,356
|
|
|
|
544,502
|
|
|
|
|
|
|
|
|
|
|
Total Net Deferred Income Taxes
|
|
$
|
566,806
|
|
|
$
|
512,097
|
|
|
|
|
|
|
|
|
|
|
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 $14.0 million and $10.4 million at
September 30, 2007 and 2006, 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
$84.0 million and $79.5 million at September 30,
2007 and 2006, respectively.
82
NATIONAL
FUEL GAS COMPANY
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
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, 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
|
|
|
|
30,416
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income Available for Common Stock
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
337,455
|
|
|
|
|
|
Dividends Declared on Common Stock ($1.22 Per Share)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(101,496
|
)
|
|
|
|
|
Other Comprehensive Loss, Net of Tax
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(24,137
|
)
|
Adjustment to Recognize the Funded Position of the Pension and
Other Post-Retirement Benefit Plans
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(12,482
|
)
|
Share-Based Payment Expense(2)
|
|
|
|
|
|
|
|
|
|
|
3,727
|
|
|
|
|
|
|
|
|
|
Common Stock Issued Under Stock and Benefit Plans(1)
|
|
|
1,367
|
|
|
|
1,367
|
|
|
|
30,193
|
|
|
|
|
|
|
|
|
|
Share Repurchases
|
|
|
(1,309
|
)
|
|
|
(1,309
|
)
|
|
|
(8,565
|
)
|
|
|
(38,196
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at September 30, 2007
|
|
|
83,461
|
|
|
$
|
83,461
|
|
|
$
|
569,085
|
|
|
$
|
983,776
|
(3)
|
|
$
|
(6,203
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Paid in Capital includes tax benefits of $13.7 million,
$6.5 million and $3.7 million for September 30,
2007, 2006 and 2005, respectively, associated with the exercise
of stock options. |
|
(2) |
|
As of October 1, 2005, Paid in Capital includes
compensation costs associated with stock option, stock-settled
SARs and/or 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,
2007, $880.6 million of accumulated earnings was free of
such limitations. |
83
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 2007, the Company issued 2,070,613 original issue shares
of common stock as a result of stock option exercises and 25,000
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 2007, 731,793 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. There were also 6,000 restricted
stock award shares forfeited during 2007.
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 9,146 original
issue shares of common stock to the non-employee directors of
the Company during 2007.
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
2007, the Company repurchased 1,308,328 shares for
$48.1 million under this program, funded with cash provided
by operating activities
and/or
through the use of the Companys lines of credit. Since the
repurchase program was implemented, the Company has repurchased
3,834,878 shares for $133.2 million.
Shareholder
Rights Plan
In 1996, the Companys Board of Directors adopted a
shareholder rights plan (Plan). The Plan has been amended three
times since it was adopted and is now embodied in an Amended and
Restated Rights Agreement effective September 1, 2007,
which is an Exhibit to this Annual Report and
Form 10-K.
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 voting stock and (ii) ten days after
the commencement or announcement by a person or group of an
intention to
84
NATIONAL
FUEL GAS COMPANY
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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 earlier than that date, they are
exchanged or redeemed or the Plan is amended to extend the
expiration 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, stock-settled SARs, restricted
stock, performance units or performance shares. Stock options
and stock-settled SARs 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 or stock-settled SAR is
exercisable less than one year or more than ten years after the
date of each grant.
85
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, 2006
|
|
|
9,016,254
|
|
|
$
|
24.69
|
|
|
|
|
|
|
|
|
|
Granted in 2007
|
|
|
448,000
|
|
|
$
|
39.48
|
|
|
|
|
|
|
|
|
|
Exercised in 2007
|
|
|
(2,070,613
|
)
|
|
$
|
23.65
|
|
|
|
|
|
|
|
|
|
Forfeited in 2007
|
|
|
(33,600
|
)
|
|
$
|
25.39
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at September 30, 2007
|
|
|
7,360,041
|
|
|
$
|
25.89
|
|
|
|
3.96
|
|
|
$
|
154,007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Option shares exercisable at September 30, 2007
|
|
|
6,875,041
|
|
|
$
|
24.99
|
|
|
|
3.62
|
|
|
$
|
150,038
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Option shares available for future grant at September 30,
2007(1)
|
|
|
1,075,397
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Including shares available for stock-settled SARs and restricted
stock grants. |
The following table summarizes information about options
outstanding at September 30, 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Options Outstanding
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
Options Exercisable
|
|
|
|
Number
|
|
|
Average
|
|
|
Weighted
|
|
|
Number
|
|
|
Weighted
|
|
|
|
Outstanding
|
|
|
Remaining
|
|
|
Average
|
|
|
Exercisable
|
|
|
Average
|
|
|
|
at
|
|
|
Contractual
|
|
|
Exercise
|
|
|
at
|
|
|
Exercise
|
|
Range of Exercise Price
|
|
9/30/07
|
|
|
Life
|
|
|
Price
|
|
|
9/30/07
|
|
|
Price
|
|
|
$20.60-$24.72
|
|
|
4,233,174
|
|
|
|
2.8
|
|
|
$
|
22.72
|
|
|
|
4,213,174
|
|
|
$
|
22.73
|
|
$24.73-$28.84
|
|
|
2,361,867
|
|
|
|
4.4
|
|
|
$
|
27.72
|
|
|
|
2,361,867
|
|
|
$
|
27.72
|
|
$28.85-$32.96
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$32.97-$37.08
|
|
|
300,000
|
|
|
|
8.6
|
|
|
$
|
35.11
|
|
|
|
300,000
|
|
|
$
|
35.11
|
|
$37.09-$41.20
|
|
|
465,000
|
|
|
|
9.2
|
|
|
$
|
39.39
|
|
|
|
|
|
|
|
|
|
86
NATIONAL
FUEL GAS COMPANY
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Transactions involving stock-settled SARs 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, 2006
|
|
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
Granted in 2007
|
|
|
50,000
|
|
|
$
|
41.20
|
|
|
|
|
|
|
|
|
|
Exercised in 2007
|
|
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
Forfeited in 2007
|
|
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at September 30, 2007
|
|
|
50,000
|
|
|
$
|
41.20
|
|
|
|
9.45
|
|
|
$
|
281
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock-settled SARs exercisable at September 30, 2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The following table summarizes information about stock-settled
SARs outstanding at September 30, 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock-Settled SARs Outstanding
|
|
|
Stock-Settled SARs
|
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
Exercisable
|
|
|
|
Number
|
|
|
Average
|
|
|
Weighted
|
|
|
Number
|
|
|
Weighted
|
|
|
|
Outstanding
|
|
|
Remaining
|
|
|
Average
|
|
|
Exercisable
|
|
|
Average
|
|
|
|
at
|
|
|
Contractual
|
|
|
Exercise
|
|
|
at
|
|
|
Exercise
|
|
Range of Exercise Price
|
|
9/30/07
|
|
|
Life
|
|
|
Price
|
|
|
9/30/07
|
|
|
Price
|
|
|
$37.09-$41.20
|
|
|
50,000
|
|
|
|
9.5
|
|
|
$
|
41.20
|
|
|
|
|
|
|
|
|
|
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.
Transactions involving restricted 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, 2006
|
|
|
42,328
|
|
|
$
|
28.44
|
|
Granted in 2007
|
|
|
25,000
|
|
|
$
|
40.18
|
|
Vested in 2007
|
|
|
(25,000
|
)
|
|
$
|
24.50
|
|
Forfeited in 2007
|
|
|
(6,000
|
)
|
|
$
|
34.94
|
|
|
|
|
|
|
|
|
|
|
Restricted Share Awards Outstanding at September 30, 2007
|
|
|
36,328
|
|
|
$
|
38.16
|
|
|
|
|
|
|
|
|
|
|
Vesting restrictions for the outstanding shares of non-vested
restricted stock at September 30, 2007 will lapse as
follows: 2008 2,500 shares; 2009
2,500 shares; 2010
28,828 shares; and 2011 2,500 shares.
Redeemable
Preferred Stock
As of September 30, 2007, there were 10,000,000 shares
of $1 par value Preferred Stock authorized but unissued.
87
NATIONAL
FUEL GAS COMPANY
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Long-Term
Debt
The outstanding long-term debt is as follows:
|
|
|
|
|
|
|
|
|
|
|
At September 30
|
|
|
|
2007
|
|
|
2006
|
|
|
|
(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 6.5% due March 2013 to September 2022(2)
|
|
|
250,000
|
|
|
|
346,665
|
|
|
|
|
|
|
|
|
|
|
|
|
|
999,000
|
|
|
|
1,095,665
|
|
|
|
|
|
|
|
|
|
|
Other Notes:
|
|
|
|
|
|
|
|
|
Secured(3)
|
|
|
|
|
|
|
22,766
|
|
Unsecured
|
|
|
24
|
|
|
|
169
|
|
|
|
|
|
|
|
|
|
|
Total Long-Term Debt
|
|
|
999,024
|
|
|
|
1,118,600
|
|
Less Current Portion
|
|
|
200,024
|
|
|
|
22,925
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
799,000
|
|
|
$
|
1,095,675
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
These medium-term notes and notes are unsecured. |
|
(2) |
|
At September 30, 2006, $96,665,000 of the 6.5% unsecured
notes were redeemable at par at any time after
September 15, 2006. On April 30, 2007, the Company
redeemed these notes for $96.3 million, plus accrued
interest. |
|
(3) |
|
On December 8, 2006, the Company repaid these notes for
$22.8 million. As such, the notes were classified as
Current Portion of Long-Term Debt on the Companys
Consolidated Balance Sheet at September 30, 2006. These
notes constituted project financing that was secured
by the various project documentation and natural gas
transportation contracts related to the Empire State Pipeline.
The interest rate on these notes was a variable rate based on
LIBOR. |
As of September 30, 2007, the aggregate principal amounts
of long-term debt maturing during the next five years and
thereafter are as follows: $200.0 million in 2008,
$100.0 million in 2009, zero in 2010, $200.0 million
in 2011, $150.0 million in 2012, and $349.0 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
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
$455.0 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.
At September 30, 2007 and 2006, the Company had no
outstanding short-term notes payable to banks or commercial
paper.
88
NATIONAL
FUEL GAS COMPANY
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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, 2007, the Companys debt to
capitalization ratio (as calculated under the facility) was .38.
The constraints specified in the committed credit facility would
permit an additional $2.02 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, 2007, the Company would have been permitted
to issue up to a maximum of $1.4 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 40%) of the Companys long-term
debt (as of September 30, 2007) 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 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, 2007, 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
|
|
|
|
2007 Carrying
|
|
|
2007 Fair
|
|
|
2006 Carrying
|
|
|
2006 Fair
|
|
|
|
Amount
|
|
|
Value
|
|
|
Amount
|
|
|
Value
|
|
|
|
(Thousands)
|
|
|
Long-Term Debt
|
|
$
|
999,024
|
|
|
$
|
1,024,417
|
|
|
$
|
1,118,600
|
|
|
$
|
1,148,089
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
89
NATIONAL
FUEL GAS COMPANY
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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 $54.7 million
and $62.5 million at September 30, 2007 and 2006,
respectively. The fair value of the equity mutual fund was
$14.7 million and $12.9 million at September 30,
2007 and 2006, respectively. The gross unrealized gain on this
equity mutual fund was $2.2 million and $1.0 million
at September 30, 2007 and 2006, 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
$16.3 million and $12.7 million at September 30,
2007 and 2006, respectively. The gross unrealized gain on this
stock was $13.8 million and $10.3 million at
September 30, 2007 and 2006, 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 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 various national natural gas publications. 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 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, 2007, the Company had natural gas price swap
agreements covering a notional amount of 13.2 Bcf extending
through 2009 at a weighted average fixed rate of $8.20 per Mcf.
Of this amount, 0.5 Bcf is accounted for as fair value
hedges at a weighted average fixed rate of $6.94 per Mcf. The
remaining 12.7 Bcf are accounted for as cash flow hedges at
a weighted average fixed rate of $8.24 per Mcf. At
September 30, 2007, the Company would have received a net
$2.8 million to terminate the price swap agreements. The
Company also had crude oil price swap agreements covering a
notional amount of 1,485,000 bbls extending through 2009 at a
weighted average fixed rate of $57.35 per bbl. At
September 30, 2007, the Company would have had to pay a net
$11.2 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 various national natural gas publications. 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, 2007, the Company
had no cost collars on natural gas covering a notional amount of
1.4 Bcf extending through 2008 with a weighted average
floor price of $8.83 per Mcf and a
90
NATIONAL
FUEL GAS COMPANY
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
weighted average ceiling price of $16.45 per Mcf. At
September 30, 2007, the Company would have received
$1.9 million to terminate the no cost collars.
At September 30, 2007, the Company had long (purchased)
futures contracts covering 8.7 Bcf of gas extending through
2012 at a weighted average contract price of $8.72 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
residential, commercial and industrial customers. The Company
would have had to pay $6.0 million to terminate these
futures contracts at September 30, 2007.
At September 30, 2007, the Company had short (sold) futures
contracts covering 5.9 Bcf of gas extending through 2009 at
a weighted average contract price of $9.67 per Mcf. Of this
amount, 3.9 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 2.0 Bcf is
accounted for as fair value hedges used to hedge against falling
prices on their fixed price gas purchasing commitments and hedge
against decreases in natural gas prices associated with the
eventual sale of gas in storage. The Company would have received
$8.2 million to terminate these futures contracts at
September 30, 2007.
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 many of the parent companies of the respective
counterparties to its derivative financial instruments. At
September 30, 2007, the Company used nine counterparties
for its over the counter derivative financial instruments. At
September 30, 2007, no individual counterparty represented
greater than 32% 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, 2007.
In August 2007, the Exploration and Production segments
investment in Canada was sold. Of the $232.1 million in net
proceeds received, $58.0 million was placed in escrow
(denominated in Canadian dollars) pending receipt of a tax
clearance certificate from the Canadian government. To hedge
against foreign currency exchange risk, the Company entered into
a $58.0 million forward contract to sell Canadian dollars.
At September 30, 2007, due to the increase in the strength
of the Canadian dollar versus the U.S. dollar, the Company
had a $2.7 million derivative liability related to the
collar. The Company records gains or losses associated with this
forward contract directly to the income statement.
|
|
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 73% of the employees of the Company. The Company
provides health care and life insurance benefits for a majority
of its 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
91
NATIONAL
FUEL GAS COMPANY
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
made, subject to limitations contained in the Internal Revenue
Code and regulations. 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, 2007, 2006 and 2005, respectively.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Retirement Plan
|
|
|
Other Post-Retirement Benefits
|
|
|
|
Year Ended September 30
|
|
|
Year Ended September 30
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(Thousands)
|
|
|
Change in Benefit Obligation
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Benefit Obligation at Beginning of Period
|
|
$
|
732,207
|
|
|
$
|
825,204
|
|
|
$
|
693,532
|
|
|
$
|
445,931
|
|
|
$
|
546,273
|
|
|
$
|
422,003
|
|
Service Cost
|
|
|
12,898
|
|
|
|
16,416
|
|
|
|
13,714
|
|
|
|
5,614
|
|
|
|
8,029
|
|
|
|
6,153
|
|
Interest Cost
|
|
|
44,350
|
|
|
|
40,196
|
|
|
|
42,079
|
|
|
|
27,198
|
|
|
|
26,804
|
|
|
|
25,783
|
|
Plan Participants Contributions
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,566
|
|
|
|
1,559
|
|
|
|
1,017
|
|
Retiree Drug Subsidy Receipts
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,325
|
|
|
|
|
|
|
|
|
|
Actuarial (Gain) Loss
|
|
|
(2,986
|
)
|
|
|
(108,112
|
)
|
|
|
115,128
|
|
|
|
(14,450
|
)
|
|
|
(115,052
|
)
|
|
|
110,663
|
|
Benefits Paid
|
|
|
(43,950
|
)
|
|
|
(41,497
|
)
|
|
|
(39,249
|
)
|
|
|
(22,639
|
)
|
|
|
(21,682
|
)
|
|
|
(19,346
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Benefit Obligation at End of Period
|
|
$
|
742,519
|
|
|
$
|
732,207
|
|
|
$
|
825,204
|
|
|
$
|
444,545
|
|
|
$
|
445,931
|
|
|
$
|
546,273
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Change in Plan Assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value of Assets at Beginning of Period
|
|
$
|
664,521
|
|
|
$
|
616,462
|
|
|
$
|
573,366
|
|
|
$
|
325,624
|
|
|
$
|
271,636
|
|
|
$
|
229,485
|
|
Actual Return on Plan Assets
|
|
|
119,662
|
|
|
|
68,649
|
|
|
|
56,201
|
|
|
|
65,552
|
|
|
|
34,785
|
|
|
|
20,577
|
|
Employer Contributions
|
|
|
16,488
|
|
|
|
20,907
|
|
|
|
26,144
|
|
|
|
42,268
|
|
|
|
39,326
|
|
|
|
39,903
|
|
Employer Contributions During Period from Measurement Date to
Fiscal Year End
|
|
|
8,423
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Plan Participants Contributions
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,566
|
|
|
|
1,559
|
|
|
|
1,017
|
|
Benefits Paid
|
|
|
(43,950
|
)
|
|
|
(41,497
|
)
|
|
|
(39,249
|
)
|
|
|
(22,639
|
)
|
|
|
(21,682
|
)
|
|
|
(19,346
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value of Assets at End of Period
|
|
$
|
765,144
|
|
|
$
|
664,521
|
|
|
$
|
616,462
|
|
|
$
|
412,371
|
|
|
$
|
325,624
|
|
|
$
|
271,636
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reconciliation of Funded Status
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Funded Status
|
|
$
|
22,625
|
|
|
$
|
(67,686
|
)
|
|
$
|
(208,742
|
)
|
|
$
|
(32,174
|
)
|
|
$
|
(120,307
|
)
|
|
$
|
(274,637
|
)
|
Unrecognized Net Actuarial Loss
|
|
|
|
|
|
|
107,626
|
|
|
|
257,553
|
|
|
|
|
|
|
|
54,487
|
|
|
|
205,423
|
|
Unrecognized Transition Obligation
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
49,890
|
|
|
|
57,017
|
|
Unrecognized Prior Service Cost
|
|
|
|
|
|
|
7,185
|
|
|
|
8,142
|
|
|
|
|
|
|
|
12
|
|
|
|
17
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Amount Recognized at End of Period
|
|
$
|
22,625
|
|
|
$
|
47,125
|
|
|
$
|
56,953
|
|
|
$
|
(32,174
|
)
|
|
$
|
(15,918
|
)
|
|
$
|
(12,180
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
92
NATIONAL
FUEL GAS COMPANY
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Retirement Plan
|
|
|
Other Post-Retirement Benefits
|
|
|
|
Year Ended September 30
|
|
|
Year Ended September 30
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(Thousands)
|
|
|
Amounts Recognized in the Balance Sheets Consist of:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accrued Benefit Liability
|
|
$
|
|
|
|
$
|
|
|
|
$
|
(117,103
|
)
|
|
$
|
(70,555
|
)
|
|
$
|
(32,918
|
)
|
|
$
|
(26,584
|
)
|
Prepaid Benefit Cost
|
|
|
22,625
|
|
|
|
47,125
|
|
|
|
|
|
|
|
38,381
|
|
|
|
17,000
|
|
|
|
14,404
|
|
Intangible Assets
|
|
|
|
|
|
|
|
|
|
|
8,142
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated Other Comprehensive Loss from Additional Minimum
Pension Liability Adjustment (Pre-Tax)
|
|
|
|
|
|
|
|
|
|
|
165,914
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Amount Recognized at End of Period
|
|
$
|
22,625
|
|
|
$
|
47,125
|
|
|
$
|
56,953
|
|
|
$
|
(32,174
|
)
|
|
$
|
(15,918
|
)
|
|
$
|
(12,180
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted Average Assumptions Used to Determine Benefit
Obligation at September 30
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Discount Rate
|
|
|
6.25
|
%
|
|
|
6.25
|
%
|
|
|
5.00
|
%
|
|
|
6.25
|
%
|
|
|
6.25
|
%
|
|
|
5.00
|
%
|
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
|
|
$
|
12,898
|
|
|
$
|
16,416
|
|
|
$
|
13,714
|
|
|
$
|
5,614
|
|
|
$
|
8,029
|
|
|
$
|
6,153
|
|
Interest Cost
|
|
|
44,350
|
|
|
|
40,196
|
|
|
|
42,079
|
|
|
|
27,198
|
|
|
|
26,804
|
|
|
|
25,783
|
|
Expected Return on Plan Assets
|
|
|
(51,235
|
)
|
|
|
(49,943
|
)
|
|
|
(49,545
|
)
|
|
|
(26,960
|
)
|
|
|
(22,302
|
)
|
|
|
(18,862
|
)
|
Amortization of Prior Service Cost
|
|
|
882
|
|
|
|
957
|
|
|
|
1,029
|
|
|
|
4
|
|
|
|
4
|
|
|
|
4
|
|
Amortization of Transition Amount
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
7,127
|
|
|
|
7,127
|
|
|
|
7,127
|
|
Recognition of Actuarial Loss(1)
|
|
|
13,528
|
|
|
|
23,108
|
|
|
|
10,473
|
|
|
|
8,214
|
|
|
|
23,402
|
|
|
|
12,467
|
|
Net Amortization and Deferral for Regulatory Purposes
|
|
|
1,211
|
|
|
|
(6,409
|
)
|
|
|
1,988
|
|
|
|
16,220
|
|
|
|
(11,084
|
)
|
|
|
(410
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Periodic Benefit Cost
|
|
$
|
21,634
|
|
|
$
|
24,325
|
|
|
$
|
19,738
|
|
|
$
|
37,417
|
|
|
$
|
31,980
|
|
|
$
|
32,262
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Comprehensive (Income) Loss (Pre-Tax) Attributable to
Change In Additional Minimum Liability Recognition
|
|
$
|
|
|
|
$
|
(165,914
|
)
|
|
$
|
83,379
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated Other Comprehensive Loss (Pre-Tax) Attributable to
Adoption of SFAS 158
|
|
$
|
11,256
|
|
|
|
NA
|
|
|
|
NA
|
|
|
$
|
778
|
|
|
|
NA
|
|
|
|
NA
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted Average Assumptions Used to Determine Net Periodic
Benefit Cost 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
|
%
|
|
|
|
(1) |
|
Distribution Corporations New York jurisdiction calculates
the amortization of the actuarial loss on a vintage year basis
over 10 years, as mandated by the NYPSC. All the other
subsidiaries of the Company utilize the corridor approach. |
93
NATIONAL
FUEL GAS COMPANY
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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 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. Under SFAS 158, certain
previously unrecognized actuarial gains and losses and
previously unrecognized prior service costs for both the pension
and other post-retirement benefit plans as well as a previously
unrecognized transition obligation for the other post-retirement
benefit plan are required to be recognized. These amounts were
not required to be recorded on the Companys Consolidated
Balance Sheet before the adoption of SFAS 158, but were
instead amortized over a period of time. In accordance with
SFAS 158, the Company has recognized the funded status of
its benefit plans and implemented the disclosure requirements of
SFAS 158 at September 30, 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. Currently, the Company
measures its plan assets and benefit obligations using a
June 30th measurement date. The incremental effects of
adopting the provisions of SFAS 158 on the Companys
Consolidated Balance Sheet at September 30, 2007 are
presented in the table below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Before
|
|
|
Consolidated
|
|
|
After
|
|
|
|
Application of
|
|
|
SFAS 158
|
|
|
Application of
|
|
|
|
SFAS 158(1)
|
|
|
Impact
|
|
|
SFAS 158
|
|
|
|
(Thousands)
|
|
|
Qualified Retirement Plan
|
|
|
|
|
|
|
|
|
|
|
|
|
Reduction in Prepaid Pension and Post-Retirement Benefit Costs
|
|
$
|
51,612
|
|
|
$
|
(28,987
|
)
|
|
$
|
22,625
|
|
Increase in Other Regulatory Assets Related to SFAS 158
|
|
$
|
|
|
|
$
|
17,731
|
|
|
$
|
17,731
|
|
Reduction in Accumulated Other Comprehensive Income
|
|
$
|
|
|
|
$
|
7,008
|
|
|
$
|
7,008
|
|
Reduction in Deferred Income Taxes (under Deferred Credits)
|
|
$
|
|
|
|
$
|
4,248
|
|
|
$
|
4,248
|
|
94
NATIONAL
FUEL GAS COMPANY
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Before
|
|
|
Consolidated
|
|
|
After
|
|
|
|
Application of
|
|
|
SFAS 158
|
|
|
Application of
|
|
|
|
SFAS 158(1)
|
|
|
Impact
|
|
|
SFAS 158
|
|
|
|
(Thousands)
|
|
|
Other Post-Retirement Benefits
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase in Prepaid Pension and Post-Retirement Benefit Costs
|
|
$
|
26,067
|
|
|
$
|
12,314
|
|
|
$
|
38,381
|
|
Increase in Other Regulatory Assets Related to SFAS 158
|
|
$
|
|
|
|
$
|
38,472
|
|
|
$
|
38,472
|
|
Increase in Other Regulatory Liabilities Related to SFAS 158
|
|
$
|
|
|
|
$
|
(3,247
|
)
|
|
$
|
(3,247
|
)
|
Reduction in Accumulated Other Comprehensive Income
|
|
$
|
|
|
|
$
|
484
|
|
|
$
|
484
|
|
Reduction in Deferred Income Taxes (under Deferred Credits)
|
|
$
|
|
|
|
$
|
294
|
|
|
$
|
294
|
|
Increase in Post-Retirement Liabilities
|
|
$
|
(22,238
|
)
|
|
$
|
(48,317
|
)
|
|
$
|
(70,555
|
)
|
Non-Qualified Benefit Plan
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase in Other Regulatory Assets Related to SFAS 158
|
|
$
|
|
|
|
$
|
5,704
|
|
|
$
|
5,704
|
|
Reduction in Accumulated Other Comprehensive Income
|
|
$
|
|
|
|
$
|
4,990
|
|
|
$
|
4,990
|
|
Reduction in Deferred Income Taxes (under Deferred Credits)
|
|
$
|
|
|
|
$
|
3,027
|
|
|
$
|
3,027
|
|
Increase in Other Deferred Credits
|
|
$
|
(30,115
|
)
|
|
$
|
(13,721
|
)
|
|
$
|
(43,836
|
)
|
Total Consolidated
|
|
|
|
|
|
|
|
|
|
|
|
|
Reduction in Prepaid Pension and Post-Retirement Benefit Costs
|
|
$
|
77,679
|
|
|
$
|
(16,673
|
)
|
|
$
|
61,006
|
|
Increase in Other Regulatory Assets Related to SFAS 158
|
|
$
|
|
|
|
$
|
61,907
|
|
|
$
|
61,907
|
|
Increase in Other Regulatory Liabilities Related to SFAS 158
|
|
$
|
|
|
|
$
|
(3,247
|
)
|
|
$
|
(3,247
|
)
|
Reduction in Accumulated Other Comprehensive Income
|
|
$
|
|
|
|
$
|
12,482
|
|
|
$
|
12,482
|
|
Reduction in Deferred Income Taxes (under Deferred Credits)
|
|
$
|
|
|
|
$
|
7,569
|
|
|
$
|
7,569
|
|
Increase in Post-Retirement Liabilities
|
|
$
|
(22,238
|
)
|
|
$
|
(48,317
|
)
|
|
$
|
(70,555
|
)
|
Increase in Other Deferred Credits
|
|
$
|
(30,115
|
)
|
|
$
|
(13,721
|
)
|
|
$
|
(43,836
|
)
|
|
|
|
(1) |
|
Amounts represent balances before applying the effects of the
adoption of SFAS 158, but after giving effect to any
necessary adjustments as a result of recognizing an additional
minimum pension liability. At September 30, 2007, there was
no additional minimum pension liability adjustment since the
fair value of the plan assets exceeded the accumulated benefit
obligation. |
95
NATIONAL
FUEL GAS COMPANY
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The amounts recognized in accumulated other comprehensive loss,
regulatory assets, and regulatory liabilities in fiscal 2007, as
well as the amounts expected to be recognized in net periodic
benefit cost in fiscal 2008 are presented in the table below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
|
|
|
|
|
|
|
Retirement
|
|
|
Post-Retirement
|
|
|
Non-Qualified
|
|
|
|
Plan
|
|
|
Benefits
|
|
|
Benefit Plan
|
|
|
|
(Thousands)
|
|
|
Amounts Recognized In Accumulated Other Comprehensive Loss,
Regulatory Assets and Regulatory Liabilities(1)
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Actuarial Gain/(Loss)
|
|
$
|
(22,684
|
)
|
|
$
|
6,768
|
|
|
$
|
(13,605
|
)
|
Transition Obligation
|
|
|
|
|
|
|
(42,763
|
)
|
|
|
|
|
Prior Service Cost
|
|
|
(6,303
|
)
|
|
|
(8
|
)
|
|
|
(116
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Amount Recognized
|
|
$
|
(28,987
|
)
|
|
$
|
(36,003
|
)
|
|
$
|
(13,721
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amounts Expected to be Recognized in Net Periodic Benefit
Cost in the Next Fiscal Year(1)
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Actuarial Gain/(Loss)
|
|
$
|
(11,064
|
)
|
|
$
|
(2,927
|
)
|
|
$
|
(1,218
|
)
|
Transition Obligation
|
|
|
|
|
|
|
(7,127
|
)
|
|
|
|
|
Prior Service Cost
|
|
|
(808
|
)
|
|
|
(4
|
)
|
|
|
(106
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Amount Expected to be Recognized
|
|
$
|
(11,872
|
)
|
|
$
|
(10,058
|
)
|
|
$
|
(1,324
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Amounts presented are shown before recognizing deferred taxes. |
In accordance with the provisions of SFAS 87, the Company
recorded an additional minimum pension liability at
September 30, 2005 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 related to the additional minimum pension
liability adjustment at September 30, 2006 and 2005 are
shown in the table above. At September 30, 2007, prior to
recognizing the impact of adopting SFAS 158, there was no
additional minimum pension liability adjustment recorded since
the fair value of the plan assets exceeded the accumulated
benefit obligation. The projected benefit obligation,
accumulated benefit obligation and fair value of assets for the
Retirement Plan were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
Projected Benefit Obligation
|
|
$
|
742,519
|
|
|
$
|
732,207
|
|
|
$
|
825,204
|
|
Accumulated Benefit Obligation
|
|
$
|
672,340
|
|
|
$
|
660,026
|
|
|
$
|
733,565
|
|
Fair Value of Plan Assets
|
|
$
|
765,144
|
|
|
$
|
664,520
|
|
|
$
|
616,462
|
|
In 2007, other actuarial experience decreased the projected
benefit obligation for the Retirement Plan by $3.0 million.
There was no change to the discount rate used to estimate the
projected benefit obligation for the Retirement Plan during
2007. 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 discount rate
change for the Retirement Plan in 2005 caused the projected
benefit obligation to increase by $113.0 million.
96
NATIONAL
FUEL GAS COMPANY
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The Company made cash contributions totaling $24.9 million
to the Retirement Plan during the year ended September 30,
2007. The Company expects that the annual contribution to the
Retirement Plan in 2008 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: $46.7 million in 2008; $47.8 million in
2009; $49.0 million in 2010; $50.1 million in 2011;
$51.3 million in 2012; and $283.3 million in the five
years thereafter.
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 $0.4 million through
September 30, 2007 (with $0.2 million and
$0.1 million of costs occurring in 2007 and 2006,
respectively). Costs associated with the Companys
contributions to the Tax-Deferred Savings Plans were
$4.1 million, $4.1 million, and $4.2 million for
the years ended September 30, 2007, 2006 and 2005,
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 $5.5 million,
$5.4 million and $4.3 million in 2007, 2006 and 2005,
respectively. For 2007, accumulated other comprehensive loss
(pre-tax) of $8.0 million was recognized attributable to
the adoption of SFAS 158. There were no amounts recognized
in other comprehensive income (loss) attributable to the
recognition of an additional minimum liability for 2006 and
2005. The accumulated benefit obligation for this plan was
$28.8 million and $26.5 million at September 30,
2007 and 2006, respectively. The projected benefit obligation
for the plan was $43.8 million and $44.5 million at
September 30, 2007 and 2006, respectively. The actuarial
valuations for this plan were determined based on a discount
rate of 6.25%, 6.25% and 5.0% as of September 30, 2007,
2006 and 2005, respectively; a rate of compensation increase of
10.0% as of September 30, 2007, 2006 and 2005; and an
expected long-term rate of return on plan assets of 8.25% at
September 30, 2007, 2006 and 2005.
There was no change to the discount rate used to estimate the
other post-retirement benefit obligation during 2007. Effective
July 1, 2007, 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 $8.6 million. Other actuarial
experience decreased the other
post-retirement
benefit obligation in 2007 by $23.0 million.
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 introduced a prescription drug benefit under
Medicare (Medicare Part D), as
97
NATIONAL
FUEL GAS COMPANY
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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 estimated gross benefit payments and gross amount of subsidy
receipts are as follows:
|
|
|
|
|
|
|
|
|
|
|
Benefit Payments
|
|
|
Subsidy Receipts
|
|
|
First Year
|
|
$
|
23,990,000
|
|
|
$
|
(1,522,000
|
)
|
Second Year
|
|
$
|
25,973,000
|
|
|
$
|
(1,745,000
|
)
|
Third Year
|
|
$
|
28,007,000
|
|
|
$
|
(1,954,000
|
)
|
Fourth Year
|
|
$
|
29,917,000
|
|
|
$
|
(2,154,000
|
)
|
Fifth Year
|
|
$
|
31,406,000
|
|
|
$
|
(2,401,000
|
)
|
Next Five Years
|
|
$
|
176,333,000
|
|
|
$
|
(15,391,000
|
)
|
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 10.0% 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 9.0% 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%
in 2006 and was assumed to gradually decline to 5.0% by the year
2014. In 2007, the rate of increase for Pre age 65
participants was 8.0% and was assumed to gradually decline to
5.0% by the year 2014. The rate of increase for the Post
age 65 participants was 6.67% in 2007 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 12.5% for 2005, 11.0% for 2006, 10.0%
for 2007, 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 6.0%
for 2005, 5.25% for 2006, and 7.0% for 2007. The annual rate of
increase for the Medicare Part B Reimbursement is expected
to gradually decline to 5.0% by the year 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, 2007
would increase by $55.6 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 2007
by $4.9 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, 2007 would decrease by
$46.6 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 2007 by
$4.0 million.
The Company made cash contributions including payments made
directly to participants totaling $42.3 million to the
Post-Retirement Plan during the year ended September 30,
2007. The Company expects that the annual contribution to the
Post-Retirement Plan in 2008 will be in the range of
$25.0 million to $35.0 million.
98
NATIONAL
FUEL GAS COMPANY
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The Companys Retirement Plan weighted average asset
allocations at September 30, 2007, 2006 and 2005 by asset
category are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Percentage of Plan
|
|
|
|
Target Allocation
|
|
|
Assets at September 30
|
|
Asset Category
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
Equity Securities
|
|
|
60-75
|
%
|
|
|
70
|
%
|
|
|
67
|
%
|
|
|
63
|
%
|
Fixed Income Securities
|
|
|
20-35
|
%
|
|
|
24
|
%
|
|
|
26
|
%
|
|
|
28
|
%
|
Other
|
|
|
0-15
|
%
|
|
|
6
|
%
|
|
|
7
|
%
|
|
|
9
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
|
|
|
100
|
%
|
|
|
100
|
%
|
|
|
100
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The Companys Post-Retirement Plan weighted average asset
allocations at September 30, 2007, 2006 and 2005 by asset
category are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Percentage of Plan
|
|
|
|
Target Allocation
|
|
|
Assets at September 30
|
|
Asset Category
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
Equity Securities
|
|
|
85-100
|
%
|
|
|
95
|
%
|
|
|
95
|
%
|
|
|
92
|
%
|
Fixed Income Securities
|
|
|
0-15
|
%
|
|
|
1
|
%
|
|
|
1
|
%
|
|
|
2
|
%
|
Other
|
|
|
0-15
|
%
|
|
|
4
|
%
|
|
|
4
|
%
|
|
|
6
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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, 2007. 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). The Company also
utilizes a yield curve model to determine the discount rate. The
yield curve is a spot rate yield curve that provides a
zero-coupon interest rate for each year into the future. Each
years anticipated benefit payments are discounted at the
associated spot interest rate back to the measurement date. The
discount rate is then determined based on the spot interest rate
that results in the same present value when applied to the same
anticipated benefit payments.
99
NATIONAL
FUEL GAS COMPANY
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
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. At September 30, 2007, the
Company has estimated its remaining
clean-up
costs related to former manufactured gas plant sites and third
party waste disposal sites will be in the range of
$12.1 million to $15.8 million. The minimum estimated
liability of $12.1 million has been recorded on the
Consolidated Balance Sheet at September 30, 2007. 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 four former manufactured gas plant sites in New York
and Pennsylvania. The Company continues to be responsible for
future ongoing maintenance at one site. At a second site,
remediation is complete and long-term maintenance and monitoring
activities are ongoing. A third site, which allegedly contains,
among other things, manufactured gas plant waste, is in the
investigation stage.
At a fourth former manufactured gas plant site, the Company
received, in 1998 and again in October 1999, notice that the
NYDEC believes the Company is responsible for contamination
discovered at the site located in New York for which the Company
had not been named as a PRP. In February 2007, the NYDEC
identified the Company as a PRP for the site and issued a
proposed remedial action plan. The NYDEC estimated
clean-up
costs under its proposed remedy to be $8.9 million if
implemented. Although the Company commented to the NYDEC that
the proposed remedial action plan contained a number of material
errors, omissions and procedural defects, the NYDEC, in a March
2007 Record of Decision, selected the remedy it had previously
proposed. In July 2007, the Company appealed the NYDECs
Record of Decision to the New York State Supreme Court, Albany
County. The Company believes that a negotiated resolution with
the NYDEC regarding the site remains possible.
|
|
(ii)
|
Third
Party Waste Disposal Sites
|
The Company was identified by the NYDEC or the EPA 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 were alleged to have
contributed to the materials that may have been collected at
such waste disposal sites by the site operators. The remediation
was 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. In September
2007, the reallocation process was concluded with respect to
both of these sites whereby the Company was released from any
future liability related to these sites, and was allocated a
refund of approximately $0.5 million as a result of the
conclusion of the cost reallocation process.
100
NATIONAL
FUEL GAS COMPANY
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
In June 2007, the NYDEC notified the Company, as well as a
number of other companies, of their liability with respect to a
remedial account at a waste disposal site in New York. The
notification identified the Company as one of approximately 400
other companies considered to be PRPs related to this site and
requested that the remedy the NYDEC proposed in a Record of
Decision issued in March 2006 be performed. The estimated
clean-up
costs under the remedy selected by the NYDEC are estimated to be
approximately $13.0 million if implemented. The Company is
in the process of organizing a group with the other PRPs and
negotiating an Order on Consent with the NYDEC to perform the
remedy. The Company has not been able to reasonably estimate the
probability or extent of its share of potential liability at
this site.
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: $766.5 million in
2008, $114.5 million in 2009, $50.8 million in 2010,
$22.1 million in 2011, $8.8 million in 2012, and
$23.3 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: $6.7 million in 2008,
$5.8 million in 2009, $4.4 million in 2010,
$2.9 million in 2011, $2.6 million in 2012, and
$13.1 million thereafter.
The Company has entered into several contractual commitments
associated with the construction of the Empire Connector
project, including the pipeline construction itself and
construction of a compressor station, as well as other
contractual commitments for engineering and consulting services.
The Empire Connector is scheduled to go in service by November
2008. As of September 30, 2007, the future contractual
commitments related to the construction of the Empire Connector
during the next two years are as follows: $118.3 million in
2008 and $0.6 million in 2009.
The Company is involved in other 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. These other litigation and regulatory
matters may include, for example, negligence claims and tax,
regulatory or other governmental audits, inspections,
investigations and 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 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.
|
|
Note I
|
Discontinued
Operations
|
On August 31, 2007, the Company completed the sale of SECI,
Senecas wholly owned subsidiary that operated in Canada,
to NAL Oil & Gas Trust. The Company received
approximately $232.1 million of proceeds from the sale, of
which $58.0 million was placed in escrow pending receipt of
a tax clearance certificate from the Canadian government. The
sale resulted in the recognition of a gain of approximately
$120.3 million, net of tax, during the fourth quarter of
2007. SECI is engaged in the exploration for, and the
development and purchase of,
101
NATIONAL
FUEL GAS COMPANY
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
natural gas and oil reserves in the provinces of Alberta,
Saskatchewan and British Columbia in Canada. The decision to
sell was based on lower than expected returns from the Canadian
oil and gas properties combined with difficulty in finding
significant new reserves. Seneca will continue its exploration
and development activities in the Gulf of Mexico, in California
and in Appalachia. As a result of the decision to sell SECI, the
Company began presenting all SECI operations as discontinued
operations during the fourth quarter of 2007.
The following is selected financial information of the
discontinued operations for SECI:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended September 30
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(Thousands)
|
|
|
Operating Revenues
|
|
$
|
50,495
|
|
|
$
|
71,984
|
|
|
$
|
62,775
|
|
Operating Expenses
|
|
|
33,306
|
|
|
|
151,532
|
|
|
|
40,600
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Income (Loss)
|
|
|
17,189
|
|
|
|
(79,548
|
)
|
|
|
22,175
|
|
Interest Income
|
|
|
1,082
|
|
|
|
866
|
|
|
|
260
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (Loss) before Income Taxes
|
|
|
18,271
|
|
|
|
(78,682
|
)
|
|
|
22,435
|
|
Income Tax Expense (Benefit)
|
|
|
2,792
|
|
|
|
(32,159
|
)
|
|
|
7,357
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (Loss) from Discontinued Operations
|
|
|
15,479
|
|
|
|
(46,523
|
)
|
|
|
15,078
|
|
Gain on Disposal, Net of Taxes of $39,572
|
|
|
120,301
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (Loss) from Discontinued Operations
|
|
$
|
135,780
|
|
|
$
|
(46,523
|
)
|
|
$
|
15,078
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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.
102
NATIONAL
FUEL GAS COMPANY
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The following is selected financial information of the
discontinued operations for U.E.:
|
|
|
|
|
|
|
Year Ended
|
|
|
|
September 30
|
|
|
|
2005
|
|
|
|
(Thousands)
|
|
|
Operating Revenues
|
|
$
|
124,840
|
|
Operating Expenses
|
|
|
103,155
|
|
|
|
|
|
|
Operating Income
|
|
|
21,685
|
|
Other Income
|
|
|
2,048
|
|
Interest Expense
|
|
|
(558
|
)
|
|
|
|
|
|
Income before Income Taxes and Minority Interest
|
|
|
23,175
|
|
Income Tax Expense
|
|
|
10,331
|
|
Minority Interest, Net of Taxes
|
|
|
2,645
|
|
|
|
|
|
|
Income from Discontinued Operations
|
|
|
10,199
|
|
Gain on Disposal, Net of Taxes of $1,612
|
|
|
25,774
|
|
|
|
|
|
|
Income from Discontinued Operations
|
|
$
|
35,973
|
|
|
|
|
|
|
|
|
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 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, and in the Gulf Coast region of
Texas, Louisiana and Alabama. Senecas production is, for
the most part, sold to purchasers located in the vicinity of its
wells. As disclosed in Note I Discontinued
Operations, on August 31, 2007, Seneca completed the sale
of SECI, its wholly owned subsidiary operating in Canada, for a
gain of approximately $120.3 million, net of tax, during
the fourth quarter of 2007. As a result of the sale, SECIs
operations have been reported as discontinued operations and
previous period segment information has been restated to reflect
this change.
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.
103
NATIONAL
FUEL GAS COMPANY
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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.
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. All Czech Republic
operations have been reported as discontinued operations. Any
remaining international activity has been included in corporate
operations.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended September 30, 2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
|
|
$
|
1,106,453
|
|
|
$
|
130,410
|
|
|
$
|
324,037
|
|
|
$
|
413,612
|
|
|
$
|
58,897
|
|
|
$
|
2,033,409
|
|
|
$
|
5,385
|
|
|
$
|
772
|
|
|
$
|
2,039,566
|
|
Intersegment Revenues
|
|
$
|
14,271
|
|
|
$
|
81,556
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
95,827
|
|
|
$
|
8,726
|
|
|
$
|
(104,553
|
)
|
|
$
|
|
|
Interest Income
|
|
$
|
(2,345
|
)
|
|
$
|
357
|
|
|
$
|
9,905
|
|
|
$
|
682
|
|
|
$
|
1,249
|
|
|
$
|
9,848
|
|
|
$
|
16
|
|
|
$
|
(8,314
|
)
|
|
$
|
1,550
|
|
Interest Expense
|
|
$
|
28,190
|
|
|
$
|
9,623
|
|
|
$
|
51,743
|
|
|
$
|
263
|
|
|
$
|
3,265
|
|
|
$
|
93,084
|
|
|
$
|
2,687
|
|
|
$
|
(21,296
|
)
|
|
$
|
74,475
|
|
Depreciation, Depletion and Amortization
|
|
$
|
40,541
|
|
|
$
|
32,985
|
|
|
$
|
78,174
|
|
|
$
|
33
|
|
|
$
|
4,709
|
|
|
$
|
156,442
|
|
|
$
|
785
|
|
|
$
|
692
|
|
|
$
|
157,919
|
|
Income Tax Expense
|
|
$
|
31,642
|
|
|
$
|
35,740
|
|
|
$
|
52,421
|
|
|
$
|
5,654
|
|
|
$
|
2,818
|
|
|
$
|
128,275
|
|
|
$
|
1,647
|
|
|
$
|
1,891
|
|
|
$
|
131,813
|
|
Income from Unconsolidated Subsidiaries
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
4,979
|
|
|
$
|
|
|
|
$
|
4,979
|
|
Segment Profit: Income from Continuing Operations
|
|
$
|
50,886
|
|
|
$
|
56,386
|
|
|
$
|
74,889
|
|
|
$
|
7,663
|
|
|
$
|
3,728
|
|
|
$
|
193,552
|
|
|
$
|
2,564
|
|
|
$
|
5,559
|
|
|
$
|
201,675
|
|
Expenditures for Additions to Long-Lived Assets from Continuing
Operations
|
|
$
|
54,185
|
|
|
$
|
43,226
|
|
|
$
|
146,687
|
|
|
$
|
76
|
|
|
$
|
3,657
|
|
|
$
|
247,831
|
|
|
$
|
87
|
|
|
$
|
(319
|
)
|
|
$
|
247,599
|
|
|
|
|
|
|
At September 30, 2007
|
|
|
|
|
|
(Thousands)
|
Segment Assets
|
|
$
|
1,565,593
|
|
|
$
|
810,957
|
|
|
$
|
1,326,073
|
|
|
$
|
59,802
|
|
|
$
|
165,224
|
|
|
$
|
3,927,649
|
|
|
$
|
66,531
|
|
|
$
|
(105,768
|
)
|
|
$
|
3,888,412
|
|
104
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
|
|
|
$
|
274,896
|
|
|
$
|
497,069
|
|
|
$
|
65,024
|
|
|
$
|
2,235,605
|
|
|
$
|
3,304
|
|
|
$
|
766
|
|
|
$
|
2,239,675
|
|
Intersegment Revenues
|
|
$
|
15,068
|
|
|
$
|
81,431
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
5
|
|
|
$
|
96,504
|
|
|
$
|
9,444
|
|
|
$
|
(105,948
|
)
|
|
$
|
|
|
Interest Income
|
|
$
|
4,889
|
|
|
$
|
454
|
|
|
$
|
7,816
|
|
|
$
|
445
|
|
|
$
|
747
|
|
|
$
|
14,351
|
|
|
$
|
22
|
|
|
$
|
(4,964
|
)
|
|
$
|
9,409
|
|
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
|
|
|
$
|
67,122
|
|
|
$
|
53
|
|
|
$
|
6,495
|
|
|
$
|
150,718
|
|
|
$
|
789
|
|
|
$
|
492
|
|
|
$
|
151,999
|
|
Income Tax Expense
|
|
$
|
35,699
|
|
|
$
|
33,896
|
|
|
$
|
29,351
|
|
|
$
|
3,748
|
|
|
$
|
3,277
|
|
|
$
|
105,971
|
|
|
$
|
969
|
|
|
$
|
1,305
|
|
|
$
|
108,245
|
|
Income from Unconsolidated Subsidiaries
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
3,583
|
|
|
$
|
|
|
|
$
|
3,583
|
|
Segment Profit (Loss): Income (Loss) from Continuing Operations
|
|
$
|
49,815
|
|
|
$
|
55,633
|
|
|
$
|
67,494
|
|
|
$
|
5,798
|
|
|
$
|
5,704
|
|
|
$
|
184,444
|
|
|
$
|
359
|
|
|
$
|
(189
|
)
|
|
$
|
184,614
|
|
Expenditures for Additions to Long-Lived Assets from Continuing
Operations
|
|
$
|
54,414
|
|
|
$
|
26,023
|
|
|
$
|
166,535
|
|
|
$
|
16
|
|
|
$
|
2,323
|
|
|
$
|
249,311
|
|
|
$
|
85
|
|
|
$
|
2,995
|
|
|
$
|
252,391
|
|
|
|
|
|
|
At September 30, 2006
|
|
|
|
|
|
(Thousands)
|
Segment Assets
|
|
$
|
1,498,442
|
|
|
$
|
767,889
|
|
|
$
|
1,209,969
|
(1)
|
|
$
|
81,374
|
|
|
$
|
159,421
|
|
|
$
|
3,717,095
|
|
|
$
|
64,287
|
|
|
$
|
(17,634
|
)
|
|
$
|
3,763,748
|
|
|
|
|
(1) |
|
Amount includes $134,930 of assets of SECI, which has been
classified as discontinued operations as of September 30,
2007. (See Note I Discontinued Operations). |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
|
|
|
$
|
230,650
|
|
|
$
|
329,714
|
|
|
$
|
61,285
|
|
|
$
|
1,856,026
|
|
|
$
|
4,748
|
|
|
$
|
|
|
|
$
|
1,860,774
|
|
Intersegment Revenues
|
|
$
|
15,495
|
|
|
$
|
83,054
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
1
|
|
|
$
|
98,550
|
|
|
$
|
8,606
|
|
|
$
|
(107,156
|
)
|
|
$
|
|
|
Interest Income
|
|
$
|
4,111
|
|
|
$
|
76
|
|
|
$
|
4,401
|
|
|
$
|
783
|
|
|
$
|
438
|
|
|
$
|
9,809
|
|
|
$
|
19
|
|
|
$
|
(3,592
|
)
|
|
$
|
6,236
|
|
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
|
|
|
$
|
67,647
|
|
|
$
|
41
|
|
|
$
|
6,601
|
|
|
$
|
152,498
|
|
|
$
|
3,537
|
|
|
$
|
467
|
|
|
$
|
156,502
|
|
Income Tax Expense (Benefit)
|
|
$
|
23,102
|
|
|
$
|
39,068
|
|
|
$
|
20,996
|
|
|
$
|
3,210
|
|
|
$
|
2,271
|
|
|
$
|
88,647
|
|
|
$
|
(1,425
|
)
|
|
$
|
(1,601
|
)
|
|
$
|
85,621
|
|
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
|
|
|
$
|
35,581
|
|
|
$
|
5,077
|
|
|
$
|
5,032
|
|
|
$
|
145,341
|
|
|
$
|
(2,616
|
)
|
|
$
|
(4,288
|
)
|
|
$
|
138,437
|
|
Expenditures for Additions to Long-Lived Assets from Continuing
Operations
|
|
$
|
50,071
|
|
|
$
|
21,099
|
|
|
$
|
83,972
|
|
|
$
|
58
|
|
|
$
|
18,894
|
|
|
$
|
174,094
|
|
|
$
|
463
|
|
|
$
|
618
|
|
|
$
|
175,175
|
|
|
|
|
|
|
At September 30, 2005
|
|
|
|
|
|
(Thousands)
|
Segment Assets
|
|
$
|
1,423,597
|
|
|
$
|
782,546
|
|
|
$
|
1,213,525
|
(2)
|
|
$
|
92,470
|
|
|
$
|
162,052
|
|
|
$
|
3,674,190
|
|
|
$
|
73,354
|
|
|
$
|
2,209
|
|
|
$
|
3,749,753
|
|
|
|
|
(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. |
105
NATIONAL
FUEL GAS COMPANY
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
(2) |
|
Amount includes $204,892 of assets of SECI, which has been
classified as discontinued operations as of September 30,
2007. (See Note I Discontinued Operations). |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For The Year Ended September 30
|
|
Geographic Information
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(Thousands)
|
|
|
Revenues from External Customers(1):
|
|
|
|
|
|
|
|
|
|
|
|
|
United States
|
|
$
|
2,039,566
|
|
|
$
|
2,239,675
|
|
|
$
|
1,860,774
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
At September 30
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(Thousands)
|
|
|
Long-Lived Assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
United States
|
|
$
|
3,334,274
|
|
|
$
|
3,181,769
|
|
|
$
|
2,978,680
|
|
Assets of Discontinued Operations
|
|
|
|
|
|
|
97,234
|
|
|
|
171,196
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
3,334,274
|
|
|
$
|
3,279,003
|
|
|
$
|
3,149,876
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Revenue is based upon the country in which the sale originates.
This table excludes revenues from Canadian discontinued
operations of $50,495, $71,984 and $62,775 for
September 30, 2007, 2006 and 2005, respectively. |
|
|
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.
During 2007, Horizon Power made capital contributions of
$3.3 million to Seneca Energy. Seneca Energy is in the
process of expanding its generating capacity from 11.2 megawatts
to 17.6 megawatts.
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, 2007 and 2006 is as follows:
|
|
|
|
|
|
|
|
|
|
|
At September 30
|
|
|
|
2007
|
|
|
2006
|
|
|
|
(Thousands)
|
|
|
ESNE
|
|
$
|
4,652
|
|
|
$
|
4,486
|
|
Seneca Energy
|
|
|
12,033
|
|
|
|
5,366
|
|
Model City
|
|
|
1,571
|
|
|
|
1,738
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
18,256
|
|
|
$
|
11,590
|
|
|
|
|
|
|
|
|
|
|
|
|
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
106
NATIONAL
FUEL GAS COMPANY
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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 30,
|
|
|
|
At September 30, 2007
|
|
|
2006
|
|
|
|
Gross Carrying
|
|
|
Accumulated
|
|
|
Net Carrying
|
|
|
Net Carrying
|
|
|
|
Amount
|
|
|
Amortization
|
|
|
Amount
|
|
|
Amount
|
|
|
Intangible Assets Subject to Amortization:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-Term Transportation Contracts
|
|
$
|
8,580
|
|
|
$
|
(4,989
|
)
|
|
$
|
3,591
|
|
|
$
|
4,660
|
|
Long-Term Gas Purchase Contracts
|
|
|
31,864
|
|
|
|
(6,619
|
)
|
|
|
25,245
|
|
|
|
26,838
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
40,444
|
|
|
$
|
(11,608
|
)
|
|
$
|
28,836
|
|
|
$
|
31,498
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Aggregate Amortization Expense:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Year Ended September 30, 2007
|
|
$
|
2,662
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Year Ended September 30, 2006
|
|
$
|
2,662
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Year Ended September 30, 2005
|
|
$
|
2,662
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The gross carrying amount of intangible assets subject to
amortization at September 30, 2007 remained unchanged from
September 30, 2006. 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 in 2008, $0.5 million in 2009, and
$0.4 million in 2010, 2011 and 2012. Amortization expense
for the long-term gas purchase contracts is estimated to be
$1.6 million annually for 2008, 2009, 2010, 2011 and 2012.
|
|
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.
107
NATIONAL
FUEL GAS COMPANY
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
|
|
|
Income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
|
|
|
(Loss)
|
|
|
Available
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
from
|
|
|
from
|
|
|
for
|
|
|
Earnings from
|
|
|
|
|
|
|
|
Quarter
|
|
Operating
|
|
|
Operating
|
|
|
Continuing
|
|
|
Discontinued
|
|
|
Common
|
|
|
Continuing Operations per Common Share
|
|
|
Earnings per Common Share
|
|
Ended
|
|
Revenues
|
|
|
Income
|
|
|
Operations
|
|
|
Operations
|
|
|
Stock
|
|
|
Basic
|
|
|
Diluted
|
|
|
Basic
|
|
|
Diluted
|
|
|
|
(Thousands, except per common share amounts)
|
|
|
2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
9/30/2007
|
|
$
|
302,030
|
|
|
$
|
73,504
|
|
|
$
|
34,295
|
|
|
$
|
123,395
|
(1)
|
|
$
|
157,690
|
(1)
|
|
$
|
0.41
|
|
|
$
|
0.40
|
|
|
$
|
1.89
|
|
|
$
|
1.84
|
|
6/30/2007
|
|
$
|
448,779
|
|
|
$
|
83,933
|
|
|
$
|
41,212
|
(2)
|
|
$
|
5,586
|
|
|
$
|
46,798
|
(2)
|
|
$
|
0.49
|
|
|
$
|
0.48
|
|
|
$
|
0.56
|
|
|
$
|
0.55
|
|
3/31/2007
|
|
$
|
798,100
|
|
|
$
|
142,404
|
|
|
$
|
75,480
|
(3)
|
|
$
|
2,967
|
|
|
$
|
78,447
|
(3)
|
|
$
|
0.91
|
|
|
$
|
0.89
|
|
|
$
|
0.95
|
|
|
$
|
0.92
|
|
12/31/2006
|
|
$
|
490,657
|
|
|
$
|
96,657
|
|
|
$
|
50,688
|
(4)
|
|
$
|
3,832
|
|
|
$
|
54,520
|
(4)
|
|
$
|
0.61
|
|
|
$
|
0.60
|
|
|
$
|
0.66
|
|
|
$
|
0.64
|
|
2006
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
9/30/2006
|
|
$
|
280,506
|
|
|
$
|
56,865
|
|
|
$
|
28,585
|
|
|
$
|
(26,617
|
)(5)
|
|
$
|
1,968
|
(5)
|
|
$
|
0.34
|
|
|
$
|
0.33
|
|
|
$
|
0.02
|
|
|
$
|
0.02
|
|
6/30/2006
|
|
$
|
397,206
|
|
|
$
|
67,122
|
|
|
$
|
37,618
|
(7)
|
|
$
|
(37,507
|
)(6)
|
|
$
|
111
|
(6)(7)
|
|
$
|
0.45
|
|
|
$
|
0.44
|
|
|
$
|
|
|
|
$
|
|
|
3/31/2006
|
|
$
|
874,700
|
|
|
$
|
133,745
|
|
|
$
|
69,650
|
|
|
$
|
8,944
|
(8)
|
|
$
|
78,594
|
(8)
|
|
$
|
0.83
|
|
|
$
|
0.81
|
|
|
$
|
0.93
|
|
|
$
|
0.91
|
|
12/31/2005
|
|
$
|
687,263
|
|
|
$
|
97,891
|
|
|
$
|
48,761
|
(9)
|
|
$
|
8,657
|
|
|
$
|
57,418
|
(9)
|
|
$
|
0.58
|
|
|
$
|
0.57
|
|
|
$
|
0.68
|
|
|
$
|
0.67
|
|
|
|
|
(1) |
|
Includes a $120.3 million gain on the sale of SECI. |
|
(2) |
|
Includes $4.8 million of income associated with the
reversal of reserve for preliminary project costs associated
with the Empire Connector project. |
|
(3) |
|
Includes a $2.3 million of income associated with the
reversal of a purchased gas expense accrual related to the
resolution of a contingency. |
|
(4) |
|
Includes a $1.9 million positive earnings impact associated
with the discontinuance of hedge accounting on an interest rate
collar. |
|
(5) |
|
Includes expense of $29.1 million related to the impairment
of oil and gas producing properties. |
|
(6) |
|
Includes expense of $39.5 million related to the impairment
of oil and gas producing properties. |
|
(7) |
|
Includes income of $6.1 million related to income tax
adjustments. |
|
(8) |
|
Includes income of $5.1 million related to income tax
adjustments. |
|
(9) |
|
Includes income of $2.6 million related to a regulatory
adjustment. |
|
|
Note N
|
Market
for Common Stock and Related Shareholder Matters
(unaudited)
|
At September 30, 2007, there were 16,989 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
108
NATIONAL
FUEL GAS COMPANY
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
ranges (based on
intra-day
prices) and quarterly dividends declared for the fiscal years
ended September 30, 2007 and 2006, are shown below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Price Range
|
|
|
|
|
Quarter Ended
|
|
High
|
|
|
Low
|
|
|
Dividends Declared
|
|
|
2007
|
|
|
|
|
|
|
|
|
|
|
|
|
9/30/2007
|
|
$
|
47.00
|
|
|
$
|
40.95
|
|
|
$
|
.31
|
|
6/30/2007
|
|
$
|
47.87
|
|
|
$
|
42.75
|
|
|
$
|
.31
|
|
3/31/2007
|
|
$
|
43.79
|
|
|
$
|
36.94
|
|
|
$
|
.30
|
|
12/31/2006
|
|
$
|
40.21
|
|
|
$
|
35.02
|
|
|
$
|
.30
|
|
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
|
|
Note O
Supplementary Information for Oil and Gas Producing Activities
(unaudited)
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
|
|
|
|
2007
|
|
|
2006
|
|
|
|
(Thousands)
|
|
|
Proved Properties(1)
|
|
$
|
1,583,956
|
|
|
$
|
1,884,049
|
|
Unproved Properties
|
|
|
20,005
|
|
|
|
41,930
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,603,961
|
|
|
|
1,925,979
|
|
Less Accumulated Depreciation, Depletion and
Amortization
|
|
|
627,073
|
|
|
|
929,921
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
976,888
|
|
|
$
|
996,058
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Includes asset retirement costs of $40.9 million and
$42.2 million at September 30, 2007 and 2006,
respectively. |
Costs related to unproved properties are excluded from
amortization until proved reserves are found or it is determined
that the unproved properties are impaired. All costs related to
unproved properties are reviewed quarterly to determine if
impairment has occurred. The amount of any impairment is
transferred to the pool of capitalized costs being amortized.
Following is a summary of costs excluded from amortization at
September 30, 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
as of
|
|
|
|
|
|
|
|
|
|
|
September 30,
|
|
Year Costs Incurred
|
|
|
2007
|
|
2007
|
|
2006
|
|
2005
|
|
Prior
|
|
|
(Thousands)
|
|
Acquisition Costs
|
|
$
|
20,005
|
|
|
$
|
5,957
|
|
|
$
|
12,485
|
|
|
$
|
1,099
|
|
|
$
|
464
|
|
109
NATIONAL
FUEL GAS COMPANY
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Costs
Incurred in Oil and Gas Property Acquisition, Exploration and
Development Activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended September 30
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(Thousands)
|
|
|
United States
|
|
|
|
|
|
|
|
|
|
|
|
|
Property Acquisition Costs:
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved
|
|
$
|
2,621
|
|
|
$
|
5,339
|
|
|
$
|
287
|
|
Unproved
|
|
|
3,210
|
|
|
|
8,844
|
|
|
|
1,215
|
|
Exploration Costs
|
|
|
26,891
|
|
|
|
64,087
|
|
|
|
32,456
|
|
Development Costs
|
|
|
113,206
|
|
|
|
87,738
|
|
|
|
49,016
|
|
Asset Retirement Costs
|
|
|
2,139
|
|
|
|
10,965
|
|
|
|
8,051
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
148,067
|
|
|
|
176,973
|
|
|
|
91,025
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canada Discontinued Operations
|
|
|
|
|
|
|
|
|
|
|
|
|
Property Acquisition Costs:
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved
|
|
|
(1,404
|
)
|
|
|
(427
|
)
|
|
|
(1,551
|
)
|
Unproved
|
|
|
(1,142
|
)
|
|
|
6,492
|
|
|
|
4,668
|
|
Exploration Costs
|
|
|
20,134
|
|
|
|
20,778
|
|
|
|
22,943
|
|
Development Costs
|
|
|
11,414
|
|
|
|
14,385
|
|
|
|
12,198
|
|
Asset Retirement Costs
|
|
|
167
|
|
|
|
279
|
|
|
|
292
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
29,169
|
|
|
|
41,507
|
|
|
|
38,550
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
|
|
Property Acquisition Costs:
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved
|
|
|
1,217
|
|
|
|
4,912
|
|
|
|
(1,264
|
)
|
Unproved
|
|
|
2,068
|
|
|
|
15,336
|
|
|
|
5,883
|
|
Exploration Costs
|
|
|
47,025
|
|
|
|
84,865
|
|
|
|
55,399
|
|
Development Costs
|
|
|
124,620
|
|
|
|
102,123
|
|
|
|
61,214
|
|
Asset Retirement Costs
|
|
|
2,306
|
|
|
|
11,244
|
|
|
|
8,343
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
177,236
|
|
|
$
|
218,480
|
|
|
$
|
129,575
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the years ended September 30, 2007, 2006 and 2005, the
Company spent $30.3 million, $55.6 million and
$19.2 million, respectively, developing proved undeveloped
reserves.
110
NATIONAL
FUEL GAS COMPANY
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Results
of Operations for Producing Activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended September 30
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(Thousands, except per Mcfe amounts)
|
|
|
United States
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas (includes revenues from sales to affiliates of $325,
$106 and $77, respectively)
|
|
$
|
135,399
|
|
|
$
|
152,451
|
|
|
$
|
151,004
|
|
Oil, Condensate and Other Liquids
|
|
|
189,539
|
|
|
|
195,050
|
|
|
|
160,145
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Operating Revenues(1)
|
|
|
324,938
|
|
|
|
347,501
|
|
|
|
311,149
|
|
Production/Lifting Costs
|
|
|
48,410
|
|
|
|
41,354
|
|
|
|
38,442
|
|
Accretion Expense
|
|
|
3,704
|
|
|
|
2,412
|
|
|
|
2,220
|
|
Depreciation, Depletion and Amortization ($1.97, $1.74 and $1.58
per Mcfe of production)
|
|
|
77,452
|
|
|
|
66,488
|
|
|
|
67,097
|
|
Income Tax Expense
|
|
|
78,928
|
|
|
|
88,104
|
|
|
|
74,110
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Results of Operations for Producing Activities (excluding
corporate overheads and interest charges)
|
|
|
116,444
|
|
|
|
149,143
|
|
|
|
129,280
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canada Discontinued Operations
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas
|
|
|
39,114
|
|
|
|
54,819
|
|
|
|
49,275
|
|
Oil, Condensate and Other Liquids
|
|
|
10,313
|
|
|
|
13,985
|
|
|
|
12,875
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Operating Revenues(1)
|
|
|
49,427
|
|
|
|
68,804
|
|
|
|
62,150
|
|
Production/Lifting Costs
|
|
|
14,846
|
|
|
|
14,628
|
|
|
|
12,683
|
|
Accretion Expense
|
|
|
249
|
|
|
|
258
|
|
|
|
228
|
|
Depreciation, Depletion and Amortization ($1.67, $2.95 and $2.36
per Mcfe of production)
|
|
|
12,787
|
|
|
|
27,439
|
|
|
|
23,108
|
|
Impairment of Oil and Gas Producing Properties(2)
|
|
|
|
|
|
|
104,739
|
|
|
|
|
|
Income Tax Expense (Benefit)
|
|
|
3,703
|
|
|
|
(31,987
|
)
|
|
|
8,577
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Results of Operations for Producing Activities (excluding
corporate overheads and interest charges)
|
|
|
17,842
|
|
|
|
(46,273
|
)
|
|
|
17,554
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
111
NATIONAL
FUEL GAS COMPANY
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended September 30
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(Thousands, except per Mcfe amounts)
|
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas (includes revenues from sales to affiliates of $325,
$106 and $77, respectively)
|
|
|
174,513
|
|
|
|
207,270
|
|
|
|
200,279
|
|
Oil, Condensate and Other Liquids
|
|
|
199,852
|
|
|
|
209,035
|
|
|
|
173,020
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Operating Revenues(1)
|
|
|
374,365
|
|
|
|
416,305
|
|
|
|
373,299
|
|
Production/Lifting Costs
|
|
|
63,256
|
|
|
|
55,982
|
|
|
|
51,125
|
|
Accretion Expense
|
|
|
3,953
|
|
|
|
2,670
|
|
|
|
2,448
|
|
Depreciation, Depletion and Amortization ($1.92, $1.98 and $1.72
per Mcfe of production)
|
|
|
90,239
|
|
|
|
93,927
|
|
|
|
90,205
|
|
Impairment of Oil and Gas Producing Properties(2)
|
|
|
|
|
|
|
104,739
|
|
|
|
|
|
Income Tax Expense
|
|
|
82,631
|
|
|
|
56,117
|
|
|
|
82,687
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Results of Operations for Producing Activities (excluding
corporate overheads and interest charges)
|
|
$
|
134,286
|
|
|
$
|
102,870
|
|
|
$
|
146,834
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(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. |
112
NATIONAL
FUEL GAS COMPANY
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Reserve
Quantity Information
The Companys proved oil and gas reserves are located in
the United States. 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
|
|
|
|
|
|
|
|
|
Canada
|
|
|
|
|
|
|
|
|
|
Coast
|
|
|
Coast
|
|
|
Appalachian
|
|
|
Total
|
|
|
(Discontinued
|
|
|
Total
|
|
|
|
|
|
|
Region
|
|
|
Region
|
|
|
Region
|
|
|
U.S.
|
|
|
Operations)
|
|
|
Company
|
|
|
Proved Developed and Undeveloped Reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
|
|
Extensions and Discoveries
|
|
|
|
|
|
|
3,577
|
|
|
|
|
|
|
|
29,676
|
|
|
|
33,253
|
|
|
|
1,333
|
|
|
|
34,586
|
|
Revisions of Previous Estimates
|
|
|
|
|
|
|
(9,851
|
)
|
|
|
1,238
|
|
|
|
1,618
|
|
|
|
(6,995
|
)
|
|
|
11,634
|
|
|
|
4,639
|
|
Production
|
|
|
|
|
|
|
(10,356
|
)
|
|
|
(3,929
|
)
|
|
|
(5,555
|
)
|
|
|
(19,840
|
)
|
|
|
(6,426
|
)
|
|
|
(26,266
|
)
|
Sales of Minerals in Place
|
|
|
|
|
|
|
(36
|
)
|
|
|
|
|
|
|
(34
|
)
|
|
|
(70
|
)
|
|
|
(40,075
|
)
|
|
|
(40,145
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
September 30, 2007
|
|
|
|
|
|
|
25,136
|
|
|
|
73,175
|
|
|
|
107,078
|
|
|
|
205,389
|
|
|
|
|
|
|
|
205,389
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved Developed Reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
|
|
September 30, 2007
|
|
|
|
|
|
|
25,136
|
|
|
|
66,017
|
|
|
|
96,674
|
|
|
|
187,827
|
|
|
|
|
|
|
|
187,827
|
|
113
NATIONAL
FUEL GAS COMPANY
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil Mbbl
|
|
|
|
U.S.
|
|
|
|
|
|
|
|
|
|
|
|
|
West
|
|
|
|
|
|
|
|
|
Canada
|
|
|
|
|
|
|
Gulf Coast
|
|
|
Coast
|
|
|
Appalachian
|
|
|
Total
|
|
|
(Discontinued
|
|
|
Total
|
|
|
|
Region
|
|
|
Region
|
|
|
Region
|
|
|
U.S.
|
|
|
Operations)
|
|
|
Company
|
|
|
Proved Developed and Undeveloped Reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
|
|
Extensions and Discoveries
|
|
|
63
|
|
|
|
|
|
|
|
281
|
|
|
|
344
|
|
|
|
108
|
|
|
|
452
|
|
Revisions of Previous Estimates
|
|
|
851
|
|
|
|
(6,822
|
)
|
|
|
84
|
|
|
|
(5,887
|
)
|
|
|
(76
|
)
|
|
|
(5,963
|
)
|
Production
|
|
|
(717
|
)
|
|
|
(2,403
|
)
|
|
|
(124
|
)
|
|
|
(3,244
|
)
|
|
|
(206
|
)
|
|
|
(3,450
|
)
|
Sales of Minerals in Place
|
|
|
(6
|
)
|
|
|
|
|
|
|
(7
|
)
|
|
|
(13
|
)
|
|
|
(1,458
|
)
|
|
|
(1,471
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
September 30, 2007
|
|
|
1,435
|
|
|
|
45,644
|
|
|
|
507
|
|
|
|
47,586
|
|
|
|
|
|
|
|
47,586
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved Developed Reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
|
|
September 30, 2007
|
|
|
1,435
|
|
|
|
36,509
|
|
|
|
483
|
|
|
|
38,427
|
|
|
|
|
|
|
|
38,427
|
|
Standardized Measure of Discounted Future Net Cash Flows
Relating to Proved Oil and Gas Reserves
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.
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.
114
NATIONAL
FUEL GAS COMPANY
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended September 30
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(Thousands)
|
|
|
United States
|
|
|
|
|
|
|
|
|
|
|
|
|
Future Cash Inflows
|
|
$
|
4,879,496
|
|
|
$
|
3,911,059
|
|
|
$
|
6,138,522
|
|
Less:
|
|
|
|
|
|
|
|
|
|
|
|
|
Future Production Costs
|
|
|
872,536
|
|
|
|
758,258
|
|
|
|
777,417
|
|
Future Development Costs
|
|
|
229,987
|
|
|
|
205,497
|
|
|
|
188,795
|
|
Future Income Tax Expense at Applicable Statutory Rate
|
|
|
1,423,707
|
|
|
|
1,019,307
|
|
|
|
1,868,548
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Future Net Cash Flows
|
|
|
2,353,266
|
|
|
|
1,927,997
|
|
|
|
3,303,762
|
|
Less:
|
|
|
|
|
|
|
|
|
|
|
|
|
10% Annual Discount for Estimated Timing of Cash Flows
|
|
|
1,292,804
|
|
|
|
1,066,338
|
|
|
|
1,812,230
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Standardized Measure of Discounted Future Net Cash Flows
|
|
|
1,060,462
|
|
|
|
861,659
|
|
|
|
1,491,532
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canada Discontinued Operations
|
|
|
|
|
|
|
|
|
|
|
|
|
Future Cash Inflows
|
|
|
|
|
|
|
197,227
|
|
|
|
601,210
|
|
Less:
|
|
|
|
|
|
|
|
|
|
|
|
|
Future Production Costs
|
|
|
|
|
|
|
92,234
|
|
|
|
136,338
|
|
Future Development Costs
|
|
|
|
|
|
|
11,520
|
|
|
|
12,197
|
|
Future Income Tax Expense at Applicable Statutory Rate
|
|
|
|
|
|
|
(151
|
)
|
|
|
137,524
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Future Net Cash Flows
|
|
|
|
|
|
|
93,624
|
|
|
|
315,151
|
|
Less:
|
|
|
|
|
|
|
|
|
|
|
|
|
10% Annual Discount for Estimated Timing of Cash Flows
|
|
|
|
|
|
|
19,375
|
|
|
|
108,508
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Standardized Measure of Discounted Future Net Cash Flows
|
|
|
|
|
|
|
74,249
|
|
|
|
206,643
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
|
|
Future Cash Inflows
|
|
|
4,879,496
|
|
|
|
4,108,286
|
|
|
|
6,739,732
|
|
Less:
|
|
|
|
|
|
|
|
|
|
|
|
|
Future Production Costs
|
|
|
872,536
|
|
|
|
850,492
|
|
|
|
913,755
|
|
Future Development Costs
|
|
|
229,987
|
|
|
|
217,017
|
|
|
|
200,992
|
|
Future Income Tax Expense at Applicable Statutory Rate
|
|
|
1,423,707
|
|
|
|
1,019,156
|
|
|
|
2,006,072
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Future Net Cash Flows
|
|
|
2,353,266
|
|
|
|
2,021,621
|
|
|
|
3,618,913
|
|
Less:
|
|
|
|
|
|
|
|
|
|
|
|
|
10% Annual Discount for Estimated Timing of Cash Flows
|
|
|
1,292,804
|
|
|
|
1,085,713
|
|
|
|
1,920,738
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Standardized Measure of Discounted Future Net Cash Flows
|
|
$
|
1,060,462
|
|
|
$
|
935,908
|
|
|
$
|
1,698,175
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
115
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
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(Thousands)
|
|
|
United States
|
|
|
|
|
|
|
|
|
|
|
|
|
Standardized Measure of Discounted Future
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Cash Flows at Beginning of Year
|
|
$
|
861,659
|
|
|
$
|
1,491,532
|
|
|
$
|
935,369
|
|
Sales, Net of Production Costs
|
|
|
(276,529
|
)
|
|
|
(306,147
|
)
|
|
|
(272,707
|
)
|
Net Changes in Prices, Net of Production Costs
|
|
|
539,895
|
|
|
|
(941,545
|
)
|
|
|
1,093,353
|
|
Purchases of Minerals in Place
|
|
|
|
|
|
|
7,607
|
|
|
|
|
|
Sales of Minerals in Place
|
|
|
484
|
|
|
|
|
|
|
|
(762
|
)
|
Extensions and Discoveries
|
|
|
98,751
|
|
|
|
66,975
|
|
|
|
100,102
|
|
Changes in Estimated Future Development Costs
|
|
|
(83,199
|
)
|
|
|
(83,750
|
)
|
|
|
(89,805
|
)
|
Previously Estimated Development Costs Incurred
|
|
|
58,710
|
|
|
|
67,048
|
|
|
|
25,038
|
|
Net Change in Income Taxes at Applicable Statutory Rate
|
|
|
(174,920
|
)
|
|
|
404,176
|
|
|
|
(362,956
|
)
|
Revisions of Previous Quantity Estimates
|
|
|
(140,203
|
)
|
|
|
4,850
|
|
|
|
25,055
|
|
Accretion of Discount and Other
|
|
|
175,814
|
|
|
|
150,913
|
|
|
|
38,845
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Standardized Measure of Discounted Future Net Cash Flows at End
of Year
|
|
|
1,060,462
|
|
|
|
861,659
|
|
|
|
1,491,532
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canada Discontinued Operations
|
|
|
|
|
|
|
|
|
|
|
|
|
Standardized Measure of Discounted Future
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Cash Flows at Beginning of Year
|
|
|
74,249
|
|
|
|
206,643
|
|
|
|
110,730
|
|
Sales, Net of Production Costs
|
|
|
(34,581
|
)
|
|
|
(54,176
|
)
|
|
|
(49,467
|
)
|
Net Changes in Prices, Net of Production Costs
|
|
|
35,628
|
|
|
|
(180,216
|
)
|
|
|
174,985
|
|
Purchases of Minerals in Place
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales of Minerals in Place
|
|
|
(151,236
|
)
|
|
|
(238
|
)
|
|
|
(3,751
|
)
|
Extensions and Discoveries
|
|
|
6,908
|
|
|
|
10,369
|
|
|
|
31,028
|
|
Changes in Estimated Future Development Costs
|
|
|
5,722
|
|
|
|
(3,282
|
)
|
|
|
(11,007
|
)
|
Previously Estimated Development Costs Incurred
|
|
|
5,798
|
|
|
|
4,450
|
|
|
|
12,032
|
|
Net Change in Income Taxes at Applicable Statutory Rate
|
|
|
(10,075
|
)
|
|
|
82,966
|
|
|
|
(51,541
|
)
|
Revisions of Previous Quantity Estimates
|
|
|
34,998
|
|
|
|
(15,478
|
)
|
|
|
(5,990
|
)
|
Accretion of Discount and Other
|
|
|
32,589
|
|
|
|
23,211
|
|
|
|
(376
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Standardized Measure of Discounted Future Net Cash Flows at End
of Year
|
|
|
|
|
|
|
74,249
|
|
|
|
206,643
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
116
NATIONAL
FUEL GAS COMPANY
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended September 30
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(Thousands)
|
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
|
|
Standardized Measure of Discounted Future
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Cash Flows at Beginning of Year
|
|
|
935,908
|
|
|
|
1,698,175
|
|
|
|
1,046,099
|
|
Sales, Net of Production Costs
|
|
|
(311,110
|
)
|
|
|
(360,323
|
)
|
|
|
(322,174
|
)
|
Net Changes in Prices, Net of Production Costs
|
|
|
575,523
|
|
|
|
(1,121,761
|
)
|
|
|
1,268,338
|
|
Purchases of Minerals in Place
|
|
|
|
|
|
|
7,607
|
|
|
|
|
|
Sales of Minerals in Place
|
|
|
(150,752
|
)
|
|
|
(238
|
)
|
|
|
(4,513
|
)
|
Extensions and Discoveries
|
|
|
105,659
|
|
|
|
77,344
|
|
|
|
131,130
|
|
Changes in Estimated Future Development Costs
|
|
|
(77,477
|
)
|
|
|
(87,032
|
)
|
|
|
(100,812
|
)
|
Previously Estimated Development Costs Incurred
|
|
|
64,508
|
|
|
|
71,498
|
|
|
|
37,070
|
|
Net Change in Income Taxes at Applicable Statutory Rate
|
|
|
(184,995
|
)
|
|
|
487,142
|
|
|
|
(414,497
|
)
|
Revisions of Previous Quantity Estimates
|
|
|
(105,205
|
)
|
|
|
(10,628
|
)
|
|
|
19,065
|
|
Accretion of Discount and Other
|
|
|
208,403
|
|
|
|
174,124
|
|
|
|
38,469
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Standardized Measure of Discounted Future Net Cash Flows at End
of Year
|
|
$
|
1,060,462
|
|
|
$
|
935,908
|
|
|
$
|
1,698,175
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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, 2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allowance for Uncollectible Accounts
|
|
$
|
31,427
|
|
|
$
|
27,652
|
|
|
$
|
1,414
|
(1)
|
|
$
|
31,839
|
|
|
$
|
28,654
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Represents the discount on accounts receivable purchased in
accordance with the Utility segments 2005 New York rate
agreement. |
|
(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. |
117
|
|
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 the time periods
specified in the SECs rules and forms. 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, 2007.
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, 2007. 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, 2007.
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 the effectiveness of the Companys
internal control over financial reporting as of
September 30, 2007. 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, 2007 that have materially affected, or are
reasonably likely to materially affect, the Companys
internal control over financial reporting.
|
|
Item 9B
|
Other
Information
|
None
|
|
Item 10
|
Directors,
Executive Officers and Corporate Governance
|
The information required by this item concerning the directors
of the Company and corporate governance is omitted pursuant to
Instruction G of
Form 10-K
since the Companys definitive Proxy Statement for its 2008
118
Annual Meeting of Stockholders will be filed with the SEC not
later than 120 days after September 30, 2007. 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
2011, Directors Whose Terms Expire in 2010,
Directors Whose Terms Expire in 2009, and
Section 16(a) Beneficial Ownership Reporting
Compliance and is incorporated herein by reference. The
information concerning corporate governance is set forth in the
definitive Proxy Statement under the heading entitled
Meetings of the Board of Directors and Standing
Committees 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 2008
Annual Meeting of Stockholders will be filed with the SEC not
later than 120 days after September 30, 2007. 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,
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 2008
Annual Meeting of Stockholders will be filed with the SEC not
later than 120 days after September 30, 2007. 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 2008
Annual Meeting of Stockholders will be filed with the SEC not
later than 120 days after September 30, 2007. 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 2008
Annual Meeting of Stockholders will be filed with the SEC not
later than 120 days after September 30, 2007. The
information concerning security ownership of
119
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.
None
|
|
Item 13
|
Certain
Relationships and Related Transactions, and Director
Independence
|
The information required by this item is omitted pursuant to
Instruction G of
Form 10-K
since the Companys definitive Proxy Statement for its 2008
Annual Meeting of Stockholders will be filed with the SEC not
later than 120 days after September 30, 2007. The
information regarding certain relationships and related
transactions is set forth in the definitive Proxy Statement
under the headings Compensation Committee Interlocks and
Insider Participation and Related Person
Transactions and is incorporated herein by reference. The
information regarding director independence is set forth in the
definitive Proxy Statement under the heading Director
Independence 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 2008
Annual Meeting of Stockholders will be filed with the SEC not
later than 120 days after September 30, 2007. 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.
|
|
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 June 7, 2007
(Exhibit 3.1,
Form 8-K
dated June 8, 2007 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)
|
120
|
|
|
|
|
Exhibit
|
|
Description of
|
Number
|
|
Exhibits
|
|
|
|
|
|
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)
|
|
|
|
|
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)
|
|
|
|
|
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)
|
|
4
|
.1
|
|
Amended and Restated Rights Agreement, dated as of
September 1, 2007, between the Company and The Bank of New
York
|
|
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:
|
|
10
|
.1
|
|
Form of Employment Continuation and Noncompetition Agreement
among the Company, a subsidiary of the Company and each of
Philip C. Ackerman, Anna Marie Cellino, Paula M. Ciprich, Donna
L. DeCarolis, John R. Pustulka, James D. Ramsdell, David F.
Smith and Ronald J. Tanski
|
|
10
|
.2
|
|
Employment Continuation and Noncompetition Agreement, dated as
of September 20, 2007, among the Company, Seneca Resources
Corporation and Matthew D. Cabell
|
|
|
|
|
Letter Agreement between the Company and Matthew D. Cabell,
dated November 17, 2006 (Exhibit 10.1,
Form 10-Q
for the quarterly period ended December 31, 2006 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)
|
|
|
|
|
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)
|
121
|
|
|
|
|
Exhibit
|
|
Description of
|
Number
|
|
Exhibits
|
|
|
|
|
|
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, as amended
and restated as of February 15, 2007 (Exhibit 10.2,
Form 10-Q
for the quarterly period ended March 31, 2007 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)
|
|
|
|
|
Form of Restricted Stock Award Notice under National Fuel Gas
Company 1997 Award and Option Plan (Exhibit 10.2,
Form 10-Q
for the quarterly period ended December 31, 2006 in File
No. 1-3880)
|
|
|
|
|
Form of Stock Option Award Notice under National Fuel Gas
Company 1997 Award and Option Plan (Exhibit 10.3,
Form 10-Q
for the quarterly period ended December 31, 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)
|
|
|
|
|
National Fuel Gas Company 2007 Annual At Risk Compensation
Incentive Program (Exhibit 10.1,
Form 10-Q
for the quarterly period ended March 31, 2007 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)
|
|
|
|
|
Description of performance goals for certain executive officers
under the Companys Annual At Risk Compensation Incentive
Program (Exhibit 10.8,
Form 10-Q
for the quarterly period ended December 31, 2006 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 December 6, 2006 (Exhibit 10.6,
Form 10-Q
for the quarterly period ended December 31, 2006 in File
No. 1-3880)
|
|
|
|
|
National Fuel Gas Company Deferred Compensation Plan, as amended
and restated through May 1, 1994 (Exhibit 10.7,
Form 10-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,
Form 10-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)
|
122
|
|
|
|
|
Exhibit
|
|
Description of
|
Number
|
|
Exhibits
|
|
|
|
|
|
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)
|
|
|
|
|
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)
|
|
10
|
.3
|
|
National Fuel Gas Company Tophat Plan, as amended
September 20, 2007
|
|
|
|
|
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 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)
|
123
|
|
|
|
|
Exhibit
|
|
Description of
|
Number
|
|
Exhibits
|
|
|
|
|
|
National Fuel Gas Company and Participating Subsidiaries
Executive Retirement Plan, Amended and Restated as of
January 1, 2007 (Exhibit 10.5,
Form 10-Q
for the quarterly period ended December 31, 2006 in File
No. 1-3880)
|
|
10
|
.4
|
|
National Fuel Gas Company and Participating Subsidiaries
Executive Retirement Plan, Amended and Restated as of
September 20, 2007
|
|
|
|
|
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)
|
|
|
|
|
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)
|
|
|
|
|
National Fuel Gas Company Performance Incentive Program
(Exhibit 10.1,
Form 8-K
dated June 3, 2005 in File
No. 1-3880)
|
|
|
|
|
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)
|
|
10
|
.5
|
|
Amended and Restated Retirement Benefit Agreement for David F.
Smith, dated September 20, 2007,among the Company, National
Fuel Gas Supply Corporation and David F. Smith
|
|
|
|
|
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)
|
|
|
|
|
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)
|
|
|
|
|
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)
|
|
|
|
|
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)
|
|
|
|
|
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)
|
|
|
|
|
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)
|
|
|
|
|
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)
|
|
|
|
|
Description of long-term performance incentives under the
National Fuel Gas Company Performance Incentive Program
(Exhibit 10.7,
Form 10-Q
for the quarterly period ended December 31, 2006 in File
No. 1-3880)
|
|
|
|
|
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)
|
|
|
|
|
Agreement, dated September 24, 2006, between the Company
and Philip C. Ackerman regarding death benefit
(Exhibit 10.1,
Form 10-K
for the fiscal year ended September 30, 2006 in File
No. 1-3880)
|
|
|
|
|
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)
|
|
|
|
|
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)
|
|
12
|
|
|
Statements regarding Computation of Ratios: Ratio of Earnings to
Fixed Charges for the fiscal years ended September 30, 2003
through 2007
|
|
21
|
|
|
Subsidiaries of the Registrant
|
|
23
|
|
|
Consents of Experts:
|
124
|
|
|
|
|
Exhibit
|
|
Description of
|
Number
|
|
Exhibits
|
|
|
23
|
.1
|
|
Consent of Netherland, Sewell & Associates, Inc.
regarding Seneca Resources Corporation
|
|
23
|
.2
|
|
Consent of Independent Registered Public Accounting Firm
|
|
31
|
|
|
Rule 13a-14(a)/15d-14(a)
Certifications:
|
|
31
|
.1
|
|
Written statements of Chief Executive Officer pursuant to
Rule 13a-14(a)/15d-14(a)
of the Exchange Act
|
|
31
|
.2
|
|
Written statements of Principal Financial Officer pursuant to
Rule 13a-14(a)/15d-14(a)
of the Exchange Act
|
|
32
|
|
|
Certifications pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002
|
|
99
|
|
|
Additional Exhibits:
|
|
99
|
.1
|
|
Report of Netherland, Sewell & Associates, Inc.
regarding Seneca Resources Corporation
|
|
99
|
.2
|
|
Company Maps
|
|
|
|
|
Incorporated herein by reference as indicated.
|
|
|
|
|
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
|
|
|
|
|
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
|
125
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: November 29, 2007
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.
|
|
|
|
|
|
|
Signature
|
|
Title
|
|
|
|
|
|
|
|
|
/s/ P.
C. Ackerman
P.
C. Ackerman
|
|
Chairman of the Board, Chief Executive Officer and Director
|
|
Date: November 29, 2007
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|
|
|
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/s/ R.
T. Brady
R.
T. Brady
|
|
Director
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|
Date: November 29, 2007
|
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|
|
|
|
/s/ R.
D. Cash
R.
D. Cash
|
|
Director
|
|
Date: November 29, 2007
|
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|
|
|
|
/s/ S.
E. Ewing
S.
E. Ewing
|
|
Director
|
|
Date: November 29, 2007
|
|
|
|
|
|
/s/ R.
E. Kidder
R.
E. Kidder
|
|
Director
|
|
Date: November 29, 2007
|
|
|
|
|
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/s/ C.
G. Matthews
C.
G. Matthews
|
|
Director
|
|
Date: November 29, 2007
|
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|
|
|
|
/s/ G.
L. Mazanec
G.
L. Mazanec
|
|
Director
|
|
Date: November 29, 2007
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/s/ R.
G. Reiten
R.
G. Reiten
|
|
Director
|
|
Date: November 29, 2007
|
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/s/ J.
F. Riordan
J.
F. Riordan
|
|
Director
|
|
Date: November 29, 2007
|
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|
|
/s/ D.
F. Smith
D.
F. Smith
|
|
President, Chief Operating Officer and Director
|
|
Date: November 29, 2007
|
126
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Signature
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Title
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/s/ R.
J. Tanski
R.
J. Tanski
|
|
Treasurer and Principal Financial Officer
|
|
Date: November 29, 2007
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|
/s/ K.
M. Camiolo
K.
M. Camiolo
|
|
Controller and Principal Accounting Officer
|
|
Date: November 29, 2007
|
127