Form 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, 2008
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TRANSITION REPORT PURSUANT TO
SECTION 13 OR 15(d)
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OF THE SECURITIES EXCHANGE ACT
OF 1934
For the Transition Period
from
to
Commission File Number 1-3880
National Fuel Gas
Company
(Exact name of registrant as
specified in its charter)
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New Jersey
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13-1086010
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(State or other jurisdiction
of
incorporation or organization)
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(I.R.S. Employer
Identification No.)
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6363 Main Street
Williamsville, New York
(Address of principal
executive offices)
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14221
(Zip
Code)
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(716) 857-7000
Registrants telephone number, including area
code
Securities registered pursuant to Section 12(b) of the
Act:
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Name of
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Each Exchange
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on Which
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Title of Each Class
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Registered
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Common Stock, $1 Par Value, and
Common Stock Purchase Rights
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New York Stock Exchange
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Securities registered pursuant to Section 12(g) of the
Act:
None
Indicate by check mark if the registrant is a well-known
seasoned issuer, as defined in Rule 405 of the Securities
Act. Yes þ No o
Indicate by check mark if the registrant is not required to file
reports pursuant to Section 13 or Section 15
(d) of the
Act. Yes o No þ
Indicate by check mark whether the registrant (1) has filed
all reports required to be filed by Section 13 or 15(d) of
the Securities Exchange Act of 1934 during the preceding
12 months and (2) has been subject to such filing
requirements for the past
90 days. Yes þ No o
Indicate by check mark if disclosure of delinquent filers
pursuant to Item 405 of
Regulation S-K
is not contained herein, and will not be contained, to the best
of the registrants knowledge, in definitive proxy or
information statements incorporated by reference in
Part III of this
Form 10-K
or any amendment to this
Form 10-K. o
Indicate by check mark whether the registrant is a large
accelerated filer, an accelerated filer, a non-accelerated
filer, or a smaller reporting company. See the definitions of
large accelerated filer, accelerated
filer and smaller reporting company in Rule
12b-2 of the
Exchange Act. (Check one):
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Large
accelerated
filer þ
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Accelerated
filer o
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Non-accelerated
filer o
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Smaller reporting
company o
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(Do not check if a smaller
reporting company)
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 $3,768,755,000 as of
March 31, 2008.
Common Stock, $1 Par Value, outstanding as of
October 31, 2008: 79,124,644 shares.
DOCUMENTS
INCORPORATED BY REFERENCE
Portions of the registrants definitive Proxy Statement for
its 2009 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:
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National
Fuel Gas Companies
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Company
The Registrant, the
Registrant and its subsidiaries or the Registrants
subsidiaries as appropriate in the context of the disclosure
Data-Track
Data-Track Account
Services, Inc.
Distribution Corporation
National Fuel Gas
Distribution Corporation
Empire
Empire State Pipeline
ESNE
Energy Systems North
East, LLC
Highland
Highland Forest
Resources, Inc.
Horizon
Horizon Energy
Development, Inc.
Horizon
B.V. Horizon Energy
Development B.V.
Horizon LFG
Horizon LFG, Inc.
Horizon Power
Horizon Power, Inc.
Leidy Hub
Leidy Hub, Inc.
Midstream
National Fuel Gas
Midstream Corporation
Model City
Model City Energy, LLC
National Fuel
National Fuel Gas Company
NFR
National Fuel Resources,
Inc.
Registrant
National Fuel Gas Company
SECI
Seneca Energy Canada Inc.
Seneca
Seneca Resources
Corporation
Seneca Energy
Seneca Energy II, LLC
Supply Corporation
National Fuel Gas Supply
Corporation
Toro
Toro Partners, LP
U.E.
United Energy, a.s.
EPA
United States
Environmental Protection Agency
FASB
Financial Accounting
Standards Board
FERC
Federal Energy
Regulatory Commission
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
APB 18
Accounting Principles
Board Opinion No. 18, The Equity Method of Accounting for
Investments in Common Stock
APB 25
Accounting Principles
Board Opinion No. 25, Accounting for Stock Issued to
Employees
ARB 51
Accounting Research
Bulletin No. 51, Consolidated Financial Statements
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.
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.
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.
Open Season
A bidding procedure used
by pipelines to allocate firm transportation or storage capacity
among prospective shippers, in which all bids submitted during a
defined time period are evaluated as if they had been submitted
simultaneously.
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.
PCB
Polychlorinated Biphenyl
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 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 141R
Statement of Financial
Accounting Standards No. 141R, Business Combinations
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
SFAS 160
Statement of Financial
Accounting Standards No. 160, Noncontrolling Interests in
Consolidated Financial Statements, an Amendment of ARB 51
SFAS 161
Statement of Financial
Accounting Standards No. 161, Disclosures about Derivative
Instruments and Hedging Activities, an Amendment of SFAS 133
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, 2008
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, objectives, goals, projections, strategies,
future events or performance and underlying assumptions, capital
structure, anticipated capital expenditures, completion of
construction and other 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.
PART I
The
Company and its Subsidiaries
National Fuel Gas Company (the Registrant), incorporated in
1902, is a holding company organized under the laws of the State
of New Jersey. Except as otherwise indicated below, the
Registrant owns directly or indirectly all of the outstanding
securities of its subsidiaries. Reference to the
Company in this report means the Registrant, the
Registrant and its subsidiaries or the Registrants
subsidiaries as appropriate in the context of the disclosure.
Also, all references to a certain year in this report relate to
the Companys fiscal year ended September 30 of that year
unless otherwise noted.
The Company is a diversified energy company and reports
financial results for five business segments.
1. The Utility segment operations are carried out by
National Fuel Gas Distribution Corporation (Distribution
Corporation), a New York corporation. Distribution Corporation
sells natural gas or provides natural gas transportation
services to approximately 727,000 customers through a local
distribution system located in western New York and northwestern
Pennsylvania. The principal metropolitan areas served by
Distribution Corporation include Buffalo, Niagara Falls and
Jamestown, New York and Erie and Sharon, Pennsylvania.
2. The Pipeline and Storage segment operations are carried
out by National Fuel Gas Supply Corporation (Supply
Corporation), a Pennsylvania corporation, and Empire State
Pipeline (Empire), a New York joint venture between two wholly
owned subsidiaries of the Company. Supply Corporation provides
interstate natural gas transportation and storage services for
affiliated and nonaffiliated companies through (i) an
integrated gas pipeline system extending from southwestern
Pennsylvania to the New York-Canadian border at the Niagara
River and eastward to Ellisburg and Leidy, Pennsylvania, and
(ii) 27 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 other
interstate gas pipeline companies. Empire, an intrastate
pipeline company acquired by the Company in 2003, transports
natural gas for Distribution Corporation and for other
utilities, large industrial customers and power producers in New
York State. Empire owns the Empire Pipeline, which is 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
77-mile
pipeline extension from near Rochester, New York to an
interconnection near Corning, New York with the unaffiliated
Millennium Pipeline project, 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
Connector and Millennium Pipeline projects, which is currently
expected to occur in December 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
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waters and some state waters. At September 30, 2008, the
Company had U.S. reserves of 46,198 Mbbl of oil and
225,899 MMcf of natural gas.
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.
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, wholesale, commercial,
public authority and residential customers primarily in western
and central New York and northwestern Pennsylvania, offering
competitively priced natural gas 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, 2008,
the Company owned 103,680 acres of timber property and
managed an additional 3,122 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 reported 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;
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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); and
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National Fuel Gas Midstream Corporation, a Pennsylvania
corporation formed to build, own and operate natural gas
processing and pipeline gathering facilities in the Appalachian
region.
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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 2008.
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Rates and
Regulation
The Registrant is a holding company as defined under PUHCA 2005.
PUHCA 2005 repealed PUHCA 1935, to which the Company was
formerly subject, and granted the FERC and state public utility
commissions access to certain books and records of companies in
holding company systems. Pursuant to the FERCs regulations
under PUHCA 2005, the Company and its subsidiaries are exempt
from the FERCs books and records regulations under PUHCA
2005.
The Utility segments rates, services and other matters are
regulated by the NYPSC with respect to services provided within
New York and by the PaPUC with respect to services provided
within Pennsylvania. For additional discussion of the Utility
segments rates and regulation, see Item 7, MD&A
under the heading Rate and Regulatory Matters and
Item 8 at Note C Regulatory Matters.
The Pipeline and Storage segments rates, services and
other matters are currently regulated by the FERC with respect
to Supply Corporation and by the NYPSC with respect to Empire.
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 December 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
The Utility segment contributed approximately 22.9% of the
Companys 2008 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 20.1%
of the Companys 2008 net income available for common
stock.
Supply Corporation has service agreements for all of its firm
storage capacity, totaling 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
4,811 MDth or 7.1% of the total firm storage capacity.
Nonaffiliated customers have contracted for the remaining 35,732
MDth or 52.2% of the total firm storage capacity. The majority
of Supply Corporations storage and transportation services
are performed under contracts that allow Supply Corporation or
the shipper to terminate the contract upon six or twelve
months notice effective at the end of the contract term.
The contracts also typically include evergreen
language designed to allow the contracts to extend year-to-year
at the end of the primary term. At the beginning of 2009, 72.0%
of Supply Corporations total firm storage capacity was
committed under contracts that, subject to 2008 shipper or
Supply Corporation notifications, could have been terminated
effective in 2009. Supply Corporation did not issue or
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receive any such storage contract termination notifications in
2008. The strong demand for market-area storage enabled Supply
Corporation to eliminate its remaining storage service rate
discounts in 2007, and effective April 1, 2008, all storage
services were contracted at the maximum tariff rates.
Supply Corporations firm transportation capacity is not
limited to a fixed quantity, due to the diverse weblike nature
of its pipeline system, and is subject to change as the market
identifies different transportation paths and receipt/delivery
point combinations. Supply Corporation currently has firm
transportation service agreements for approximately 2,117 MDth
per day (contracted transportation capacity). The Utility
segment accounts for approximately 1,065 MDth per day or 50.3%
of contracted transportation capacity, and the Energy Marketing
and Exploration and Production segments represent another 102
MDth per day or 4.8% of contracted transportation capacity. The
remaining 950 MDth or 44.9% of contracted transportation
capacity is subject to firm contracts with nonaffiliated
customers.
At the beginning of 2009, 49.3% of Supply Corporations
contracted transportation capacity was committed under affiliate
contracts that were scheduled to expire in 2009 or, subject to
2008 shipper or Supply Corporation notifications, could have
been terminated effective in 2009. Based on contract expirations
and termination notices received in 2008 for 2009 termination,
and taking into account any known contract additions, contracted
transportation capacity with affiliates is expected to decrease
0.3% in 2009. Similarly, 26.7% of contracted transportation
capacity was committed under unaffiliated shipper contracts that
were scheduled to expire in 2009 or, subject to 2008 shipper or
Supply Corporation notifications, could have been terminated
effective in 2009. Based on contract expirations and termination
notices received in 2008 for 2009 termination, and taking into
account any known contract additions, contracted transportation
capacity with unaffiliated shippers is expected to increase 9.4%
in 2009. This increase is due largely to the addition of
compression at various facilities throughout the system as well
as other projects designed to create incremental transportation
capacity. 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.
For the
2008-2009
winter period, Empire has service agreements in place for the
full amount of its firm transportation capacity to its existing
delivery points, totaling approximately 547 MDth per day. Most
of Empires firm capacity (91.2%) has been contracted as
long-term full-year deals. A small number of those contracts are
due to expire during fiscal 2009, representing 1.4% of
Empires firm capacity. In addition, Empire has some
seasonal (winter-only) contracts that extend for multiple years,
representing 2.7% of Empires firm capacity. One of those
seasonal contracts is due to expire during fiscal 2009;
representing 1.1% of Empires firm capacity. Arrangements
for the remaining 6.1% of Empires firm capacity are
seasonal or annual contracts that expire before the end of
fiscal 2009. Empire expects that all available capacity arising
from expiring agreements will be re-contracted under new
seasonal or annual agreements. The Utility segment accounts for
approximately 7.8% of Empires firm capacity, and the
Energy Marketing segment accounts for approximately 1.9% of
Empires firm capacity, with the remaining 90.3% of
Empires firm capacity subject to contracts with
nonaffiliated customers.
Upon the completion of the Empire Connector project, Empire will
have expansion capacity for the
2008-2009
winter period. Empire has a firm service agreement for 150.7
MDth per day of this expansion capacity. This long-term
full-year agreement represents approximately 60% of the Empire
Connector expansion capacity. The Company continues to market
the remaining capacity on both a firm and interruptible basis.
None of this contracted expansion capacity will expire during
fiscal 2009.
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
54.6% of the Companys 2008 net income available for
common stock.
6
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 2.2% of
the Companys 2008 net income available for common
stock.
Additional discussion of the Energy Marketing segment appears
below under the headings Sources and Availability of Raw
Materials, Competition: The Energy Marketing
Segment and Seasonality, in Item 7,
MD&A and in Item 8, Financial Statements and
Supplementary Data.
The
Timber Segment
The Timber segments contribution to the Companys
2008 net income available for common stock was not
significant.
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 0.2% of the Companys 2008 net income
available for common stock.
Additional discussion of the All Other category and Corporate
operations appears below in Item 7, MD&A and in
Item 8, Financial Statements and Supplementary Data.
Discontinued
Operations
In 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 2008, the Utility segment purchased 76.0 Bcf of
gas for core market demand. All such purchases were made from
non-affiliated companies. Gas purchased from producers and
suppliers in the southwestern United States and Canada under
firm contracts (seasonal and longer) accounted for 89% of these
purchases. Purchases of gas on the spot market (contracts for
one month or less) accounted for 11% of the Utility
segments 2008 purchases. Purchases from Total
Gas & Power North America Inc. (18%), Chevron Natural
Gas (17%), ConocoPhillips Company (16%) and BP Canada (11%)
accounted for 62% of the Utilitys 2008 gas purchases. No
other producer or supplier provided the Utility segment with
more than 10% of its gas requirements in 2008.
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.
7
The Exploration and Production segment seeks to discover and
produce raw materials (natural gas, oil and hydrocarbon liquids)
as further described in this report in Item 7, MD&A
and Item 8 at Note J Business Segment
Information and Note O Supplementary
Information for Oil and Gas Producing Activities.
With respect to the Timber segment, Highland requires an
adequate supply of timber to process in its sawmill and kiln
operations. Fifty-two percent of the timber processed during
2008 in Highlands sawmill operations came from land owned
by the Companys subsidiaries, and 48% 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 5.4 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 2008, this segment
purchased 57 Bcf of gas, including 56 Bcf for core
market demands. The remaining 1 Bcf largely represents gas
used in operations. The gas purchased by the Energy Marketing
segment originates in either the Appalachian or mid-continent
regions of the United States or in Canada.
Competition
Competition in the natural gas industry exists among providers
of natural gas, as well as between natural gas and other sources
of energy. The natural gas industry has gone through various
stages of regulation. Apart from environmental and state utility
commission regulation, the natural gas industry has experienced
considerable deregulation. This has enhanced the competitive
position of natural gas relative to other energy sources, such
as fuel oil or electricity, since some of the historical
regulatory impediments to adding customers and responding to
market forces have been removed. In addition, management
believes that the environmental advantages of natural gas have
enhanced its competitive position relative to other fuels.
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. On
September 11, 2008, the PaPUC adopted a Final Order and
Action Plan designed to increase effective competition in
the retail market for natural gas services. The plan sets
forth a schedule of action items for utilities and the PaPUC in
order to remove barriers in the market structure
that, in the opinion of the PaPUC, prevented the full
participation of unregulated natural gas suppliers in
Pennsylvania retail markets.
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.
8
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.
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 supply.
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 hardwood species such as cherry, oak and maple as veneer
logs, saw logs, export logs or lumber ultimately used in the
production of high-end furniture, cabinetry and flooring. The
Timber segment sells its products in domestic and international
markets.
Seasonality
Variations in weather conditions can materially affect the
volume of gas delivered by the Utility segment, as virtually all
of its residential and commercial customers use gas for space
heating. The effect that this has on Utility segment margins in
New York is mitigated by a WNC, which covers the eight-month
period from October through May. Weather that is warmer than
normal results in a surcharge being added to customers
current bills, while weather that is 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
9
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 December 2008), Empires allowed
rates, like Supply Corporations, will be based on a
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.
Capital
Expenditures
A discussion of capital expenditures by business segment is
included in Item 7, MD&A under the heading
Investing Cash Flow.
Environmental
Matters
A discussion of material environmental matters involving the
Company is included in Item 7, MD&A under the heading
Environmental Matters and in Item 8,
Note H Commitments and Contingencies.
Miscellaneous
The Company and its wholly owned or majority-owned subsidiaries
had a total of 1,943 full-time employees at
September 30, 2008. This is a decrease of approximately
one-half of one percent from the 1,952 employees in the
Companys U.S. operations at September 30, 2007.
In 2008 the Company entered into new agreements with collective
bargaining units in New York. The new agreements went into
effect in February 2008 and expire in February 2013. In November
2008 the Company entered into a new agreement with a collective
bargaining unit in Pennsylvania. The agreement will go into
effect in April 2009 and expire in April 2014. An agreement
covering employees in another collective bargaining unit in
Pennsylvania is scheduled to expire in May 2009. In
November 2008 the Company reached a new agreement with the
local leadership of that collective bargaining unit. The members
of the collective bargaining unit are scheduled to vote on the
agreement in December 2008.
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,
2008(1)
|
|
|
|
|
Current Company
|
|
|
Positions and
|
|
|
Other Material
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|
|
Business Experience
|
Name and Age (as of
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During Past
|
November 15, 2008)
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Five Years
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David F. Smith
(55)
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Chief Executive Officer of the Company since February 2008 and
President of the Company since February 2006. Mr. Smith
previously served as Chief Operating Officer of the Company from
February 2006 through January 2008; President of Supply
Corporation from April 2005 through June 2008; President of
Empire from April 2005 through January 2008; Vice President of
the Company from April 2005 through January 2006; President
of Distribution Corporation from July 1999 to April 2005; and
Senior Vice President of Supply Corporation from July 2000 to
April 2005.
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Ronald J. Tanski
(56)
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Treasurer and Principal Financial Officer of the Company since
April 2004; President of Supply Corporation since July 2008. Mr.
Tanski previously served as President of Distribution
Corporation from February 2006 through June 2008; Treasurer of
Distribution Corporation from April 2004 through September 2008;
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
(50)
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|
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.
|
Anna Marie Cellino
(55)
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President of Distribution Corporation since July 2008. Ms.
Cellino previously served as Secretary of the Company from
October 1995 through June 2008; Secretary of Distribution
Corporation from September 1999 through September 2008; and
Senior Vice President of Distribution Corporation from July 2001
through June 2008.
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Karen M. Camiolo
(49)
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Controller and Principal Accounting Officer of the Company since
April 2004; Controller of Distribution Corporation and Supply
Corporation since April 2004; and Chief Auditor of the Company
from July 1994 through March 2004.
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Carl M. Carlotti
(53)
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Senior Vice President of Distribution Corporation since January
2008. Mr. Carlotti previously served as Vice President of
Distribution Corporation from October 1998 to January 2008.
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Paula M. Ciprich
(48)
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Secretary of the Company since July 2008; General Counsel of the
Company since January 2005; Secretary of Distribution
Corporation since July 2008. Ms. Ciprich previously served as
General Counsel of Distribution Corporation from February 1997
through February 2007 and as Assistant Secretary of Distribution
Corporation from February 1997 through June 2008.
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Donna L. DeCarolis
(49)
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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.
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John R. Pustulka
(56)
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Senior Vice President of Supply Corporation since July 2001.
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James D. Ramsdell
(53)
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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.
Recent
disruptions in financial markets may affect National Fuels
ability to obtain financing or refinance maturing debt on
reasonable terms and may have other adverse
effects.
Widely-documented disruptions in financial markets have resulted
in a severe tightening of credit availability in the United
States. Liquidity in credit markets has contracted
significantly, making terms for certain financings less
attractive. Ongoing turmoil in the credit markets may make it
difficult for National Fuel to obtain financing on acceptable
terms or at all for working capital, capital expenditures and
other investments and to refinance maturing debt on favorable
terms. These difficulties could adversely affect National
Fuels operations and financial performance.
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.
Recent access to the commercial paper markets has been on less
favorable terms as a result of ongoing turmoil in the credit
markets, and the commercial paper markets may not consistently
be a reliable source of short-term financing for National Fuel
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 (S&P), Moodys
Investors Service and Fitch Ratings Service. On October 15,
2008, National Fuels senior unsecured credit rating of
BBB+ was placed on CreditWatch-with negative implications by
S&P. A ratings downgrade could increase the interest cost
of debt issued by National Fuel and decrease future availability
of money from banks, commercial paper purchasers and other
sources. National Fuels debt securities are currently
rated at investment grade and the Company believes it is
important to maintain investment grade credit ratings to conduct
its business.
National
Fuel may be adversely affected by economic conditions and their
impact on our suppliers and customers.
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 and energy
marketing territories also impact its collections of accounts
receivable. All of National Fuels segments are exposed to
risks associated with the creditworthiness or performance of key
suppliers and customers, many of which may be adversely affected
by volatile conditions in the financial markets. These
conditions could result in financial
12
instability or other adverse effects at any of our suppliers or
customers. For example, counterparties to National Fuels
commodity hedging arrangements might not be able to perform
their obligations under these arrangements. Customers of
National Fuels Utility and Energy Marketing segments may
have particular trouble paying their bills during periods of
declining economic activity and high commodity prices,
potentially resulting in increased bad debt expense and reduced
earnings. Any of these events could have a material adverse
effect on National Fuels results of operations, financial
condition and cash flows.
The
increasing costs of certain employee and retiree benefits could
adversely affect National Fuels results.
National Fuels earnings and cash flow may be impacted by
the amount of income or expense it expends or records for
employee benefit plans. This is particularly true for pension
plans, which are dependent on actual plan asset returns and
factors used to determine the value and current costs of plan
benefit obligations. In addition, if medical costs rise at a
rate faster than the general inflation rate, National Fuel might
not be able to mitigate the rising costs of medical benefits.
Increases to the costs of pension and medical benefits could
have an adverse effect on National Fuels financial results.
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 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 did not result 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. On September 11, 2008, the PaPUC
adopted a Final Order and Action Plan designed to increase
effective competition in the retail market for natural gas
services. The plan sets forth a schedule of action items
for utilities and the PaPUC in order to remove barriers in
the market structure that, in the opinion of the PaPUC,
prevented the full participation of unregulated natural gas
13
suppliers in Pennsylvania retail markets. 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.
Both the NYPSC and the PaPUC have instituted proceedings for the
purpose of promoting conservation of energy commodities,
including natural gas. In New York, Distribution Corporation
implemented a Conservation Incentive Program that promotes
conservation and efficient use of natural gas by offering
customer rebates for high-efficiency appliances, among other
things. The intent of conservation and efficiency programs is to
reduce customer usage of natural gas. Under traditional
volumetric rates, reduced usage by customers results in
decreased revenues to the Utility. To prevent revenue erosion
caused by conservation, the NYPSC approved a revenue
decoupling mechanism that renders Distribution
Corporations New York division financially indifferent to
the effects of conservation. In Pennsylvania, although a
proceeding is pending, the PaPUC has not yet directed
Distribution Corporation to implement conservation measures. If
the NYPSC were to revoke the revenue decoupling mechanism in a
future proceeding or the PaPUC were to adopt a conservation
program without a revenue decoupling mechanism or other changes
in rate design, reduced customer usage could decrease revenues,
forcing Distribution Corporation to file for rate relief.
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 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
14
gas costs, during periods when natural gas prices are
significantly higher than historical levels, customers may have
trouble paying the resulting higher bills, and Distribution
Corporations bad debt expenses may increase and ultimately
reduce earnings.
Changes
in interest rates 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 in part upon interest
rates. 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 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
15
certain customers and their forecasted consumption of natural
gas. Depending on market conditions for natural gas and crude
oil and the levels of production actually achieved, it is
possible that certain of those assumptions may change in the
future, and, depending on the magnitude of any such changes, it
is possible that a portion of the Companys hedges may no
longer be considered highly effective. In that case, gains or
losses from the ineffective derivative financial instruments
would be marked-to-market on the income statement without regard
to an underlying physical transaction. Gains would occur to the
extent that natural gas and crude oil hedge prices exceed market
prices for the Companys natural gas and crude oil
production, and losses would occur to the extent that market
prices for the Companys natural gas and crude oil
production 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 reserve
16
estimates in the future. Estimates of economically recoverable
oil and natural gas reserves and of future net cash flows depend
upon a number of variable factors and assumptions, including
historical production from the area compared with production
from other comparable producing areas, and the assumed effects
of regulations by governmental agencies. Because all reserve
estimates are to some degree subjective, each of the following
items may differ materially from those assumed in estimating
reserves: the quantities of oil and natural gas that are
ultimately recovered, the timing of the recovery of oil and
natural gas reserves, the production and operating costs
incurred, the amount and timing of future development 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 non-productive 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, 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
17
laws and regulations could require unexpected capital
expenditures at National Fuels facilities. Because the
costs of complying with environmental regulations are
significant, additional regulation could negatively affect
National Fuels business. Although National Fuel cannot
predict the impact of the interpretation or enforcement of EPA
standards or other federal, state and local regulations,
National Fuels costs could increase if environmental laws
and regulations become more strict.
The
nature of National Fuels operations presents inherent
risks of loss that could adversely affect its results of
operations, financial condition and cash flows.
National Fuels operations 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.
Significant
shareholders or potential shareholders may attempt to effect
changes at National Fuel or acquire control over National Fuel,
which could adversely affect National Fuels results of
operations and financial condition.
In January 2008, National Fuel entered into an agreement with
New Mountain Vantage GP, L.L.C. (New Mountain)
and certain parties related to New Mountain, including the
California Public Employees Retirement System
(collectively, Vantage), to settle a proxy contest
pertaining to the election of directors to National Fuels
Board of Directors at National Fuels 2008 Annual Meeting
of Stockholders. Pursuant to the settlement agreement, National
Fuel and Vantage agreed, among other things, to a standstill
whereby, until September 2009, Vantage will not, among
other things, acquire voting securities that would increase its
beneficial ownership to more than 9.6% of National Fuels
voting securities; engage in any proxy solicitations or advance
any shareholder proposals; attempt to control National
Fuels Board of Directors, management or
18
policies; call a meeting of shareholders; obtain additional
representation to the Board of Directors; or effect the removal
of any member of the Board of Directors. At the end of the
standstill period, Vantage may again seek to effect changes at
National Fuel or acquire control over National Fuel. In
addition, other existing or potential shareholders may engage in
proxy solicitations, advance shareholder proposals or otherwise
attempt to effect changes or acquire control over National Fuel.
Campaigns by shareholders to effect changes at publicly traded
companies are sometimes led by investors seeking to increase
short-term shareholder value through actions such as changes in
strategy or management, changes to the board of directors,
restructuring, increased financial leverage, special dividends,
stock repurchases or sales of assets or the entire company.
Responding to proxy contests and other actions by activist
shareholders can be costly and time-consuming, disrupting
National Fuels operations and diverting the attention of
National Fuels Board of Directors and senior management.
As a result, shareholder campaigns could adversely affect
National Fuels results of operations and financial
condition.
|
|
Item 1B
|
Unresolved
Staff Comments
|
None
General
Information on Facilities
The net investment of the Company in property, plant and
equipment was $3.2 billion at September 30, 2008.
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 (35%), 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
(2%) 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
$163.1 million, or 5.5%, since 2003. 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, 2008. The
net investment in its gas distribution network (including
14,819 miles of distribution pipeline) and its service
connections to customers represent approximately 52% and 34%,
respectively, of the Utility segments net investment in
property, plant and equipment at September 30, 2008.
The Pipeline and Storage segment had a net investment of
$826.5 million in property, plant and equipment at
September 30, 2008. Transmission pipeline represents 27% of
this segments total net investment and includes
2,371 miles of pipeline utilized to move large volumes of
gas throughout its service area. Storage facilities represent
21% of this segments total net investment and consist of
31 storage fields, four of which are jointly owned and operated
with certain pipeline suppliers, and 429 miles of pipeline.
Net investment in storage facilities includes $94.8 million
of gas stored underground-noncurrent, representing the cost of
the gas utilized 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 27 compressor stations with 75,104 installed
compressor horsepower that represent 11% of this segments
total net investment in property, plant and equipment.
The Exploration and Production segment had a net investment in
property, plant and equipment of $1.1 billion at
September 30, 2008.
19
The Timber segment had a net investment in property, plant and
equipment of $86.4 million at September 30, 2008.
Located primarily in northwestern Pennsylvania, the net
investment includes two sawmills, 103,680 acres of land and
timber, and 3,122 acres of timber rights.
The Utility and Pipeline and Storage segments facilities
provided the capacity to meet the Companys 2008 peak day
sendout, including transportation service, of 1,632 MMcf,
which occurred on February 10, 2008. Withdrawals from
storage of 768.3 MMcf provided approximately 47.1% 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 and undeveloped reserve information for Seneca.
Senecas proved developed and undeveloped natural gas
reserves increased from 205 Bcf at September 30, 2007
to 226 Bcf at September 30, 2008. This increase is
attributed primarily to extensions and discoveries
(40.1 Bcf), primarily in the Appalachian region
(31.3 Bcf). This increase was partially offset by
production of 22.3 Bcf. Senecas proved developed and
undeveloped oil reserves decreased from 47,586 Mbbl at
September 30, 2007 to 46,198 Mbbl at September 30,
2008. This decrease is attributed to production (3,070 Mbbl),
primarily occurring in California (2,460 Mbbl) and sales of
minerals in place (1,334 Mbbl). These decreases were partially
offset by purchases of minerals in place (2,084 Mbbl) and
extensions and discoveries (827 Mbbl). On a Bcfe basis,
Senecas proved developed and undeveloped reserves
increased from 491 Bcfe at September 30, 2007 to
503 Bcfe at September 30, 2008. 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). On a Bcfe basis,
Senecas proved developed and undeveloped reserves
decreased from 581 Bcfe at September 30, 2006 to
491 Bcfe at September 30, 2007.
Senecas oil and gas reserves reported in Item 8 at
Note O as of September 30, 2008 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 204 Bcf and 49,899
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 versus the reserves disclosed in
Item 8 at Note O, which are reported on a net revenue
interest basis.
20
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
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
United States
|
|
|
|
|
|
|
|
|
|
|
|
|
Gulf Coast Region
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Sales Price per Mcf of Gas
|
|
$
|
10.03
|
|
|
$
|
6.58
|
|
|
$
|
8.01
|
|
Average Sales Price per Barrel of Oil
|
|
$
|
107.27
|
|
|
$
|
63.04
|
|
|
$
|
64.10
|
|
Average Sales Price per Mcf of Gas (after hedging)
|
|
$
|
9.49
|
|
|
$
|
6.87
|
|
|
$
|
5.89
|
|
Average Sales Price per Barrel of Oil (after hedging)
|
|
$
|
98.56
|
|
|
$
|
64.09
|
|
|
$
|
47.46
|
|
Average Production (Lifting) Cost per Mcf Equivalent of Gas and
Oil Produced
|
|
$
|
1.63
|
|
|
$
|
1.08
|
|
|
$
|
0.86
|
|
Average Production per Day (in MMcf Equivalent of Gas and Oil
Produced)
|
|
|
38
|
|
|
|
40
|
|
|
|
36
|
|
West Coast Region
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Sales Price per Mcf of Gas
|
|
$
|
8.71
|
|
|
$
|
6.54
|
|
|
$
|
7.93
|
|
Average Sales Price per Barrel of Oil
|
|
$
|
98.17
|
|
|
$
|
56.86
|
|
|
$
|
56.80
|
|
Average Sales Price per Mcf of Gas (after hedging)
|
|
$
|
8.22
|
|
|
$
|
6.82
|
|
|
$
|
7.19
|
|
Average Sales Price per Barrel of Oil (after hedging)
|
|
$
|
77.64
|
|
|
$
|
47.43
|
|
|
$
|
37.69
|
|
Average Production (Lifting) Cost per Mcf Equivalent of Gas and
Oil Produced
|
|
$
|
2.01
|
|
|
$
|
1.54
|
|
|
$
|
1.35
|
|
Average Production per Day (in MMcf Equivalent of Gas and Oil
Produced)
|
|
|
51
|
|
|
|
50
|
|
|
|
53
|
|
Appalachian Region
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Sales Price per Mcf of Gas
|
|
$
|
9.73
|
|
|
$
|
7.48
|
|
|
$
|
9.53
|
|
Average Sales Price per Barrel of Oil
|
|
$
|
97.40
|
|
|
$
|
62.26
|
|
|
$
|
65.28
|
|
Average Sales Price per Mcf of Gas (after hedging)
|
|
$
|
8.85
|
|
|
$
|
8.25
|
|
|
$
|
8.90
|
|
Average Sales Price per Barrel of Oil (after hedging)
|
|
$
|
97.40
|
|
|
$
|
62.26
|
|
|
$
|
65.28
|
|
Average Production (Lifting) Cost per Mcf Equivalent of Gas and
Oil Produced
|
|
$
|
0.77
|
|
|
$
|
0.69
|
|
|
$
|
0.69
|
|
Average Production per Day (in MMcf Equivalent of Gas and Oil
Produced)
|
|
|
22
|
|
|
|
17
|
|
|
|
15
|
|
Total United States
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Sales Price per Mcf of Gas
|
|
$
|
9.70
|
|
|
$
|
6.82
|
|
|
$
|
8.42
|
|
Average Sales Price per Barrel of Oil
|
|
$
|
99.64
|
|
|
$
|
58.43
|
|
|
$
|
58.47
|
|
Average Sales Price per Mcf of Gas (after hedging)
|
|
$
|
9.05
|
|
|
$
|
7.25
|
|
|
$
|
7.02
|
|
Average Sales Price per Barrel of Oil (after hedging)
|
|
$
|
81.75
|
|
|
$
|
51.68
|
|
|
$
|
40.26
|
|
Average Production (Lifting) Cost per Mcf Equivalent of Gas and
Oil Produced
|
|
$
|
1.64
|
|
|
$
|
1.23
|
|
|
$
|
1.09
|
|
Average Production per Day (in MMcf Equivalent of Gas and Oil
Produced)
|
|
|
111
|
|
|
|
108
|
|
|
|
104
|
|
21
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For The Year Ended September 30
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
Canada Discontinued Operations
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Sales Price per Mcf of Gas
|
|
$
|
|
|
|
$
|
6.09
|
|
|
$
|
7.14
|
|
Average Sales Price per Barrel of Oil
|
|
$
|
|
|
|
$
|
50.06
|
|
|
$
|
51.40
|
|
Average Sales Price per Mcf of Gas (after hedging)
|
|
$
|
|
|
|
$
|
6.17
|
|
|
$
|
7.47
|
|
Average Sales Price per Barrel of Oil (after hedging)
|
|
$
|
|
|
|
$
|
50.06
|
|
|
$
|
51.40
|
|
Average Production (Lifting) Cost per Mcf Equivalent of Gas and
Oil Produced
|
|
$
|
|
|
|
$
|
1.94
|
|
|
$
|
1.57
|
|
Average Production per Day (in MMcf Equivalent of Gas and Oil
Produced)
|
|
|
|
|
|
|
21
|
|
|
|
26
|
|
Total Company
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Sales Price per Mcf of Gas
|
|
$
|
9.70
|
|
|
$
|
6.64
|
|
|
$
|
8.04
|
|
Average Sales Price per Barrel of Oil
|
|
$
|
99.64
|
|
|
$
|
57.93
|
|
|
$
|
57.94
|
|
Average Sales Price per Mcf of Gas (after hedging)
|
|
$
|
9.05
|
|
|
$
|
6.98
|
|
|
$
|
7.15
|
|
Average Sales Price per Barrel of Oil (after hedging)
|
|
$
|
81.75
|
|
|
$
|
51.58
|
|
|
$
|
41.10
|
|
Average Production (Lifting) Cost per Mcf Equivalent of Gas and
Oil Produced
|
|
$
|
1.64
|
|
|
$
|
1.35
|
|
|
$
|
1.18
|
|
Average Production per Day (in MMcf Equivalent of Gas and Oil
Produced)
|
|
|
111
|
|
|
|
129
|
|
|
|
130
|
|
Productive
Wells
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gulf Coast
|
|
|
West Coast
|
|
|
Appalachian
|
|
|
|
|
|
|
|
|
|
Region
|
|
|
Region
|
|
|
Region
|
|
|
Total Company
|
|
At September 30, 2008
|
|
Gas
|
|
|
Oil
|
|
|
Gas
|
|
|
Oil
|
|
|
Gas
|
|
|
Oil
|
|
|
Gas
|
|
|
Oil
|
|
|
Productive Wells Gross
|
|
|
25
|
|
|
|
42
|
|
|
|
|
|
|
|
1,437
|
|
|
|
2,641
|
|
|
|
6
|
|
|
|
2,666
|
|
|
|
1,485
|
|
Productive Wells Net
|
|
|
14
|
|
|
|
14
|
|
|
|
|
|
|
|
1,426
|
|
|
|
2,570
|
|
|
|
5
|
|
|
|
2,584
|
|
|
|
1,445
|
|
Developed
and Undeveloped Acreage
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gulf
|
|
|
West
|
|
|
|
|
|
|
|
|
|
Coast
|
|
|
Coast
|
|
|
Appalachian
|
|
|
Total
|
|
At September 30, 2008
|
|
Region
|
|
|
Region
|
|
|
Region
|
|
|
Company
|
|
|
Developed Acreage
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross
|
|
|
113,934
|
|
|
|
11,360
|
|
|
|
531,743
|
|
|
|
657,037
|
|
Net
|
|
|
80,852
|
|
|
|
10,945
|
|
|
|
501,411
|
|
|
|
593,208
|
|
Undeveloped Acreage
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross
|
|
|
142,118
|
|
|
|
|
|
|
|
458,894
|
|
|
|
601,012
|
|
Net
|
|
|
102,831
|
|
|
|
|
|
|
|
438,040
|
|
|
|
540,871
|
|
As of September 30, 2008, the aggregate amount of gross
undeveloped acreage expiring in the next three years and
thereafter are as follows: 38,811 acres in 2009
(23,289 net acres), 23,302 acres in 2010
(11,754 net acres), 82,165 acres in 2011
(67,472 net acres), and 456,734 acres thereafter
(438,356 net acres).
22
Drilling
Activity
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive
|
|
|
Dry
|
|
For the Year Ended September 30
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
United States
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gulf Coast Region
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Wells Completed
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploratory
|
|
|
1.14
|
|
|
|
1.31
|
|
|
|
2.94
|
|
|
|
0.37
|
|
|
|
1.42
|
|
|
|
0.85
|
|
Development
|
|
|
|
|
|
|
1.00
|
|
|
|
0.78
|
|
|
|
|
|
|
|
0.67
|
|
|
|
|
|
West Coast Region
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Wells Completed
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploratory
|
|
|
1.00
|
|
|
|
0.50
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Development
|
|
|
62.00
|
|
|
|
58.99
|
|
|
|
92.98
|
|
|
|
1.00
|
|
|
|
2.00
|
|
|
|
1.00
|
|
Appalachian Region
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Wells Completed
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploratory
|
|
|
8.00
|
|
|
|
8.10
|
|
|
|
3.88
|
|
|
|
1.00
|
|
|
|
|
|
|
|
|
|
Development
|
|
|
186.00
|
|
|
|
184.00
|
|
|
|
140.58
|
|
|
|
|
|
|
|
2.00
|
|
|
|
1.75
|
|
Total United States
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Wells Completed
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploratory
|
|
|
10.14
|
|
|
|
9.91
|
|
|
|
6.82
|
|
|
|
1.37
|
|
|
|
1.42
|
|
|
|
0.85
|
|
Development
|
|
|
248.00
|
|
|
|
243.99
|
|
|
|
234.34
|
|
|
|
1.00
|
|
|
|
4.67
|
|
|
|
2.75
|
|
Canada Discontinued Operations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Wells Completed
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploratory
|
|
|
|
|
|
|
6.38
|
|
|
|
12.60
|
|
|
|
|
|
|
|
|
|
|
|
1.35
|
|
Development
|
|
|
|
|
|
|
1.80
|
|
|
|
2.50
|
|
|
|
|
|
|
|
|
|
|
|
1.00
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Wells Completed
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploratory
|
|
|
10.14
|
|
|
|
16.29
|
|
|
|
19.42
|
|
|
|
1.37
|
|
|
|
1.42
|
|
|
|
2.20
|
|
Development
|
|
|
248.00
|
|
|
|
245.79
|
|
|
|
236.84
|
|
|
|
1.00
|
|
|
|
4.67
|
|
|
|
3.75
|
|
Present
Activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gulf
|
|
|
West
|
|
|
|
|
|
|
|
|
|
Coast
|
|
|
Coast
|
|
|
Appalachian
|
|
|
Total
|
|
At September 30, 2008
|
|
Region
|
|
|
Region
|
|
|
Region
|
|
|
Company
|
|
|
Wells in Process of Drilling(1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross
|
|
|
2.00
|
|
|
|
1.00
|
|
|
|
148.00
|
|
|
|
151.00
|
|
Net
|
|
|
0.59
|
|
|
|
1.00
|
|
|
|
146.00
|
|
|
|
147.59
|
|
|
|
|
(1) |
|
Includes wells awaiting completion. |
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 these matters, 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
23
resolved, they are not expected to change materially the
Companys present liquidity position, nor are they expected
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, 2008.
PART II
|
|
Item 5
|
Market
for the Registrants Common Equity, Related Stockholder
Matters and Issuer Purchases of Equity Securities
|
Information regarding the market for the Companys common
equity and related stockholder matters appears under
Item 12 at Security Ownership of Certain Beneficial Owners
and Management and Related Stockholder Matters, Item 8 at
Note E Capitalization and Short-Term Borrowings
and Note N Market for Common Stock and Related
Shareholder Matters (unaudited).
On July 2, 2008, the Company issued a total of 2,400
unregistered shares of Company common stock to the eight
non-employee directors of the Company then serving on the Board
of Directors of the Company and receiving compensation under the
Companys Retainer Policy for Non-Employee 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, 2008. 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, 2008
|
|
|
6,404
|
|
|
$
|
54.02
|
|
|
|
|
|
|
|
1,332,725
|
|
Aug. 1-31, 2008
|
|
|
544,982
|
|
|
$
|
46.72
|
|
|
|
537,165
|
|
|
|
795,560
|
|
Sept. 1-30, 2008
|
|
|
1,832,488
|
|
|
$
|
45.08
|
|
|
|
1,824,541
|
|
|
|
6,971,019
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
2,383,874
|
|
|
$
|
45.48
|
|
|
|
2,361,706
|
|
|
|
6,971,019
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) |
|
Represents (i) shares of common stock of the Company
purchased on the open market with Company matching
contributions for the accounts of participants in the
Companys 401(k) plans, (ii) shares of common stock of
the Company tendered to the Company by holders of stock options
or shares of restricted stock for the payment of option exercise
prices or applicable withholding taxes, and (iii) shares of
common stock of the Company purchased on the open market
pursuant to the Companys publicly announced share
repurchase program. Shares purchased other than through a
publicly announced share repurchase program totaled 6,404 in
July 2008, 7,817 in August 2008 and 7,947 in September 2008 (a
three-month total of 22,168). All of those shares were purchased
for the Companys 401(k) plans. |
|
(b) |
|
In December 2005, the Companys Board of Directors
authorized the repurchase of up to eight million shares of the
Companys common stock. The Company completed the
repurchase of the eight million shares during 2008. In September
2008, the Companys Board of Directors authorized the
repurchase of an additional eight million shares of the
Companys common stock. The Company had, however, stopped
repurchasing shares after September 17, 2008 in light of
the unsettled nature of the credit markets. However, such
repurchases may be made in the future if conditions improve.
Such repurchases would be made in the open market or through
private transactions. |
24
|
|
Item 6
|
Selected
Financial Data
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended September 30
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
|
(Thousands)
|
|
|
Summary of Operations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Revenues
|
|
$
|
2,400,361
|
|
|
$
|
2,039,566
|
|
|
$
|
2,239,675
|
|
|
$
|
1,860,774
|
|
|
$
|
1,867,875
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchased Gas
|
|
|
1,235,157
|
|
|
|
1,018,081
|
|
|
|
1,267,562
|
|
|
|
959,827
|
|
|
|
949,452
|
|
Operation and Maintenance
|
|
|
432,871
|
|
|
|
396,408
|
|
|
|
395,289
|
|
|
|
388,094
|
|
|
|
374,010
|
|
Property, Franchise and Other Taxes
|
|
|
75,585
|
|
|
|
70,660
|
|
|
|
69,202
|
|
|
|
68,164
|
|
|
|
68,378
|
|
Depreciation, Depletion and Amortization
|
|
|
170,623
|
|
|
|
157,919
|
|
|
|
151,999
|
|
|
|
156,502
|
|
|
|
159,184
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,914,236
|
|
|
|
1,643,068
|
|
|
|
1,884,052
|
|
|
|
1,572,587
|
|
|
|
1,551,024
|
|
Loss on Sale of Timber Properties
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,252
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Income
|
|
|
486,125
|
|
|
|
396,498
|
|
|
|
355,623
|
|
|
|
288,187
|
|
|
|
315,599
|
|
Other Income (Expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from Unconsolidated Subsidiaries
|
|
|
6,303
|
|
|
|
4,979
|
|
|
|
3,583
|
|
|
|
3,362
|
|
|
|
805
|
|
Impairment of Investment in Partnership
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(4,158
|
)
|
|
|
|
|
Interest Income
|
|
|
10,815
|
|
|
|
1,550
|
|
|
|
9,409
|
|
|
|
6,236
|
|
|
|
1,771
|
|
Other Income
|
|
|
7,376
|
|
|
|
4,936
|
|
|
|
2,825
|
|
|
|
12,744
|
|
|
|
2,908
|
|
Interest Expense on Long-Term Debt
|
|
|
(70,099
|
)
|
|
|
(68,446
|
)
|
|
|
(72,629
|
)
|
|
|
(73,244
|
)
|
|
|
(82,989
|
)
|
Other Interest Expense
|
|
|
(3,870
|
)
|
|
|
(6,029
|
)
|
|
|
(5,952
|
)
|
|
|
(9,069
|
)
|
|
|
(6,354
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from Continuing Operations Before Income Taxes
|
|
|
436,650
|
|
|
|
333,488
|
|
|
|
292,859
|
|
|
|
224,058
|
|
|
|
231,740
|
|
Income Tax Expense
|
|
|
167,922
|
|
|
|
131,813
|
|
|
|
108,245
|
|
|
|
85,621
|
|
|
|
89,820
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from Continuing Operations
|
|
|
268,728
|
|
|
|
201,675
|
|
|
|
184,614
|
|
|
|
138,437
|
|
|
|
141,920
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Discontinued Operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (Loss) from Operations, Net of Tax
|
|
|
|
|
|
|
15,479
|
|
|
|
(46,523
|
)
|
|
|
25,277
|
|
|
|
24,666
|
|
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
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income Available for Common Stock
|
|
$
|
268,728
|
|
|
$
|
337,455
|
|
|
$
|
138,091
|
|
|
$
|
189,488
|
|
|
$
|
166,586
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
25
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended September 30
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
|
(Thousands)
|
|
|
Per Common Share Data
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic Earnings from Continuing Operations per Common Share
|
|
$
|
3.27
|
|
|
$
|
2.43
|
|
|
$
|
2.20
|
|
|
$
|
1.66
|
|
|
$
|
1.73
|
|
Diluted Earnings from Continuing Operations per Common Share
|
|
$
|
3.18
|
|
|
$
|
2.37
|
|
|
$
|
2.15
|
|
|
$
|
1.63
|
|
|
$
|
1.71
|
|
Basic Earnings per Common Share(1)
|
|
$
|
3.27
|
|
|
$
|
4.06
|
|
|
$
|
1.64
|
|
|
$
|
2.27
|
|
|
$
|
2.03
|
|
Diluted Earnings per Common Share(1)
|
|
$
|
3.18
|
|
|
$
|
3.96
|
|
|
$
|
1.61
|
|
|
$
|
2.23
|
|
|
$
|
2.01
|
|
Dividends Declared
|
|
$
|
1.27
|
|
|
$
|
1.22
|
|
|
$
|
1.18
|
|
|
$
|
1.14
|
|
|
$
|
1.10
|
|
Dividends Paid
|
|
$
|
1.26
|
|
|
$
|
1.21
|
|
|
$
|
1.17
|
|
|
$
|
1.13
|
|
|
$
|
1.09
|
|
Dividend Rate at Year-End
|
|
$
|
1.30
|
|
|
$
|
1.24
|
|
|
$
|
1.20
|
|
|
$
|
1.16
|
|
|
$
|
1.12
|
|
At September 30:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Number of Registered Shareholders
|
|
|
16,544
|
|
|
|
16,989
|
|
|
|
17,767
|
|
|
|
18,369
|
|
|
|
19,063
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Property, Plant and Equipment
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Utility
|
|
$
|
1,125,859
|
|
|
$
|
1,099,280
|
|
|
$
|
1,084,080
|
|
|
$
|
1,064,588
|
|
|
$
|
1,048,428
|
|
Pipeline and Storage
|
|
|
826,528
|
|
|
|
681,940
|
|
|
|
674,175
|
|
|
|
680,574
|
|
|
|
696,487
|
|
Exploration and Production(2)
|
|
|
1,095,960
|
|
|
|
982,698
|
|
|
|
1,002,265
|
|
|
|
974,806
|
|
|
|
923,730
|
|
Energy Marketing
|
|
|
98
|
|
|
|
102
|
|
|
|
59
|
|
|
|
97
|
|
|
|
80
|
|
Timber
|
|
|
86,392
|
|
|
|
89,902
|
|
|
|
90,939
|
|
|
|
94,826
|
|
|
|
82,838
|
|
All Other
|
|
|
11,946
|
|
|
|
16,735
|
|
|
|
17,394
|
|
|
|
18,098
|
|
|
|
21,172
|
|
Corporate(3)
|
|
|
7,317
|
|
|
|
7,748
|
|
|
|
8,814
|
|
|
|
6,311
|
|
|
|
234,029
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Net Plant
|
|
$
|
3,154,100
|
|
|
$
|
2,878,405
|
|
|
$
|
2,877,726
|
|
|
$
|
2,839,300
|
|
|
$
|
3,006,764
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Assets
|
|
$
|
4,130,187
|
|
|
$
|
3,888,412
|
|
|
$
|
3,763,748
|
|
|
$
|
3,749,753
|
|
|
$
|
3,738,103
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capitalization
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive Shareholders Equity
|
|
$
|
1,603,599
|
|
|
$
|
1,630,119
|
|
|
$
|
1,443,562
|
|
|
$
|
1,229,583
|
|
|
$
|
1,253,701
|
|
Long-Term Debt, Net of Current Portion
|
|
|
999,000
|
|
|
|
799,000
|
|
|
|
1,095,675
|
|
|
|
1,119,012
|
|
|
|
1,133,317
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Capitalization
|
|
$
|
2,602,599
|
|
|
$
|
2,429,119
|
|
|
$
|
2,539,237
|
|
|
$
|
2,348,595
|
|
|
$
|
2,387,018
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Includes discontinued operations. |
|
(2) |
|
Includes net plant of SECI discontinued operations as follows:
$0 for 2008 and 2007, $88,023 for 2006, $170,929 for 2005, and
$142,860 for 2004. |
|
(3) |
|
Includes net plant of the former international segment as
follows: $29 for 2008, $38 for 2007, $27 for 2006, $20 for 2005,
and $227,905 for 2004. |
26
|
|
Item 7
|
Managements
Discussion and Analysis of Financial Condition and Results of
Operations
|
OVERVIEW
The Company is a diversified energy company and reports
financial results for five 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) 2008 and 2009 funding for the
Companys pension and other post-retirement benefits,
(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.
Overall, 2008 was a strong year for the Company. Income from
continuing operations in 2008 benefited primarily from higher
crude oil and natural gas prices in the Exploration and
Production segment combined with an overall increase in natural
gas production, primarily in the Appalachian region. These
factors led to a $67.1 million increase in income from
continuing operations compared to the prior year. In 2007, the
Company recorded $135.8 million of income from discontinued
operations, consisting of a $120.3 million gain, net of
tax, on the sale of SECI and $15.5 million of income from
SECI prior to its sale in August 2007. SECI, Senecas
wholly owned subsidiary, 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. Combining both income from continuing operations and
discontinued operations, the Companys net income available
for common stock decreased $68.7 million in 2008 compared
to the prior year. The Companys earnings are discussed
further in the Results of Operations section that follows.
The Company spent $414.5 million on capital expenditures
during 2008, with approximately 46 percent being spent in
the Exploration and Production segment and 40 percent being
spent in the Pipeline and Storage segment. Management continues
to believe that these segments provide the best earnings growth
opportunities for shareholders. In the Exploration and
Production segment, the Companys principal focus continues
to be the development of its nearly one million acres in the
Appalachian region along with continued exploration and
development in the Gulf and West Coast regions. In the Pipeline
and Storage segment, the majority of the expenditures were for
construction costs of the Empire Connector project. The Empire
Connector is anticipated to be ready to commence service in
December 2008 on or before the in-service date of the Millennium
Pipeline. The Companys capital expenditure program is
discussed further in the Capital Resources and Liquidity section
that follows.
Despite the positives mentioned above, the economy of the United
States has become constrained by significant volatility and
turmoil in the capital and credit markets. The governments
Troubled Asset Relief Program and decreases in federal funds
rates have not been enough to stem the reluctance on the part of
lenders to extend credit to businesses. In the current period
these events have not had a material impact on the Company,
although further disruption in the markets and tightening of
credit availability could negatively impact future periods. At
September 30, 2008, the Company had a strong balance sheet
and liquidity. The Company had no outstanding short-term notes
payable to banks or commercial paper at that date. However,
since that date, the Company has borrowed short-term funds under
its credit lines and through the commercial paper market to fund
working capital needs. The Company maintains a number of
individual uncommitted or
27
discretionary lines of credit with certain financial
institutions for general corporate purposes. These credit lines,
which aggregate to $420.0 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.
During 2006, the Company began repurchasing outstanding shares
of common stock under a share repurchase program authorized by
the Companys Board of Directors. The program authorized
the Company to repurchase up to an aggregate amount of eight
million shares. This threshold was reached during 2008 for a
total program cost of $324.2 million (of which
4,165,122 shares were repurchased during the year ended
September 30, 2008 for $191.0 million). In September
2008, the Companys Board of Directors authorized the
repurchase of an additional eight million shares. Under this new
authorization, the Company repurchased 1,028,981 shares for
$46.0 million through September 17, 2008. The Company
stopped repurchasing shares after September 17, 2008 in
light of the unsettled nature of the credit markets. However,
such repurchases may be made in the future if conditions improve.
During 2009, the Company expects to finance its capital
expenditure program, dividends, and operating expenses
(including Retirement Plan and other post-retirement benefit
funding) with cash from operations, proceeds from the sale of
assets,
and/or
short-term borrowings. As oil and gas commodity prices have
decreased significantly from their highs during 2008, it is
possible that the Company may have to rely more heavily on
short-term borrowings to meet its cash needs. It is also
possible that the Company may choose to reduce its 2009 capital
expenditures.
With the turmoil in the credit markets has come a significant
decline in the stock markets. This has had a significant impact
on the asset values of the Companys Retirement Plan and
its VEBA trusts and 401(h) accounts. The Company anticipates
funding $15.0 million to $20.0 million to the
Retirement Plan and $25.0 million to $30.0 million to
its VEBA trusts and 401(h) accounts during 2009. However, under
the current funding requirements of the Pension Protection Act,
should market conditions at September 30, 2008 remain
unchanged, contributions in future years could increase
significantly. This issue is discussed further in the Other
Matters section that follows.
CRITICAL
ACCOUNTING ESTIMATES
The Company has prepared its consolidated financial statements
in conformity with GAAP. The preparation of these financial
statements requires management to make estimates and assumptions
that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of
the financial statements and the reported amounts of revenues
and expenses during the reporting period. Actual results could
differ from those estimates. In the event estimates or
assumptions prove to be different from actual results,
adjustments are made in subsequent periods to reflect more
current information. The following is a summary of the
Companys most critical accounting estimates, which are
defined as those estimates whereby judgments or uncertainties
could affect the application of accounting policies and
materially different amounts could be reported under different
conditions or using different assumptions. For a complete
discussion of the Companys significant accounting
policies, refer to Item 8 at Note A
Summary of Significant Accounting Policies.
Oil and Gas Exploration and Development
Costs. In the Companys Exploration and
Production segment, oil and gas property acquisition,
exploration and development costs are capitalized under the full
cost method of accounting. Under this accounting methodology,
all costs associated with property acquisition, exploration and
development activities are capitalized, including internal costs
directly identified with acquisition, exploration and
development activities. The internal costs that are capitalized
do not include any costs related to production, general
corporate overhead, or similar activities. The Company 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.
28
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 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 to or
subtractions from 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 included in the loss from
discontinued operations for 2006 due to the sale of SECI during
2007. At September 30, 2008, the ceiling exceeded the book
value of the Companys oil and gas properties by
approximately $500 million. Declines in commodity prices
since that date have reduced the ceiling. Using more up to date
pricing of $6 per Mcf for natural gas and $60 per barrel for
crude oil, the ceiling at September 30, 2008 would have
exceeded the book value of the Companys oil and gas
properties by approximately $80 million.
It is difficult to predict what factors could lead to future
impairments under the SECs full cost ceiling test. As
discussed above, fluctuations in or subtractions from proved
reserves and significant fluctuations in oil and gas prices have
an impact on the amount of the ceiling at any point in time.
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
29
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.
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. The Company used a
model to substantiate the values reported by the counterparties.
At September 30, 2008, the Company established a credit
reserve of $0.6 million against the asset recorded on its
books for non-exchange traded derivative financial instruments.
The credit reserve was determined by applying default
probabilities to the anticipated cash flows that the Company is
expecting from its counterparties. Refer to the Market
Risk Sensitive Instruments section below for further
discussion of the Companys derivative financial
instruments.
Pension and Other Post-Retirement
Benefits. The amounts reported in the
Companys financial statements related to its pension and
other post-retirement benefits are determined on an actuarial
basis, which uses many assumptions in the calculation of such
amounts. These assumptions include the discount rate, the
expected return on plan assets, the rate of compensation
increase and, for other post-retirement benefits, the expected
30
annual rate of increase in per capita cost of covered medical
and prescription benefits. The Company 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, including deviations between actual versus expected
return on plan assets, 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 97% and 93%, 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, 2008 and 2007.
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 other
post-retirement benefits and could impact the Companys
equity. For example, the discount rate was changed from 6.25% in
2007 to 6.75% in 2008. The change in the discount rate from 2007
to 2008 reduced the Retirement Plan projected benefit obligation
by $38.6 million and the accumulated post-retirement
benefit obligation by $26.3 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 obligation and the accumulated
post-retirement benefit obligation. For 2008, actual versus
expected return on plan assets resulted in a decrease to the
funded status of the Retirement Plan ($94.2 million) and
the VEBA trusts and 401(h) accounts ($77.2 million). The
actual versus expected benefit payments for 2008 caused an
increase of $0.1 million to the projected benefit
obligation and a decrease of $3.6 million to the
accumulated post-retirement benefit obligation, respectively. In
calculating the projected benefit obligation for the Retirement
Plan and the accumulated post-retirement obligation, the actuary
takes into account the average remaining service life of active
participants. The average remaining service life of active
participants is 11 years for the Retirement Plan and
13 years for those eligible for other post-retirement
benefits. 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.
31
RESULTS
OF OPERATIONS
EARNINGS
2008
Compared with 2007
The Companys earnings were $268.7 million in 2008
compared with earnings of $337.5 million in 2007. As
previously discussed, the Company 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
$268.7 million in 2008 compared with $201.7 million in
2007. The Companys earnings from discontinued operations
were $135.8 million in 2007. The increase in earnings from
continuing operations is primarily the result of higher earnings
in the Exploration and Production and Utility segments and the
All Other category, slightly offset by lower earnings in the
Corporate category and the Timber, Pipeline and Storage, and
Energy Marketing segments, as shown in the table below. 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 2008 and 2007,
including:
2008
Events
|
|
|
|
|
A $0.6 million gain in the All Other category associated
with the sale of Horizon Powers gas-powered turbine;
|
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.
|
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. Earnings
from continuing operations and discontinued operations were
impacted by several events discussed above and the following
2006 events:
32
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.
|
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
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(Thousands)
|
|
|
Utility
|
|
$
|
61,472
|
|
|
$
|
50,886
|
|
|
$
|
49,815
|
|
Pipeline and Storage
|
|
|
54,148
|
|
|
|
56,386
|
|
|
|
55,633
|
|
Exploration and Production
|
|
|
146,612
|
|
|
|
74,889
|
|
|
|
67,494
|
|
Energy Marketing
|
|
|
5,889
|
|
|
|
7,663
|
|
|
|
5,798
|
|
Timber
|
|
|
107
|
|
|
|
3,728
|
|
|
|
5,704
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Reported Segments
|
|
|
268,228
|
|
|
|
193,552
|
|
|
|
184,444
|
|
All Other
|
|
|
5,672
|
|
|
|
2,564
|
|
|
|
359
|
|
Corporate
|
|
|
(5,172
|
)
|
|
|
5,559
|
|
|
|
(189
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Earnings from Continuing Operations
|
|
|
268,728
|
|
|
|
201,675
|
|
|
|
184,614
|
|
Earnings (Loss) from Discontinued Operations
|
|
|
|
|
|
|
135,780
|
|
|
|
(46,523
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Consolidated
|
|
$
|
268,728
|
|
|
$
|
337,455
|
|
|
$
|
138,091
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
UTILITY
Revenues
Utility
Operating Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended September 30
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(Thousands)
|
|
|
Retail Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
Residential
|
|
$
|
876,677
|
|
|
$
|
848,693
|
|
|
$
|
993,928
|
|
Commercial
|
|
|
135,361
|
|
|
|
136,863
|
|
|
|
166,779
|
|
Industrial
|
|
|
7,419
|
|
|
|
8,271
|
|
|
|
13,484
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,019,457
|
|
|
|
993,827
|
|
|
|
1,174,191
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Off-System Sales
|
|
|
58,225
|
|
|
|
9,751
|
|
|
|
|
|
Transportation
|
|
|
113,901
|
|
|
|
102,534
|
|
|
|
92,569
|
|
Other
|
|
|
18,686
|
|
|
|
14,612
|
|
|
|
14,003
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
1,210,269
|
|
|
$
|
1,120,724
|
|
|
$
|
1,280,763
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
33
Utility
Throughput million cubic feet (MMcf)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended September 30
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
Retail Sales:
|
|
|
|
|
|
|
|
|
|
|
|
|
Residential
|
|
|
57,463
|
|
|
|
60,236
|
|
|
|
59,443
|
|
Commercial
|
|
|
9,769
|
|
|
|
10,713
|
|
|
|
10,681
|
|
Industrial
|
|
|
552
|
|
|
|
727
|
|
|
|
985
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
67,784
|
|
|
|
71,676
|
|
|
|
71,109
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Off-System Sales
|
|
|
5,686
|
|
|
|
1,355
|
|
|
|
|
|
Transportation
|
|
|
64,267
|
|
|
|
62,240
|
|
|
|
57,950
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
137,737
|
|
|
|
135,271
|
|
|
|
129,059
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Degree
Days
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Percent (Warmer)
|
|
|
|
|
|
|
|
|
|
|
|
|
Colder Than
|
|
Year Ended September 30
|
|
|
|
|
Normal
|
|
|
Actual
|
|
|
Normal
|
|
|
Prior Year
|
|
|
2008:
|
|
|
Buffalo
|
|
|
|
6,729
|
|
|
|
6,277
|
|
|
|
(6.7
|
)%
|
|
|
0.1
|
%
|
|
|
|
Erie
|
|
|
|
6,277
|
|
|
|
5,779
|
|
|
|
(7.9
|
)%
|
|
|
(3.8
|
)%
|
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
|
)%
|
2008
Compared with 2007
Operating revenues for the Utility segment increased
$89.5 million in 2008 compared with 2007. This increase
largely resulted from a $48.5 million increase in
off-system sales revenue (see discussion below), a
$25.6 million increase in retail gas sales revenues, an
$11.3 million increase in transportation revenues, and a
$4.1 million increase in other operating revenues.
The increase in retail gas sales revenues for the Utility
segment was largely a function of the recovery of higher gas
costs (subject to certain timing variations, 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. This change was
also affected by a base rate increase in the Pennsylvania
jurisdiction (effective January 2007) that increased
operating revenues by $4.0 million for 2008. The increase
is included within both retail and transportation revenues in
the table above.
In the New York jurisdiction, the NYPSC issued an order
providing for an annual rate increase of $1.8 million
beginning December 28, 2007. As part of this rate order, a
rate design change was adopted that shifts a greater amount of
cost recovery into the minimum bill amount, thus spreading the
recovery of such costs more evenly throughout the year. This
rate design change resulted in lower retail and transportation
revenues (exclusive of the impact of higher gas costs) during
the winter months compared to the prior year and higher retail
and transportation revenues in the spring and summer months
compared to the prior year. On a cumulative basis for 2008, the
impact of this rate order has been to lower operating revenues
by $1.4 million. It is expected that there will be an
increase in retail and transportation revenue in the first
quarter of 2009 compared to the prior year as a result of the
rate design change. The increase in transportation revenues was
also due to a 2.0 Bcf increase in transportation
throughput, largely the result of the migration of customers
from retail sales to transportation service.
As reported in 2006, on November 17, 2006 the
U.S. Court of Appeals vacated and remanded the FERCs
Order No. 2004 regarding affiliate standards of conduct,
with respect to natural gas pipelines. The Courts
34
decision became effective on January 5, 2007, and on
January 9, 2007, the FERC issued Order No. 690, its
Interim Rule, designed to respond to the Courts decision.
In Order No. 690, as clarified by the 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 segment
to engage in certain off-system sales without triggering the
adverse consequences that would otherwise arise under the Order
No. 2004 standards of conduct. As a result, the Utility
segment resumed engaging in off-system sales on non-affiliated
pipelines as of May 2007, resulting in total off-system sales
revenues of $58.2 million and $9.8 million for 2008
and 2007, respectively. 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 2008
and 2007.
The increase in other operating revenues of $4.1 million is
largely related to amounts recorded pursuant to rate settlements
approved by the NYPSC. In accordance with these settlements,
Distribution Corporation was allowed to utilize certain refunds
from upstream pipeline companies and certain other credits
(referred to as the cost mitigation reserve) to
offset certain specific expense items. In 2008, Distribution
Corporation utilized $5.6 million of the cost mitigation
reserve, which increased other operating revenues, to recover
previous undercollections of pension expenses. The impact of
that increase in other operating revenues was offset by an equal
amount of operation and maintenance expense (thus there is no
earnings impact).
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 partially offset by a
$10.0 million increase in transportation revenues and a
$9.8 million increase in off-system sales revenues.
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.
The increase in off-system sales revenue is due to the
resumption of off-system sales in May 2007 pursuant to FERC
authorization, as discussed above.
Purchased
Gas
The cost of purchased gas is the Companys single largest
operating expense. Annual variations in purchased gas costs are
attributed directly to changes in gas sales volumes, the price
of gas purchased and the operation of purchased gas adjustment
clauses.
Currently, Distribution Corporation has contracted for long-term
firm transportation capacity with Supply Corporation and six
other upstream pipeline companies, for long-term gas supplies
with a combination of producers and marketers, and for storage
service with Supply Corporation and three nonaffiliated
companies. In addition, Distribution Corporation satisfies a
portion of its gas requirements through spot market purchases.
Changes in wellhead prices have a direct impact on the cost of
purchased gas. Distribution Corporations average cost of
purchased gas, including the cost of transportation and storage,
was $11.23 per Mcf in 2008, an increase of 12% from the average
cost of $10.04 per Mcf in 2007. The average cost of purchased
gas in 2007 was 17% lower than the average cost of $12.07 per
Mcf in 2006. Additional discussion of the Utility segments
gas purchases appears under the heading Sources and
Availability of Raw Materials in Item 1.
35
Earnings
2008
Compared with 2007
The Utility segments earnings in 2008 were
$61.5 million, an increase of $10.6 million when
compared with earnings of $50.9 million in 2007.
In the New York jurisdiction, earnings increased by
$6.9 million. This was primarily due to a $3.6 million
overall decrease in operating expenses (mostly other
post-retirement benefits and bad debt expense), higher non-cash
interest income on a pension-related regulatory asset
($2.6 million), a decrease in property, franchise, and
other taxes ($0.9 million), a decrease in depreciation
expense ($0.8 million), lower income tax expense
($0.7 million), lower interest expense ($0.2 million),
and increased usage per account ($0.5 million). The impact
of these items more than offset lower base rates due to the rate
design change described above ($0.9 million), and routine
regulatory adjustments that reduced earnings by
$1.8 million.
In the Pennsylvania jurisdiction, earnings increased by
$3.7 million. This was primarily due to a base rate
increase ($2.6 million) that became effective January 2007,
an increase in normalized usage ($1.3 million), a decrease
in bad debt expense ($1.1 million), and a decrease in
property, franchise, and other taxes ($0.3 million). Warmer
weather ($1.6 million) partially offset these increases.
The impact of weather on the Utility segments New York
rate jurisdiction is tempered by a weather normalization clause
(WNC). The WNC, which covers the eight-month period from October
through May, has had a stabilizing effect on earnings for the
New York rate jurisdiction. In addition, in periods of colder
than normal weather, the WNC benefits the Utility segments
New York customers. In 2008 and 2007, the WNC preserved earnings
of approximately $2.5 million and $2.3 million,
respectively, as the weather was warmer than normal.
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 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.
36
PIPELINE
AND STORAGE
Revenues
Pipeline
and Storage Operating Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended September 30
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(Thousands)
|
|
|
Firm Transportation
|
|
$
|
122,321
|
|
|
$
|
118,771
|
|
|
$
|
118,551
|
|
Interruptible Transportation
|
|
|
4,330
|
|
|
|
4,161
|
|
|
|
4,858
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
126,651
|
|
|
|
122,932
|
|
|
|
123,409
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Firm Storage Service
|
|
|
67,020
|
|
|
|
66,966
|
|
|
|
66,718
|
|
Interruptible Storage Service
|
|
|
14
|
|
|
|
169
|
|
|
|
39
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
67,034
|
|
|
|
67,135
|
|
|
|
66,757
|
|
Other
|
|
|
22,871
|
|
|
|
21,899
|
|
|
|
24,186
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
216,556
|
|
|
$
|
211,966
|
|
|
$
|
214,352
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pipeline
and Storage Throughput (MMcf)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended September 30
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
Firm Transportation
|
|
|
353,173
|
|
|
|
351,113
|
|
|
|
363,379
|
|
Interruptible Transportation
|
|
|
5,197
|
|
|
|
4,975
|
|
|
|
11,609
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
358,370
|
|
|
|
356,088
|
|
|
|
374,988
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008
Compared with 2007
Operating revenues for the Pipeline and Storage segment
increased $4.6 million in 2008 as compared with 2007. The
majority of the increase was the result of increased
transportation revenues ($3.7 million) due to the fact that
the Pipeline & Storage segment was able to renew
existing contracts at higher rates due to favorable market
conditions for transportation service associated with storage.
In addition, there were increased efficiency gas revenues
($0.8 million) reported as part of other revenues in the
table above. The majority of this increase was due to higher gas
prices in the current year.
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.
Earnings
2008
Compared with 2007
The Pipeline and Storage segments earnings in 2008 were
$54.1 million, a decrease of $2.2 million when
compared with earnings of $56.4 million in 2007. The main
factors contributing to this decrease were higher operation and
maintenance expenses ($6.1 million), primarily caused by
the non-recurrence in 2008 of a reversal of a reserve for
preliminary survey costs related to the Empire Connector project
during 2007
37
($4.8 million). In addition, there was a $1.9 million
positive earnings impact during 2007 associated with the
discontinuance of hedge accounting for Empires interest
rate collar that did not recur during 2008, and the Pipeline and
Storage segment experienced higher interest costs
($1.5 million). These earnings decreases were offset by the
earnings impact associated with higher transportation revenues
($2.4 million), an increase in the allowance for funds used
during construction ($4.2 million) and the earnings impact
associated with higher efficiency gas revenues
($0.5 million).
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), the earnings impact associated with 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).
EXPLORATION
AND PRODUCTION
Revenues
Exploration
and Production Operating Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended September 30
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(Thousands)
|
|
|
Gas (after Hedging) from Continuing Operations
|
|
$
|
202,153
|
|
|
$
|
143,785
|
|
|
$
|
126,969
|
|
Oil (after Hedging) from Continuing Operations
|
|
|
250,965
|
|
|
|
167,627
|
|
|
|
134,307
|
|
Gas Processing Plant from Continuing Operations
|
|
|
49,090
|
|
|
|
37,528
|
|
|
|
42,252
|
|
Other from Continuing Operations
|
|
|
(944
|
)
|
|
|
1,147
|
|
|
|
3,072
|
|
Intrasegment Elimination from Continuing Operations(1)
|
|
|
(34,504
|
)
|
|
|
(26,050
|
)
|
|
|
(31,704
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Revenues from Continuing Operations
|
|
$
|
466,760
|
|
|
$
|
324,037
|
|
|
$
|
274,896
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Revenues from Canada Discontinued
Operations
|
|
$
|
|
|
|
$
|
50,495
|
|
|
$
|
71,984
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(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. |
38
Production
Volumes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended September 30
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
Gas Production (MMcf)
|
|
|
|
|
|
|
|
|
|
|
|
|
Gulf Coast
|
|
|
11,033
|
|
|
|
10,356
|
|
|
|
9,110
|
|
West Coast
|
|
|
4,039
|
|
|
|
3,929
|
|
|
|
3,880
|
|
Appalachia
|
|
|
7,269
|
|
|
|
5,555
|
|
|
|
5,108
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Production from Continuing Operations
|
|
|
22,341
|
|
|
|
19,840
|
|
|
|
18,098
|
|
Canada Discontinued Operations
|
|
|
|
|
|
|
6,426
|
|
|
|
7,673
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Production
|
|
|
22,341
|
|
|
|
26,266
|
|
|
|
25,771
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil Production (Mbbl)
|
|
|
|
|
|
|
|
|
|
|
|
|
Gulf Coast
|
|
|
505
|
|
|
|
717
|
|
|
|
685
|
|
West Coast
|
|
|
2,460
|
|
|
|
2,403
|
|
|
|
2,582
|
|
Appalachia
|
|
|
105
|
|
|
|
124
|
|
|
|
69
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Production from Continuing Operations
|
|
|
3,070
|
|
|
|
3,244
|
|
|
|
3,336
|
|
Canada Discontinued Operations
|
|
|
|
|
|
|
206
|
|
|
|
272
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Production
|
|
|
3,070
|
|
|
|
3,450
|
|
|
|
3,608
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average
Prices
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended September 30
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
Average Gas Price/Mcf
|
|
|
|
|
|
|
|
|
|
|
|
|
Gulf Coast
|
|
$
|
10.03
|
|
|
$
|
6.58
|
|
|
$
|
8.01
|
|
West Coast
|
|
$
|
8.71
|
|
|
$
|
6.54
|
|
|
$
|
7.93
|
|
Appalachia
|
|
$
|
9.73
|
|
|
$
|
7.48
|
|
|
$
|
9.53
|
|
Weighted Average for Continuing Operations
|
|
$
|
9.70
|
|
|
$
|
6.82
|
|
|
$
|
8.42
|
|
Weighted Average After Hedging for Continuing Operations(1)
|
|
$
|
9.05
|
|
|
$
|
7.25
|
|
|
$
|
7.02
|
|
Canada Discontinued Operations
|
|
$
|
|
|
|
$
|
6.09
|
|
|
$
|
7.14
|
|
Average Oil Price/Barrel (bbl)
|
|
|
|
|
|
|
|
|
|
|
|
|
Gulf Coast
|
|
$
|
107.27
|
|
|
$
|
63.04
|
|
|
$
|
64.10
|
|
West Coast(2)
|
|
$
|
98.17
|
|
|
$
|
56.86
|
|
|
$
|
56.80
|
|
Appalachia
|
|
$
|
97.40
|
|
|
$
|
62.26
|
|
|
$
|
65.28
|
|
Weighted Average for Continuing Operations
|
|
$
|
99.64
|
|
|
$
|
58.43
|
|
|
$
|
58.47
|
|
Weighted Average After Hedging for Continuing Operations(1)
|
|
$
|
81.75
|
|
|
$
|
51.68
|
|
|
$
|
40.26
|
|
Canada Discontinued Operations
|
|
$
|
|
|
|
$
|
50.06
|
|
|
$
|
51.40
|
|
|
|
|
(1) |
|
Refer to further discussion of hedging activities below under
Market Risk Sensitive Instruments and in
Note F Financial Instruments in Item 8 of
this report. |
|
(2) |
|
Includes low gravity oil which generally sells for a lower price. |
2008
Compared with 2007
Operating revenues from continuing operations for the
Exploration and Production segment increased $142.7 million
in 2008 as compared with 2007. Oil production revenue after
hedging from continuing operations increased $83.3 million
due primarily to a $30.07 per barrel increase in weighted
average prices after hedging, which more than offset a decrease
in oil production of 174,000 barrels. Gas production
revenue
39
after hedging from continuing operations increased
$58.4 million due to a $1.80 per Mcf increase in weighted
average prices after hedging and a 2,501 MMcf increase in
production. The increase in gas production from continuing
operations occurred primarily in the Appalachian region
(1,714 MMcf), consistent with increased drilling activity
in the region. The Gulf Coast region also contributed
significantly to the increase in natural gas production from
continuing operations (677 MMcf). Production from new
fields in 2008 (primarily in the High Island area) outpaced
declines in production from some existing fields, period to
period. Production in this region would have been higher if not
for the hurricane activity during the month of September 2008.
As a result of hurricanes Edouard, Gustav and Ike, production
was shut in for much of the month of September, resulting in
estimated lost production of approximately 804 MMcf of
natural gas and 45 Mbbl of oil. While Senecas properties
sustained only superficial damage from the hurricanes,
approximately 50% of the pre-hurricane production remains
shut-in due to repair work on third party pipelines and onshore
processing facilities. The majority of this production is
anticipated to return by December 1, 2008.
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.
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.
Earnings
2008
Compared with 2007
The Exploration and Production segments earnings from
continuing operations for 2008 were $146.6 million, an
increase of $71.7 million when compared with earnings from
continuing operations of $74.9 million for 2007. Higher
crude oil prices, higher natural gas prices and higher natural
gas production increased earnings by $60.0 million,
$26.2 million and $11.8 million, respectively, while
lower crude oil production decreased earnings by
$5.8 million. Higher lease operating costs
($11.9 million), higher depletion expense
($9.1 million), higher income tax expense
($1.1 million) and higher general and administrative and
other operating expenses ($6.2 million) also negatively
impacted earnings. Lower interest expense and higher interest
income of $6.6 million and $0.7 million, respectively,
partially offset these decreases to earnings. The increase in
lease operating costs resulted from the
start-up of
production at the High Island 24L field in October 2007, higher
steaming costs in California, and an increase in costs
associated with a higher number of producing properties in
Appalachia. The increase in depletion expense was caused by
higher production and an increase in the depletable base. The
increase in general and administrative and other operating
expenses resulted from an increase in staffing and associated
costs for the growing Appalachia division combined with the
recognition of actual plugging costs in excess of previously
accrued amounts.
40
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, 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 higher income tax expense
($6.3 million).
ENERGY
MARKETING
Revenues
Energy
Marketing Operating Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended September 30
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(Thousands)
|
|
|
Natural Gas (after Hedging)
|
|
$
|
551,243
|
|
|
$
|
413,405
|
|
|
$
|
496,769
|
|
Other
|
|
|
(11
|
)
|
|
|
207
|
|
|
|
300
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
551,232
|
|
|
$
|
413,612
|
|
|
$
|
497,069
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy
Marketing Volumes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended September 30
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
Natural Gas (MMcf)
|
|
|
56,120
|
|
|
|
50,775
|
|
|
|
45,270
|
|
2008
Compared with 2007
Operating revenues for the Energy Marketing segment increased
$137.6 million in 2008 as compared with 2007. The increase
is primarily due to higher gas sales revenue, as a result of an
increase in the price of natural gas that was recovered through
revenues, coupled with an increase in volumes. The increase in
volumes is primarily attributable to an increase in volumes sold
to low-margin wholesale customers, as well as an increase in the
number of commercial and industrial customers served by the
Energy Marketing segment. The increase in volumes also reflects
certain sales transactions undertaken to offset certain basis
risks that the Energy Marketing segment was exposed to under
certain commodity purchase contracts. The offsetting purchase
and sale transactions had the effect of increasing revenue and
volumes sold with minimal impact to earnings.
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 volumes. The
increase in volumes was due to the addition of certain large,
low-margin commercial and industrial customers, an increase in
sales to wholesale customers, and colder weather.
Earnings
2008
Compared with 2007
The Energy Marketing segments earnings in 2008 were
$5.9 million, a decrease of $1.8 million when compared
with earnings of $7.7 million in 2007. Higher operating
costs of $1.1 million (primarily due to an increase in bad
debt expense) coupled with lower margins of $1.1 million
are primarily responsible for the decrease in earnings. A major
factor in the margin decrease is the non-recurrence of a
purchased gas expense
41
adjustment recorded during the quarter ended March 31,
2007. During that quarter, the Energy Marketing segment reversed
an accrual for $2.3 million of purchased gas expense due to
a resolution of a contingency. The increase in volumes noted
above, the profitable sale of certain gas held as inventory, and
the marketing flexibility that the Energy Marketing segment
derives from its contracts for significant storage capacity
partially offset the margin decrease associated with the
purchased gas adjustment.
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 volumes increased, as noted above, much of this increase
in volume is related to sales to low margin customers.
TIMBER
Revenues
Timber
Operating Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended September 30
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(Thousands)
|
|
|
Log Sales
|
|
$
|
19,989
|
|
|
$
|
21,927
|
|
|
$
|
23,077
|
|
Green Lumber Sales
|
|
|
4,864
|
|
|
|
5,097
|
|
|
|
7,123
|
|
Kiln-Dried Lumber Sales
|
|
|
22,914
|
|
|
|
27,908
|
|
|
|
32,809
|
|
Other
|
|
|
1,749
|
|
|
|
3,965
|
|
|
|
2,020
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
49,516
|
|
|
$
|
58,897
|
|
|
$
|
65,029
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Timber
Board Feet
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended September 30
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(Thousands)
|
|
|
Log Sales
|
|
|
9,272
|
|
|
|
8,660
|
|
|
|
9,527
|
|
Green Lumber Sales
|
|
|
9,747
|
|
|
|
9,358
|
|
|
|
10,454
|
|
Kiln-Dried Lumber Sales
|
|
|
13,425
|
|
|
|
14,778
|
|
|
|
16,862
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
32,444
|
|
|
|
32,796
|
|
|
|
36,843
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008
Compared with 2007
Operating revenues for the Timber segment decreased
$9.4 million in 2008 as compared with 2007. Unfavorable
market conditions for cherry logs and lumber combined with wet
weather conditions that hampered harvesting were the main
factors causing the decrease. The decrease consisted of a
$5.0 million decline in kiln-dried lumber sales. The
decrease in kiln-dried lumber sales was due to both a decline in
the market price of kiln-dried lumber as well as a 1,353,000
board feet decline in kiln-dried lumber sales volumes (primarily
kiln-dried cherry lumber sales volumes). Log sales also
decreased $1.9 million primarily due to a decline in cherry
veneer log sales volumes of 328,000 board feet. Cherry veneer
logs are more valuable and sell at higher prices than other
species and have the largest impact on overall log sales
revenue. In addition, in 2007 the Timber segment sold
3.1 million board feet of timber rights and recorded a gain
of $1.6 million in other revenues. This event did not recur
in 2008.
42
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.
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).
Earnings
2008
Compared with 2007
The Timber segment earnings in 2008 were $0.1 million, a
decrease of $3.6 million when compared with earnings of
$3.7 million in 2007. The decrease was primarily due to
lower margins from lumber, log and timber rights sales
($4.2 million) as a result of the decline in revenues noted
above. This decrease was partially offset by the earnings
benefit associated with a lower effective tax rate
($0.8 million).
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.
ALL OTHER
AND CORPORATE OPERATIONS
All Other and Corporate operations primarily includes the
operations of Horizon LFG, Horizon Power, former International
segment activity 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.
Earnings
2008
Compared with 2007
All Other and Corporate operations had earnings of
$0.5 million in 2008, a decrease of $7.6 million
compared with earnings of $8.1 million for 2007. The
positive earnings impact of higher income from unconsolidated
subsidiaries ($0.9 million) and a gain on the sale of a
turbine by Horizon Power ($0.6 million) were more than
offset by higher operating costs ($6.1 million), higher
income tax expense ($1.7 million) and lower interest income
($1.3 million). The increase in operating costs is
primarily the result of the proxy contest with New Mountain
Vantage GP, L.L.C.
43
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 lower income tax expense
($2.0 million).
INTEREST
INCOME
Interest income was $9.3 million higher in 2008 as compared
to 2007. The main reason for this increase was a
$4.0 million increase in interest income on a
pension-related regulatory asset in the Utility segments
New York jurisdiction. The Exploration and Production
segment also contributed $3.8 million to this increase as a
result of the investment of cash proceeds from the sale of SECI
in August 2007.
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 a $7.4 million decrease
in interest income on a pension-related regulatory asset in the
Utility segments New York jurisdiction.
OTHER
INCOME
Other income was $2.4 million higher in 2008 as compared to
2007. This increase is attributed to the increase in the
allowance for funds used during construction, in the Pipeline
and Storage segment, associated with the Empire Connector
project of $4.2 million. This increase was partially offset
by the non-recurrence of a death benefit gain on life insurance
proceeds of $1.9 million recognized in the Corporate
category in 2007.
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.
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 increased $1.7 million in 2008
as compared to 2007. The increase in 2008 was primarily the
result of a higher average amount of long-term debt outstanding.
In April 2008, the Company issued $300 million of
6.5% senior, unsecured notes due in April 2018. This
increase was partially offset by the repayment of
$200 million of 6.303% medium-term notes that matured on
May 27, 2008.
Interest on long-term debt decreased $4.2 million in 2007
as compared to 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 decreased $2.2 million in 2008
compared to 2007. Other interest charges did not change
significantly in 2007 as compared to 2006. The decrease in 2008
was primarily caused by a $1.7 million increase in the
allowance for borrowed funds used during construction related to
the Empire Connector project.
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
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(Millions)
|
|
|
Provided by Operating Activities
|
|
$
|
482.8
|
|
|
$
|
394.2
|
|
|
$
|
471.4
|
|
Capital Expenditures
|
|
|
(397.7
|
)
|
|
|
(276.7
|
)
|
|
|
(294.2
|
)
|
Investment in Partnership
|
|
|
|
|
|
|
(3.3
|
)
|
|
|
|
|
Net Proceeds from Sale of Foreign Subsidiaries
|
|
|
|
|
|
|
232.1
|
|
|
|
|
|
Cash Held in Escrow
|
|
|
58.4
|
|
|
|
(58.2
|
)
|
|
|
|
|
Net Proceeds from Sale of Oil and Gas Producing Properties
|
|
|
5.9
|
|
|
|
5.1
|
|
|
|
|
|
Other Investing Activities
|
|
|
4.4
|
|
|
|
(0.8
|
)
|
|
|
(3.2
|
)
|
Reduction of Long-Term Debt
|
|
|
(200.0
|
)
|
|
|
(119.6
|
)
|
|
|
(9.8
|
)
|
Net Proceeds from Issuance of Long-Term Debt
|
|
|
296.6
|
|
|
|
|
|
|
|
|
|
Issuance of Common Stock
|
|
|
17.4
|
|
|
|
17.5
|
|
|
|
23.3
|
|
Dividends Paid on Common Stock
|
|
|
(103.7
|
)
|
|
|
(100.6
|
)
|
|
|
(98.2
|
)
|
Excess Tax Benefits Associated with Stock- Based Compensation
Awards
|
|
|
16.3
|
|
|
|
13.7
|
|
|
|
6.5
|
|
Shares Repurchased under Repurchase Plan
|
|
|
(237.0
|
)
|
|
|
(48.1
|
)
|
|
|
(85.2
|
)
|
Effect of Exchange Rates on Cash
|
|
|
|
|
|
|
(0.1
|
)
|
|
|
1.4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Increase (Decrease) in Cash and Temporary Cash Investments
|
|
$
|
(56.6
|
)
|
|
$
|
55.2
|
|
|
$
|
12.0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 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 and futures contracts in an
attempt to manage this energy commodity price risk.
Net cash provided by operating activities totaled
$482.8 million in 2008, an increase of $88.6 million
compared with the $394.2 million provided by operating
activities in 2007. The increase is partially due to lower
working capital requirements in the Utility segment. In the
Exploration and Production segment, cash provided by operations
increased due to higher commodity prices, partially offset by
the decrease in cash provided by operations that resulted from
the sale of SECI in August 2007. Offsetting these increases were
higher working capital requirements in the Energy Marketing
segment.
45
INVESTING
CASH FLOW
Expenditures
for Long-Lived Assets
The Companys expenditures for long-lived assets totaled
$414.5 million in 2008. The table below presents these
expenditures:
|
|
|
|
|
|
|
Year Ended
|
|
|
|
September 30,
|
|
|
|
2008
|
|
|
|
Total Expenditures
|
|
|
|
For Long-Lived
|
|
|
|
Assets
|
|
|
|
(Millions)
|
|
|
Utility
|
|
$
|
57.5
|
|
Pipeline and Storage(1)
|
|
|
165.5
|
|
Exploration and Production
|
|
|
192.2
|
|
Timber
|
|
|
1.4
|
|
All Other and Corporate
|
|
|
0.3
|
|
Eliminations(2)
|
|
|
(2.4
|
)
|
|
|
|
|
|
|
|
$
|
414.5
|
|
|
|
|
|
|
|
|
|
(1) |
|
Amount includes $16.8 million of accrued capital
expenditures related to the Empire Connector project. This
amount has been excluded from the Consolidated Statement of Cash
Flows at September 30, 2008 since it represents a non-cash
investing activity at that date. |
|
(2) |
|
Represents $2.4 million of capital expenditures included in
the Appalachian region of the Exploration and Production segment
for the purchase of storage facilities, buildings, and base gas
from Supply Corporation during the quarter ended March 31,
2008. |
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 related to the Empire Connector project costs,
which is discussed below under Estimated Capital Expenditures,
as well as for additions, improvements and replacements to this
segments transmission and gas storage systems.
Exploration
and Production
The Exploration and Production segments capital
expenditures were primarily well drilling and completion
expenditures and included approximately $63.6 million for
the Gulf Coast region, substantially all of which was for the
off-shore program in the shallow waters of the Gulf of Mexico,
$62.8 million for the West Coast region and
$65.8 million for the Appalachian region. These amounts
included approximately $25.4 million spent to develop
proved undeveloped reserves. The Appalachian region capital
expenditures include $2.4 million for the purchase of
storage facilities, buildings, and base gas from Supply
Corporation, as shown in the table above.
Timber
The majority of the Timber segment capital expenditures were for
construction of a lumber sorter for Highlands sawmill
operations that was placed into service in October 2007 as well
as for purchases of equipment for Highlands sawmill and
kiln operations.
46
All Other
and Corporate
In March 2008, Horizon Power sold a gas-powered turbine that it
had planned to use in the development of a co-generation plant.
Horizon Power received proceeds of $5.3 million and
recorded a pre-tax gain of $0.9 million associated with the
sale.
Estimated
Capital Expenditures
The Companys estimated capital expenditures for the next
three years are:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended September 30
|
|
|
|
2009
|
|
|
2010
|
|
|
2011
|
|
|
|
(Millions)
|
|
|
Utility
|
|
$
|
58.0
|
|
|
$
|
60.0
|
|
|
$
|
56.0
|
|
Pipeline and Storage
|
|
|
73.0
|
|
|
|
76.0
|
|
|
|
46.0
|
|
Exploration and Production(1)
|
|
|
285.0
|
|
|
|
227.0
|
|
|
|
244.0
|
|
Timber
|
|
|
1.0
|
|
|
|
1.0
|
|
|
|
1.0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
417.0
|
|
|
$
|
364.0
|
|
|
$
|
347.0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Includes estimated expenditures for the years ended
September 30, 2009, 2010 and 2011 of approximately
$48 million, $42 million and $18 million,
respectively, to develop proved undeveloped reserves. |
Estimated capital expenditures for the Utility segment in 2009
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 2009 will be concentrated on the completion of the
Empire Connector project as discussed below, the replacement of
transmission and storage lines, the 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. Construction of the Empire Connector, a
pipeline designed to transport up to approximately 250 MDth of
natural gas per day that will connect the Empire Pipeline with
the Millennium Pipeline, began in September 2007. The Empire
Connector is anticipated to be ready to commence service in
December 2008, on or before the in-service date of the
Millennium Pipeline. Refer to the Rate and Regulatory Matters
section that follows for further discussion of this matter. The
total cost to the Company of the Empire Connector project is
estimated at $187 million, after giving effect to sales tax
exemptions worth approximately $3.7 million. As of
September 30, 2008, the Company had incurred approximately
$164.7 million in costs related to this project. Of this
amount, $145.0 million, $13.7 million and
$2.0 million were incurred during the years ended
September 30, 2008, 2007 and 2006, respectively. All
project costs incurred as of September 30, 2008 have been
capitalized as Construction Work in Progress. The Company
anticipates financing the remaining cost of this project with
cash from operations.
In light of the rapidly growing demand for pipeline capacity to
move natural gas from new wells being drilled in
Appalachia specifically in the Marcellus Shale
producing area Supply Corporation recently completed
an Open Season for its Appalachian Lateral (AppLat)
pipeline project. The AppLat is expected to be routed through
areas in Pennsylvania where producers are actively drilling and
are seeking market access for their newly discovered reserves.
The AppLat will complement Supplys original West to East
(W2E) project, which was designed to transport
Rockies gas supply from Clarington to the
Ellisburg/Leidy/Corning area and includes the
Tuscarora-to-Corning facilities previously referred to as the
Tuscarora Extension. The AppLat will transport gas supply from
Pennsylvanias producing area to the Overbeck area of
Supply Corporations existing system, where the facilities
associated with the W2E project will move the gas to eastern
market points, including Leidy, and to interconnections with
Millennium and Empire at Corning.
In conjunction with the W2E and AppLat transportation projects,
Supply Corporation has plans to develop new storage capacity by
pursuing expansion of certain of its existing storage
facilities. The expansion of these
47
fields, which Supply Corporation is marketing through a recently
completed Open Season concurrent with its AppLat Open Season,
could provide approximately 8.5 MMDth of incremental
storage capacity with incremental withdrawal deliverability of
up to 121 MDth of natural gas per day, with service commencing
as early as 2011. Supply Corporation expects that the
availability of this incremental storage capacity will
complement the W2E and AppLat pipeline projects and help meet
the demand for storage created by the prospective increased flow
of Appalachian and Rockies gas supply into the western
Pennsylvania area, although traditional gas supplies will also
be able to take advantage of this incremental storage capacity.
The timeline associated with Supply Corporations pipeline
and storage projects depends on market development. The capital
cost of the AppLat/W2E project is estimated to be approximately
$800 million, and is expected to be financed by a
combination of debt and equity. As of September 30, 2008,
$0.2 million has been spent to study the W2E and AppLat
projects, and approximately $0.6 million has been spent to
study the storage expansion project. Costs associated with these
projects have been included in preliminary survey and
investigation charges and have been fully reserved for at
September 30, 2008. Supply Corporation has not yet filed an
application with the FERC for the authority to build either
pipeline project or the storage expansion.
Estimated capital expenditures in 2009 for the Exploration and
Production segment include approximately $35.0 million for
the Gulf Coast region, substantially all of which is for the
off-shore program in the Gulf of Mexico, $53.6 million for
the West Coast region and $196.3 million for the
Appalachian region.
Estimated capital expenditures in 2009 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, 2008.
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 $420.0 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 through
September 30, 2010. At September 30, 2008, the
Companys debt to capitalization ratio (as calculated under
the facility) was .41. The constraints specified in the
committed credit facility would permit an additional
$1.88 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
48
borrow under its committed credit facility, 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, 2008, the Company would have been permitted
to issue up to a maximum of $1.3 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
$199.0 million (or 18%) of the Companys long-term
debt (as of September 30, 2008) 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, 2008, the Company had no debt outstanding
under the committed credit facility.
The Companys embedded cost of long-term debt was 6.5% at
September 30, 2008 and 6.4% at September 30, 2007.
Refer to Interest Rate Risk in this Item for a more
detailed breakdown of the Companys embedded cost of
long-term debt.
In April 2008, the Company issued $300.0 million of
6.50% senior, unsecured notes in a private placement exempt
from registration under the Securities Act of 1933. The notes
have a term of 10 years, with a maturity date in April
2018. The holders of the notes may require the Company to
repurchase their notes in the event of a change in control at a
price equal to 101% of the principal amount. In addition, the
Company is required to either offer to exchange the notes for
substantially similar notes as are registered under the
Securities Act of 1933 or, in certain circumstances, register
the resale of the notes. The Company used $200.0 million of
the proceeds to refund $200.0 million of 6.303% medium-term
notes that subsequently matured on May 27, 2008. In
November 2008 the Company filed a registration statement with
the SEC in connection with the Companys plan to offer to
exchange the notes for substantially similar registered notes.
The Company will seek to have the SEC declare the registration
statement effective as of a date coinciding with or following
the date of this report.
In December 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 eight million shares in the
open market or through privately negotiated transactions. The
Company completed the repurchase of the eight million shares
during 2008 for a total program cost of $324.2 million (of
which 4,165,122 shares were repurchased during the year
ended September 30, 2008 for $191.0 million). In
September 2008, the Companys Board of Directors authorized
the repurchase of an additional eight million shares. Under this
new authorization, the Company repurchased 1,028,981 shares
for $46.0 million through September 17, 2008. The
Company stopped repurchasing shares after September 17,
2008 in light of the unsettled nature of the credit markets.
However, such repurchases may be made in the future if
conditions improve. All share repurchases mentioned above were
funded with cash provided by operating activities
and/or
through the use of the Companys lines of credit.
The Company may issue debt or equity securities in a public
offering or a private placement from time to time. 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.
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 $32.3 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
$3.0 million. The Company has guaranteed 50%, or
$1.5 million, of these capital lease commitments.
CONTRACTUAL
OBLIGATIONS
The following table summarizes the Companys expected
future contractual cash obligations as of September 30,
2008, and the twelve-month periods over which they occur:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payments by Expected Maturity Dates
|
|
|
|
2009
|
|
|
2010
|
|
|
2011
|
|
|
2012
|
|
|
2013
|
|
|
Thereafter
|
|
|
Total
|
|
|
|
(Millions)
|
|
|
Long-Term Debt, including interest expense(1)
|
|
$
|
167.5
|
|
|
$
|
65.0
|
|
|
$
|
252.2
|
|
|
$
|
191.4
|
|
|
$
|
282.3
|
|
|
$
|
565.0
|
|
|
$
|
1,523.4
|
|
Operating Lease Obligations
|
|
$
|
6.0
|
|
|
$
|
4.6
|
|
|
$
|
3.6
|
|
|
$
|
3.2
|
|
|
$
|
2.5
|
|
|
$
|
12.4
|
|
|
$
|
32.3
|
|
Capital Lease Obligations
|
|
$
|
0.5
|
|
|
$
|
0.4
|
|
|
$
|
0.4
|
|
|
$
|
0.2
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
1.5
|
|
Purchase Obligations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas Purchase Contracts(2)
|
|
$
|
745.8
|
|
|
$
|
122.3
|
|
|
$
|
14.5
|
|
|
$
|
10.3
|
|
|
$
|
10.3
|
|
|
$
|
83.8
|
|
|
$
|
987.0
|
|
Transportation and Storage Contracts
|
|
$
|
47.4
|
|
|
$
|
45.7
|
|
|
$
|
41.1
|
|
|
$
|
36.7
|
|
|
$
|
11.3
|
|
|
$
|
16.9
|
|
|
$
|
199.1
|
|
Empire Connector Project Obligations
|
|
$
|
13.5
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
13.5
|
|
Other
|
|
$
|
12.4
|
|
|
$
|
10.5
|
|
|
$
|
4.2
|
|
|
$
|
4.0
|
|
|
$
|
3.5
|
|
|
$
|
12.6
|
|
|
$
|
47.2
|
|
|
|
|
(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. |
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 environmental and other matters discussed in
this Item 7 and in Item 8 at Note H
Commitments and Contingencies, 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 expected
to change materially the Companys present liquidity
position, nor are they expected 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 a majority 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 2008, the Company contributed
$16.0 million to the Retirement Plan. The Company
anticipates that the
50
annual contribution to the Retirement Plan in 2009 will be in
the range of $15.0 million to $20.0 million. As a
result of the recent downturn in the stock markets and general
economic conditions, it is likely that the Company will have to
fund larger amounts to the Retirement Plan subsequent to 2009 in
order to be in compliance with the Pension Protection Act of
2006. The Company expects that all subsidiaries having 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
(other post-retirement benefits) for a majority of its retired
employees. The Company has established VEBA trusts and 401(h)
accounts for its other post-retirement benefits. The Company has
been making contributions to its VEBA trusts and 401(h) accounts
over the last several years and anticipates that it will
continue making contributions to the VEBA trusts and 401(h)
accounts. During 2008, the Company contributed
$29.1 million to its VEBA trusts and 401(h) accounts. The
Company anticipates that the annual contribution to its VEBA
trusts and 401(h) accounts in 2009 will be in the range of
$25.0 million to $30.0 million. The funding of such
contributions will come from amounts collected in rates in the
Utility and Pipeline and Storage segments.
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, 2008 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, 2008. At September 30, 2008, the
Company had not entered into any natural gas or crude oil price
swap agreements extending beyond 2011.
Natural
Gas Price Swap Agreements
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expected Maturity Dates
|
|
|
|
|
|
|
2009
|
|
|
2010
|
|
|
2011
|
|
|
Total
|
|
|
Notional Quantities (Equivalent Bcf)
|
|
|
11.8
|
|
|
|
3.3
|
|
|
|
0.0
|
(1)
|
|
|
15.1
|
|
Weighted Average Fixed Rate (per Mcf)
|
|
$
|
9.35
|
|
|
$
|
10.89
|
|
|
$
|
10.55
|
|
|
$
|
9.69
|
|
Weighted Average Variable Rate (per Mcf)
|
|
$
|
8.10
|
|
|
$
|
8.74
|
|
|
$
|
9.30
|
|
|
$
|
8.24
|
|
|
|
|
(1) |
|
The Energy Marketing segment has natural gas swap agreements
covering approximately 40,000 Mcf in 2011. |
51
Crude
Oil Price Swap Agreements
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expected Maturity Dates
|
|
|
|
|
|
|
2009
|
|
|
2010
|
|
|
2011
|
|
|
Total
|
|
|
Notional Quantities (Equivalent bbls)
|
|
|
1,260,000
|
|
|
|
600,000
|
|
|
|
60,000
|
|
|
|
1,920,000
|
|
Weighted Average Fixed Rate (per bbl)
|
|
$
|
83.12
|
|
|
$
|
102.52
|
|
|
$
|
125.25
|
|
|
$
|
90.50
|
|
Weighted Average Variable Rate (per bbl)
|
|
$
|
103.08
|
|
|
$
|
104.17
|
|
|
$
|
105.21
|
|
|
$
|
103.49
|
|
At September 30, 2008, the Company would have received from
its respective counterparties an aggregate of approximately
$20.3 million to terminate the natural gas price swap
agreements outstanding at that date. The Energy Marketing
segment also used natural gas swaps to hedge basis risk on their
fixed price purchase commitments. At September 30, 2008,
the Company had natural gas basis swap agreements covering
1.4 Bcf at a weighted average fixed rate of $0.47 (per Mcf)
and a weighted average variable rate of $0.64 (per Mcf). These
natural gas swap agreements are treated as fair value hedges and
the Company would have had to pay $0.2 million at
September 30, 2008 to terminate the agreements. The Company
would have had to pay an aggregate of approximately
$0.8 million to its counterparties to terminate the crude
oil price swap agreements outstanding at September 30, 2008.
At September 30, 2007, the Company had natural gas price
swap agreements covering 13.2 Bcf at a weighted average
fixed rate of $8.20 per Mcf. The Company also had crude oil
price swap agreements covering 1,485,000 bbls at a weighted
average fixed rate of $57.35 per bbl.
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, 2008, the Company held no futures contracts
with maturity dates extending beyond 2012.
Futures
Contracts
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expected Maturity Dates
|
|
|
|
2009
|
|
|
2010
|
|
|
2011
|
|
|
2012
|
|
|
Total
|
|
|
Net Contract Volumes Purchased (Sold)
(Equivalent Bcf)
|
|
|
2.1
|
|
|
|
0.3
|
|
|
|
|
(1)
|
|
|
|
(1)
|
|
|
2.4
|
|
Weighted Average Contract Price (per Mcf)
|
|
$
|
10.02
|
|
|
$
|
9.59
|
|
|
$
|
8.05
|
|
|
$
|
8.68
|
|
|
$
|
9.99
|
|
Weighted Average Settlement Price (per Mcf)
|
|
$
|
9.41
|
|
|
$
|
9.85
|
|
|
$
|
7.49
|
|
|
$
|
8.27
|
|
|
$
|
9.43
|
|
|
|
|
(1) |
|
The Energy Marketing segment has purchased 7 and 6 futures
contracts (1 contract = 2,500 Dth) for 2011 and 2012,
respectively. |
At September 30, 2008, the Company would have received
$8.7 million to terminate these futures contracts.
At September 30, 2007, the Company had futures contracts
covering 2.8 Bcf (net long position) at a weighted average
contract price of $9.11 per Mcf.
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, 2008,
the Company had eleven counterparties for its over the counter
derivative financial instruments and no individual counterparty
represented greater than 42% of total credit risk (measured as
volumes hedged by an individual counterparty as a percentage of
the Companys total over the counter volumes hedged). The
Company recorded a $0.6 million reduction to the fair
market value of its derivative assets based on its assessment of
counterparty credit risk. This credit reserve was determined by
applying default probabilities to the anticipated cash flows
that the Company is expecting from its counterparties.
52
Interest
Rate Risk
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, 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Principal Amounts by Expected Maturity Dates
|
|
|
|
2009
|
|
|
2010
|
|
|
2011
|
|
|
2012
|
|
|
2013
|
|
|
Thereafter
|
|
|
Total
|
|
|
|
(Dollars in millions)
|
|
|
|
|
|
Long-Term Fixed Rate Debt
|
|
$
|
100.0
|
(1)
|
|
$
|
|
|
|
$
|
200.0
|
|
|
$
|
150.0
|
|
|
$
|
250.0
|
|
|
$
|
399.0
|
|
|
$
|
1,099.0
|
|
Weighted Average Interest Rate Paid
|
|
|
6.0
|
%
|
|
|
|
|
|
|
7.5
|
%
|
|
|
6.7
|
%
|
|
|
5.3
|
%
|
|
|
6.7
|
%
|
|
|
6.5
|
%
|
Fair Value of Long-Term Fixed Rate Debt = $1,027.1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(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 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 was necessitated by decreased
revenues resulting from customer conservation efforts and
increased customer uncollectibles, among other things. The rate
filing also included a proposal for an 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,
Distribution Corporations conservation program for
implementation on an accelerated basis. Associated ratemaking
issues, however, were reserved for consideration in the rate.
On December 21, 2007, the NYPSC issued a rate order
providing for an annual rate increase of $1.8 million,
together with a monthly bill surcharge that would collect up to
$10.8 million to recover expenses for implementation of the
conservation program. The rate increase and bill surcharge
became effective December 28, 2007. The rate order further
provided for a return on equity of 9.1%. The rate order also
adopted Distribution Corporations proposed revenue
decoupling mechanism. The revenue decoupling mechanism, like
others, decouples revenues from throughput by
enabling the Company to collect from small volume customers its
allowed margin on average weather normalized usage per customer.
The effect of the revenue decoupling mechanism is to render the
Company financially indifferent to throughput decreases
resulting from conservation. The Company surcharges or credits
any difference from the average weather normalized usage per
customer account. The surcharge or credit is calculated to
recover total margin for the most recent twelve-month period
ending December 31, and applied to customer bills annually,
beginning March 1st.
On April 18, 2008, Distribution Corporation filed an appeal
with Supreme Court, Albany County, seeking review of the rate
order. The appeal contends that portions of the rate order
should be invalidated because they fail to meet the applicable
legal standard for agency decisions. Among the issues challenged
by the Company are the reasonableness of the NYPSCs
disallowance of expense items, including health care costs, and
the
53
methodology used for calculating rate of return, which the
appeal contends understated the Companys cost of equity.
The Company cannot predict the outcome of the appeal 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
included 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.
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.
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 December 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 the FERC, within three years after the
in-service date, justifying Empires existing recourse
rates or proposing alternative rates.
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.
The Empire Certificate contains various environmental and other
conditions. Empire accepted that Certificate and received
additional environmental permits from the U.S. Army Corps
of Engineers and state environmental agencies. Empire also
received, from all six upstate New York counties in which
it will build the Empire Connector project, final approval of
sales tax exemptions and temporary partial property tax
abatements. 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
required construction of this project. Construction began in
September 2007 and is anticipated to be ready to commence
service in December 2008, on or before the in-service date of
the Millennium Pipeline to which it will connect.
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, 2008, 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
$19.4 million to $23.6 million. The minimum estimated
liability of $19.4 million has been recorded on the
Consolidated Balance Sheet at September 30, 2008. The
Company expects to recover its environmental
clean-up
costs from a combination
54
of rate recovery and deferred insurance proceeds that are
currently recorded as a regulatory liability on the Consolidated
Balance Sheet. Other than discussed in Note H (referred to
below), the Company is currently not aware of any material
additional exposure to environmental liabilities. However,
changes in environmental regulations or other factors could
adversely 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 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. SFAS 157 is to be
applied whenever another standard requires or allows assets or
liabilities to be measured at fair value. In accordance with
FASB Staff Position
FAS No. 157-2,
SFAS 157 is effective for financial assets and financial
liabilities that are recognized or disclosed at fair value on a
recurring basis as of the Companys first quarter of fiscal
2009. The same FASB Staff Position delays the effective date for
nonfinancial assets and nonfinancial liabilities, except for
items that are recognized or disclosed at fair value on a
recurring basis, until the Companys first quarter of
fiscal 2010. The Company does not expect that SFAS 157 will
have a significant impact on its consolidated financial
statements.
In September 2006, the FASB also 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 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 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
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 does not plan to elect the
fair value measurement option for any of its financial
instruments other than those that are already being measured at
fair value.
In December 2007, the FASB issued SFAS 141R. SFAS 141R
will significantly change the accounting for business
combinations in a number of areas including the treatment of
contingent consideration, contingencies,
55
acquisition costs, in process research and development and
restructuring costs. In addition, under SFAS 141R, changes
in deferred tax asset valuation allowances and acquired income
tax uncertainties in a business combination after the
measurement period will impact income tax expense.
SFAS 141R is effective as of the Companys first
quarter of fiscal 2010.
In December 2007, the FASB issued SFAS 160. SFAS 160
will change the accounting and reporting for minority interests,
which will be recharacterized as noncontrolling interests (NCI)
and classified as a component of equity. This new consolidation
method will significantly change the accounting for transactions
with minority interest holders. SFAS 160 is effective as of
the Companys first quarter of fiscal 2010. The Company
currently does not have any NCI.
In March 2008, the FASB issued SFAS 161. SFAS 161
requires entities to provide enhanced disclosures related to an
entitys derivative instruments and hedging activities in
order to enable investors to better understand how derivative
instruments and hedging activities impact an entitys
financial reporting. The additional disclosures include how and
why an entity uses derivative instruments, how derivative
instruments and related hedged items are accounted for under
SFAS 133 and its related interpretations, and how
derivative instruments and related hedged items affect an
entitys financial position, financial performance, and
cash flows. SFAS 161 is effective as of the Companys
second quarter of fiscal 2009. The Company is currently
evaluating the impact that the adoption of SFAS 161 will
have on its disclosures in the notes to the 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 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,
objectives, goals, projections, strategies, future events or
performance and underlying assumptions, 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,
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
56
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.
|
Financial and economic conditions, including the availability of
credit, and their effect on the Companys ability to obtain
financing on acceptable terms for working capital, capital
expenditures and other investments;
|
|
2.
|
Occurrences affecting the Companys ability to obtain
financing under credit lines or other credit facilities or
through the issuance of commercial paper, other short-term notes
or debt or equity securities, including any downgrades in the
Companys credit ratings and changes in interest rates and
other capital market conditions;
|
|
3.
|
Changes in economic conditions, including global, national or
regional recessions, and their effect on the demand for, and
customers ability to pay for, the Companys products
and services;
|
|
4.
|
The creditworthiness or performance of the Companys key
suppliers, customers and counterparties;
|
|
5.
|
Economic disruptions or uninsured losses resulting from
terrorist activities, acts of war, major accidents, fires,
hurricanes, other severe weather, pest infestation or other
natural disasters;
|
|
6.
|
Changes in actuarial assumptions, the interest rate environment
and the return on plan/trust assets related to the
Companys pension and other post-retirement benefits, which
can affect future funding obligations and costs and plan
liabilities;
|
|
7.
|
Changes in demographic patterns and weather conditions;
|
|
8.
|
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;
|
|
9.
|
Impairments under the SECs full cost ceiling test for
natural gas and oil reserves;
|
|
10.
|
Uncertainty of oil and gas reserve estimates;
|
|
11.
|
Ability to successfully identify, drill for and produce
economically viable natural gas and oil reserves, including
shortages, delays or unavailability of equipment and services
required in drilling operations;
|
|
12.
|
Significant changes from expectations in the Companys
actual production levels for natural gas or oil;
|
|
13.
|
Changes in the availability
and/or price
of derivative financial instruments;
|
|
14.
|
Changes in the price differentials between various types of oil;
|
|
15.
|
Inability to obtain new customers or retain existing ones;
|
|
16.
|
Significant changes in competitive factors affecting the Company;
|
|
17.
|
Changes in laws and regulations to which the Company is subject,
including tax, environmental, safety and employment laws and
regulations;
|
|
18.
|
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 natural gas), affiliate relationships,
industry structure, franchise renewal, and environmental/safety
requirements;
|
|
19.
|
Unanticipated impacts of restructuring initiatives in the
natural gas and electric industries;
|
|
20.
|
Significant changes from expectations in actual capital
expenditures and operating expenses and unanticipated project
delays or changes in project costs or plans;
|
|
21.
|
The nature and projected profitability of pending and potential
projects and other investments, and the ability to obtain
necessary governmental approvals and permits;
|
|
22.
|
Ability to successfully identify and finance acquisitions or
other investments and ability to operate and integrate existing
and any subsequently acquired business or properties;
|
57
|
|
23.
|
Changes in the market price of timber and the impact such
changes might have on the types and quantity of timber harvested
by the Company;
|
|
24.
|
Significant changes in tax rates or policies or in rates of
inflation or interest;
|
|
25.
|
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;
|
|
26.
|
Changes in accounting principles or the application of such
principles to the Company;
|
|
27.
|
The cost and effects of legal and administrative claims against
the Company or activist shareholder campaigns to effect changes
at the Company;
|
|
28.
|
Increasing health care costs and the resulting effect on health
insurance premiums and on the obligation to provide other
post-retirement benefits; or
|
|
29.
|
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.
58
|
|
Item 8
|
Financial
Statements and Supplementary Data
|
Index
to Financial Statements
|
|
|
|
|
|
|
Page
|
|
Financial Statements:
|
|
|
|
|
|
|
|
|
|
|
|
|
60
|
|
|
|
|
61
|
|
|
|
|
62
|
|
|
|
|
63
|
|
|
|
|
64
|
|
|
|
|
65
|
|
Financial Statement Schedules:
|
|
|
|
|
For the three years ended September 30, 2008
|
|
|
|
|
|
|
|
115
|
|
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.
59
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, 2008 and 2007, and the
results of their operations and their cash flows for each of the
three years in the period ended September 30, 2008 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, 2008,
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 26, 2008
60
NATIONAL
FUEL GAS COMPANY
REINVESTED
IN THE BUSINESS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended September 30
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(Thousands of dollars, except per common
|
|
|
|
share amounts)
|
|
|
INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Revenues
|
|
$
|
2,400,361
|
|
|
$
|
2,039,566
|
|
|
$
|
2,239,675
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchased Gas
|
|
|
1,235,157
|
|
|
|
1,018,081
|
|
|
|
1,267,562
|
|
Operation and Maintenance
|
|
|
432,871
|
|
|
|
396,408
|
|
|
|
395,289
|
|
Property, Franchise and Other Taxes
|
|
|
75,585
|
|
|
|
70,660
|
|
|
|
69,202
|
|
Depreciation, Depletion and Amortization
|
|
|
170,623
|
|
|
|
157,919
|
|
|
|
151,999
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,914,236
|
|
|
|
1,643,068
|
|
|
|
1,884,052
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Income
|
|
|
486,125
|
|
|
|
396,498
|
|
|
|
355,623
|
|
Other Income (Expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from Unconsolidated Subsidiaries
|
|
|
6,303
|
|
|
|
4,979
|
|
|
|
3,583
|
|
Other Income
|
|
|
7,376
|
|
|
|
4,936
|
|
|
|
2,825
|
|
Interest Income
|
|
|
10,815
|
|
|
|
1,550
|
|
|
|
9,409
|
|
Interest Expense on Long-Term Debt
|
|
|
(70,099
|
)
|
|
|
(68,446
|
)
|
|
|
(72,629
|
)
|
Other Interest Expense
|
|
|
(3,870
|
)
|
|
|
(6,029
|
)
|
|
|
(5,952
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from Continuing Operations Before Income Taxes
|
|
|
436,650
|
|
|
|
333,488
|
|
|
|
292,859
|
|
Income Tax Expense
|
|
|
167,922
|
|
|
|
131,813
|
|
|
|
108,245
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from Continuing Operations
|
|
|
268,728
|
|
|
|
201,675
|
|
|
|
184,614
|
|
Discontinued Operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (Loss) from Operations, Net of Tax
|
|
|
|
|
|
|
15,479
|
|
|
|
(46,523
|
)
|
Gain on Disposal, Net of Tax
|
|
|
|
|
|
|
120,301
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (Loss) from Discontinued Operations, Net of Tax
|
|
|
|
|
|
|
135,780
|
|
|
|
(46,523
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income Available for Common Stock
|
|
|
268,728
|
|
|
|
337,455
|
|
|
|
138,091
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EARNINGS REINVESTED IN THE BUSINESS
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at Beginning of Year
|
|
|
983,776
|
|
|
|
786,013
|
|
|
|
813,020
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,252,504
|
|
|
|
1,123,468
|
|
|
|
951,111
|
|
Share Repurchases
|
|
|
(194,776
|
)
|
|
|
(38,196
|
)
|
|
|
(66,269
|
)
|
Cumulative Effect of Adoption of FIN 48
|
|
|
(406
|
)
|
|
|
|
|
|
|
|
|
Dividends on Common Stock
|
|
|
(103,523
|
)
|
|
|
(101,496
|
)
|
|
|
(98,829
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at End of Year
|
|
$
|
953,799
|
|
|
$
|
983,776
|
|
|
$
|
786,013
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings Per Common Share:
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic:
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from Continuing Operations
|
|
$
|
3.27
|
|
|
$
|
2.43
|
|
|
$
|
2.20
|
|
Income (Loss) from Discontinued Operations
|
|
|
|
|
|
|
1.63
|
|
|
|
(0.56
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income Available for Common Stock
|
|
$
|
3.27
|
|
|
$
|
4.06
|
|
|
$
|
1.64
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted:
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from Continuing Operations
|
|
$
|
3.18
|
|
|
$
|
2.37
|
|
|
$
|
2.15
|
|
Income (Loss) from Discontinued Operations
|
|
|
|
|
|
|
1.59
|
|
|
|
(0.54
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income Available for Common Stock
|
|
$
|
3.18
|
|
|
$
|
3.96
|
|
|
$
|
1.61
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted Average Common Shares Outstanding:
|
|
|
|
|
|
|
|
|
|
|
|
|
Used in Basic Calculation
|
|
|
82,304,335
|
|
|
|
83,141,640
|
|
|
|
84,030,118
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Used in Diluted Calculation
|
|
|
84,474,839
|
|
|
|
85,301,361
|
|
|
|
86,028,466
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See Notes to Consolidated Financial Statements
61
NATIONAL
FUEL GAS COMPANY
|
|
|
|
|
|
|
|
|
|
|
At September 30
|
|
|
|
2008
|
|
|
2007
|
|
|
|
(Thousands of dollars)
|
|
|
ASSETS
|
Property, Plant and Equipment
|
|
$
|
4,873,969
|
|
|
$
|
4,461,586
|
|
Less Accumulated Depreciation, Depletion and
Amortization
|
|
|
1,719,869
|
|
|
|
1,583,181
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,154,100
|
|
|
|
2,878,405
|
|
|
|
|
|
|
|
|
|
|
Current Assets
|
|
|
|
|
|
|
|
|
Cash and Temporary Cash Investments
|
|
|
68,239
|
|
|
|
124,806
|
|
Cash Held in Escrow
|
|
|
|
|
|
|
61,964
|
|
Hedging Collateral Deposits
|
|
|
1
|
|
|
|
4,066
|
|
Receivables Net of Allowance for Uncollectible
Accounts of $33,117 and $28,654, Respectively
|
|
|
185,397
|
|
|
|
172,380
|
|
Unbilled Utility Revenue
|
|
|
24,364
|
|
|
|
20,682
|
|
Gas Stored Underground
|
|
|
87,294
|
|
|
|
66,195
|
|
Materials and Supplies at average cost
|
|
|
31,317
|
|
|
|
35,669
|
|
Unrecovered Purchased Gas Costs
|
|
|
37,708
|
|
|
|
14,769
|
|
Other Current Assets
|
|
|
65,158
|
|
|
|
45,057
|
|
Deferred Income Taxes
|
|
|
|
|
|
|
8,550
|
|
|
|
|
|
|
|
|
|
|
|
|
|
499,478
|
|
|
|
554,138
|
|
|
|
|
|
|
|
|
|
|
Other Assets
|
|
|
|
|
|
|
|
|
Recoverable Future Taxes
|
|
|
82,506
|
|
|
|
83,954
|
|
Unamortized Debt Expense
|
|
|
13,978
|
|
|
|
12,070
|
|
Other Regulatory Assets
|
|
|
189,587
|
|
|
|
137,577
|
|
Deferred Charges
|
|
|
4,417
|
|
|
|
5,545
|
|
Other Investments
|
|
|
80,640
|
|
|
|
85,902
|
|
Investments in Unconsolidated Subsidiaries
|
|
|
16,279
|
|
|
|
18,256
|
|
Goodwill
|
|
|
5,476
|
|
|
|
5,476
|
|
Intangible Assets
|
|
|
26,174
|
|
|
|
28,836
|
|
Prepaid Pension and Other Post-Retirement Benefit Costs
|
|
|
21,034
|
|
|
|
61,006
|
|
Fair Value of Derivative Financial Instruments
|
|
|
28,786
|
|
|
|
9,188
|
|
Other
|
|
|
7,732
|
|
|
|
8,059
|
|
|
|
|
|
|
|
|
|
|
|
|
|
476,609
|
|
|
|
455,869
|
|
|
|
|
|
|
|
|
|
|
Total Assets
|
|
$
|
4,130,187
|
|
|
$
|
3,888,412
|
|
|
|
|
|
|
|
|
|
|
|
CAPITALIZATION AND LIABILITIES
|
Capitalization:
|
|
|
|
|
|
|
|
|
Comprehensive Shareholders Equity
|
|
|
|
|
|
|
|
|
Common Stock, $1 Par Value
|
|
|
|
|
|
|
|
|
Authorized 200,000,000 Shares; Issued and
Outstanding 79,120,544 Shares and
83,461,308 Shares, Respectively
|
|
$
|
79,121
|
|
|
$
|
83,461
|
|
Paid In Capital
|
|
|
567,716
|
|
|
|
569,085
|
|
Earnings Reinvested in the Business
|
|
|
953,799
|
|
|
|
983,776
|
|
|
|
|
|
|
|
|
|
|
Total Common Shareholders Equity Before Items Of
Other Comprehensive Income (Loss)
|
|
|
1,600,636
|
|
|
|
1,636,322
|
|
Accumulated Other Comprehensive Income (Loss)
|
|
|
2,963
|
|
|
|
(6,203
|
)
|
|
|
|
|
|
|
|
|
|
Total Comprehensive Shareholders Equity
|
|
|
1,603,599
|
|
|
|
1,630,119
|
|
Long-Term Debt, Net of Current Portion
|
|
|
999,000
|
|
|
|
799,000
|
|
|
|
|
|
|
|
|
|
|
Total Capitalization
|
|
|
2,602,599
|
|
|
|
2,429,119
|
|
|
|
|
|
|
|
|
|
|
Current and Accrued Liabilities
|
|
|
|
|
|
|
|
|
Notes Payable to Banks and Commercial Paper
|
|
|
|
|
|
|
|
|
Current Portion of Long-Term Debt
|
|
|
100,000
|
|
|
|
200,024
|
|
Accounts Payable
|
|
|
142,520
|
|
|
|
109,757
|
|
Amounts Payable to Customers
|
|
|
2,753
|
|
|
|
10,409
|
|
Dividends Payable
|
|
|
25,714
|
|
|
|
25,873
|
|
Interest Payable on Long-Term Debt
|
|
|
22,114
|
|
|
|
18,158
|
|
Customer Advances
|
|
|
33,017
|
|
|
|
22,863
|
|
Other Accruals and Current Liabilities
|
|
|
45,220
|
|
|
|
36,062
|
|
Deferred Income Taxes
|
|
|
1,871
|
|
|
|
|
|
Fair Value of Derivative Financial Instruments
|
|
|
1,362
|
|
|
|
16,200
|
|
|
|
|
|
|
|
|
|
|
|
|
|
374,571
|
|
|
|
439,346
|
|
|
|
|
|
|
|
|
|
|
Deferred Credits
|
|
|
|
|
|
|
|
|
Deferred Income Taxes
|
|
|
634,372
|
|
|
|
575,356
|
|
Taxes Refundable to Customers
|
|
|
18,449
|
|
|
|
14,026
|
|
Unamortized Investment Tax Credit
|
|
|
4,691
|
|
|
|
5,392
|
|
Cost of Removal Regulatory Liability
|
|
|
103,100
|
|
|
|
91,226
|
|
Other Regulatory Liabilities
|
|
|
91,933
|
|
|
|
76,659
|
|
Pension and Other Post-Retirement Liabilities
|
|
|
78,909
|
|
|
|
70,555
|
|
Asset Retirement Obligations
|
|
|
93,247
|
|
|
|
75,939
|
|
Other Deferred Credits
|
|
|
128,316
|
|
|
|
110,794
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,153,017
|
|
|
|
1,019,947
|
|
|
|
|
|
|
|
|
|
|
Commitments and Contingencies
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Capitalization and Liabilities
|
|
$
|
4,130,187
|
|
|
$
|
3,888,412
|
|
|
|
|
|
|
|
|
|
|
See Notes to Consolidated Financial Statements
62
NATIONAL
FUEL GAS COMPANY
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended September 30
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(Thousands of dollars)
|
|
|
Operating Activities
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income Available for Common Stock
|
|
$
|
268,728
|
|
|
$
|
337,455
|
|
|
$
|
138,091
|
|
Adjustments to Reconcile Net Income to Net Cash Provided by
Operating Activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Gain on Sale of Discontinued Operations
|
|
|
|
|
|
|
(159,873
|
)
|
|
|
|
|
Impairment of Oil and Gas Producing Properties
|
|
|
|
|
|
|
|
|
|
|
104,739
|
|
Depreciation, Depletion and Amortization
|
|
|
170,623
|
|
|
|
170,803
|
|
|
|
179,615
|
|
Deferred Income Taxes
|
|
|
72,496
|
|
|
|
52,847
|
|
|
|
(5,230
|
)
|
Income from Unconsolidated Subsidiaries, Net of Cash
Distributions
|
|
|
1,977
|
|
|
|
(3,366
|
)
|
|
|
1,067
|
|
Excess Tax Benefits Associated with Stock-Based Compensation
Awards
|
|
|
(16,275
|
)
|
|
|
(13,689
|
)
|
|
|
(6,515
|
)
|
Other
|
|
|
4,858
|
|
|
|
16,399
|
|
|
|
4,829
|
|
Change in:
|
|
|
|
|
|
|
|
|
|
|
|
|
Hedging Collateral Deposits
|
|
|
4,065
|
|
|
|
15,610
|
|
|
|
58,108
|
|
Receivables and Unbilled Utility Revenue
|
|
|
(16,815
|
)
|
|
|
5,669
|
|
|
|
(12,343
|
)
|
Gas Stored Underground and Materials and Supplies
|
|
|
(22,116
|
)
|
|
|
(5,714
|
)
|
|
|
1,679
|
|
Unrecovered Purchased Gas Costs
|
|
|
(22,939
|
)
|
|
|
(1,799
|
)
|
|
|
1,847
|
|
Prepayments and Other Current Assets
|
|
|
(36,376
|
)
|
|
|
18,800
|
|
|
|
(39,572
|
)
|
Accounts Payable
|
|
|
32,763
|
|
|
|
(26,002
|
)
|
|
|
(23,144
|
)
|
Amounts Payable to Customers
|
|
|
(7,656
|
)
|
|
|
(13,526
|
)
|
|
|
22,777
|
|
Customer Advances
|
|
|
10,154
|
|
|
|
(6,554
|
)
|
|
|
4,946
|
|
Other Accruals and Current Liabilities
|
|
|
(3,641
|
)
|
|
|
8,950
|
|
|
|
(17,754
|
)
|
Other Assets
|
|
|
(11,887
|
)
|
|
|
4,109
|
|
|
|
(22,700
|
)
|
Other Liabilities
|
|
|
54,817
|
|
|
|
(5,922
|
)
|
|
|
80,960
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Cash Provided by Operating Activities
|
|
|
482,776
|
|
|
|
394,197
|
|
|
|
471,400
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investing Activities
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital Expenditures
|
|
|
(397,734
|
)
|
|
|
(276,728
|
)
|
|
|
(294,159
|
)
|
Investment in Partnership
|
|
|
|
|
|
|
(3,300
|
)
|
|
|
|
|
Net Proceeds from Sale of Foreign Subsidiaries
|
|
|
|
|
|
|
232,092
|
|
|
|
|
|
Cash Held in Escrow
|
|
|
58,397
|
|
|
|
(58,248
|
)
|
|
|
|
|
Net Proceeds from Sale of Oil and Gas Producing Properties
|
|
|
5,969
|
|
|
|
5,137
|
|
|
|
13
|
|
Other
|
|
|
4,376
|
|
|
|
(725
|
)
|
|
|
(3,230
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Cash Used in Investing Activities
|
|
|
(328,992
|
)
|
|
|
(101,772
|
)
|
|
|
(297,376
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Financing Activities
|
|
|
|
|
|
|
|
|
|
|
|
|
Excess Tax Benefits Associated with Stock-Based Compensation
Awards
|
|
|
16,275
|
|
|
|
13,689
|
|
|
|
6,515
|
|
Shares Repurchased under Repurchase Plan
|
|
|
(237,006
|
)
|
|
|
(48,070
|
)
|
|
|
(85,168
|
)
|
Net Proceeds from Issuance of Long-Term Debt
|
|
|
296,655
|
|
|
|
|
|
|
|
|
|
Reduction of Long-Term Debt
|
|
|
(200,024
|
)
|
|
|
(119,576
|
)
|
|
|
(9,805
|
)
|
Net Proceeds from Issuance of Common Stock
|
|
|
17,432
|
|
|
|
17,498
|
|
|
|
23,339
|
|
Dividends Paid on Common Stock
|
|
|
(103,683
|
)
|
|
|
(100,632
|
)
|
|
|
(98,266
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Cash Used in Financing Activities
|
|
|
(210,351
|
)
|
|
|
(237,091
|
)
|
|
|
(163,385
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Effect of Exchange Rates on Cash
|
|
|
|
|
|
|
(139
|
)
|
|
|
1,365
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Increase (Decrease) in Cash and Temporary Cash
Investments
|
|
|
(56,567
|
)
|
|
|
55,195
|
|
|
|
12,004
|
|
Cash and Temporary Cash Investments At Beginning of Year
|
|
|
124,806
|
|
|
|
69,611
|
|
|
|
57,607
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and Temporary Cash Investments At End of Year
|
|
$
|
68,239
|
|
|
$
|
124,806
|
|
|
$
|
69,611
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Supplemental Disclosure of Cash Flow Information
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash Paid For:
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
|
|
$
|
69,841
|
|
|
$
|
75,987
|
|
|
$
|
78,003
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income Taxes
|
|
$
|
103,154
|
|
|
$
|
97,961
|
|
|
$
|
54,359
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See Notes to Consolidated Financial Statements
63
NATIONAL
FUEL GAS COMPANY
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended September 30
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(Thousands of dollars)
|
|
|
Net Income Available for Common Stock
|
|
$
|
268,728
|
|
|
$
|
337,455
|
|
|
$
|
138,091
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Comprehensive Income (Loss), Before Tax:
|
|
|
|
|
|
|
|
|
|
|
|
|
Minimum Pension Liability Adjustment
|
|
|
|
|
|
|
|
|
|
|
165,914
|
|
Decrease in the Funded Status of the Pension and Other
Post-Retirement Benefit Plans
|
|
|
(13,584
|
)
|
|
|
|
|
|
|
|
|
Reclassification Adjustment for Amortization of Prior Year
Funded Status of the Pension and Other Post-Retirement Benefit
Plans
|
|
|
1,924
|
|
|
|
|
|
|
|
|
|
Foreign Currency Translation Adjustment
|
|
|
12
|
|
|
|
7,874
|
|
|
|
7,408
|
|
Reclassification Adjustment for Realized Foreign Currency
Translation Gain in Net Income
|
|
|
|
|
|
|
(42,658
|
)
|
|
|
(716
|
)
|
Unrealized Gain (Loss) on Securities Available for Sale Arising
During the Period
|
|
|
(4,856
|
)
|
|
|
4,747
|
|
|
|
2,573
|
|
Unrealized Gain (Loss) on Derivative Financial Instruments
Arising During the Period
|
|
|
(31,490
|
)
|
|
|
8,495
|
|
|
|
90,196
|
|
Reclassification Adjustment for Realized Losses on Derivative
Financial Instruments in Net Income
|
|
|
64,645
|
|
|
|
5,106
|
|
|
|
91,743
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Comprehensive Income (Loss), Before Tax
|
|
|
16,651
|
|
|
|
(16,436
|
)
|
|
|
357,118
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income Tax Expense Related to Minimum Pension Liability
Adjustment
|
|
|
|
|
|
|
|
|
|
|
58,070
|
|
Income Tax Benefit Related to the Decrease in the Funded Status
of the Pension and Other Post-Retirement Benefit Plans
|
|
|
(5,127
|
)
|
|
|
|
|
|
|
|
|
Reclassification Adjustment for Income Tax Benefit Related to
the Amortization of the Prior Year Funded Status of the Pension
and Other Post-Retirement Benefit Plans
|
|
|
726
|
|
|
|
|
|
|
|
|
|
Income Tax Expense (Benefit) Related to Unrealized Gain (Loss)
on Securities Available for Sale Arising During the Period
|
|
|
(1,434
|
)
|
|
|
1,724
|
|
|
|
894
|
|
Income Tax Expense (Benefit) Related to Unrealized Gain (Loss)
on Derivative Financial Instruments Arising During the Period
|
|
|
(13,228
|
)
|
|
|
3,153
|
|
|
|
34,772
|
|
Reclassification Adjustment for Income Tax Benefit on Realized
Losses on Derivative Financial Instruments In Net Income
|
|
|
26,548
|
|
|
|
2,824
|
|
|
|
35,338
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income Taxes Net
|
|
|
7,485
|
|
|
|
7,701
|
|
|
|
129,074
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Comprehensive Income (Loss)
|
|
|
9,166
|
|
|
|
(24,137
|
)
|
|
|
228,044
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive Income
|
|
$
|
277,894
|
|
|
$
|
313,318
|
|
|
$
|
366,135
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See Notes to Consolidated Financial Statements
64
NATIONAL
FUEL GAS COMPANY
Note A
Summary of Significant Accounting Policies
Principles
of Consolidation
The Company consolidates its majority owned entities. The equity
method is used to account for minority owned entities. All
significant intercompany balances and transactions are
eliminated. The 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.
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.
Revenue
Recognition
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 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.
65
NATIONAL
FUEL GAS COMPANY
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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 warmer
than normal results in a surcharge being added to
customers current bills, while weather that is 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.
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 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
66
NATIONAL
FUEL GAS COMPANY
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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,
2008, 2007, and 2006, estimated future net cash flows were
increased by $34.5 million, $2.2 million and
$4.7 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
|
|
|
|
2008
|
|
|
2007
|
|
|
|
(Thousands)
|
|
|
Utility
|
|
$
|
1,580,366
|
|
|
$
|
1,539,808
|
|
Pipeline and Storage
|
|
|
996,743
|
|
|
|
976,316
|
|
Exploration and Production
|
|
|
1,800,422
|
|
|
|
1,577,745
|
|
Energy Marketing
|
|
|
1,232
|
|
|
|
1,199
|
|
Timber
|
|
|
120,021
|
|
|
|
119,237
|
|
All Other and Corporate
|
|
|
25,984
|
|
|
|
32,806
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
4,524,768
|
|
|
$
|
4,247,111
|
|
|
|
|
|
|
|
|
|
|
Average depreciation, depletion and amortization rates are as
follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended September 30
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
Utility
|
|
|
2.6
|
%
|
|
|
2.8
|
%
|
|
|
2.8
|
%
|
Pipeline and Storage
|
|
|
3.2
|
%
|
|
|
3.5
|
%
|
|
|
4.0
|
%
|
Exploration and Production, per Mcfe(1)
|
|
$
|
2.26
|
|
|
$
|
1.94
|
|
|
$
|
2.00
|
|
Energy Marketing
|
|
|
3.5
|
%
|
|
|
2.8
|
%
|
|
|
4.8
|
%
|
Timber
|
|
|
4.1
|
%
|
|
|
4.0
|
%
|
|
|
5.6
|
%
|
All Other and Corporate
|
|
|
5.0
|
%
|
|
|
4.6
|
%
|
|
|
4.1
|
%
|
67
NATIONAL
FUEL GAS COMPANY
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
(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 $2.23, $1.92 and $1.98 per Mcfe of
production in 2008, 2007 and 2006, respectively. Depletion of
oil and gas producing properties in the United States amounted
to $2.23, $1.97 and $1.74 per Mcfe of production in 2008, 2007
and 2006, respectively. Depletion of oil and gas producing
properties in Canada amounted $1.67 and $2.95 per Mcfe of
production in 2007 and 2006, respectively. |
Goodwill
The Company has recognized goodwill of $5.5 million as of
September 30, 2008 and 2007 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, 2008 and 2007, 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 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 2008 or 2006.
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 2008, 2007 or 2006.
68
NATIONAL
FUEL GAS COMPANY
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Accumulated
Other Comprehensive Income (Loss)
The components of Accumulated Other Comprehensive Income (Loss)
are as follows:
|
|
|
|
|
|
|
|
|
|
|
Year Ended September 30
|
|
|
|
2008
|
|
|
2007
|
|
|
|
(Thousands)
|
|
|
Funded Status of the Pension and Other Post-Retirement Benefit
Plans
|
|
$
|
(19,741
|
)
|
|
$
|
(12,482
|
)(1)
|
Cumulative Foreign Currency Translation Adjustment
|
|
|
(71
|
)
|
|
|
(83
|
)
|
Net Unrealized Gain (Loss) on Derivative Financial Instruments
|
|
|
15,949
|
|
|
|
(3,886
|
)
|
Net Unrealized Gain on Securities Available for Sale
|
|
|
6,826
|
|
|
|
10,248
|
|
|
|
|
|
|
|
|
|
|
Accumulated Other Comprehensive Income (Loss)
|
|
$
|
2,963
|
|
|
$
|
(6,203
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
In accordance with the transition recognition implementation
provisions of SFAS 158, the adjustment to recognize the
funded status 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, 2008, it is estimated that of the
$15.9 million net unrealized gain on derivative financial
instruments shown in the table above, $13.1 million will be
reclassified into the Consolidated Statement of Income during
2009. The remaining unrealized gain on derivative financial
instruments of $2.8 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.
The amounts included in accumulated other comprehensive income
(loss) related to the funded status of the Companys
pension and other post-retirement benefit plans consist of an
unrecognized transition obligation, prior service costs and
accumulated losses. The total unrecognized transition obligation
was $0.1 million at September 30, 2007 (nothing at
September 30, 2008). The total amount for prior service
costs was $0.4 million and $1.0 million at
September 30, 2008 and September 30, 2007,
respectively. The total amount for accumulated losses was
$19.3 million and $11.4 million at September 30,
2008 and September 30, 2007, respectively.
Gas
Stored Underground Current
In the Utility segment, gas stored underground
current in the amount of $34.1 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 2008, 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
$195.4 million at September 30, 2008. 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.
69
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 an adequate 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
|
|
|
|
2008
|
|
|
2007
|
|
|
|
(Thousands)
|
|
|
Materials and Supplies
|
|
$
|
9,911
|
|
|
$
|
8,925
|
|
Other Assets
|
|
|
7,383
|
|
|
|
5,641
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
17,294
|
|
|
$
|
14,566
|
|
|
|
|
|
|
|
|
|
|
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 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.
At September 30, 2008, the Company accrued
$16.8 million of capital expenditures related to the
construction of the Empire Connector project. This amount has
been excluded from the Consolidated Statement of Cash Flows at
September 30, 2008 since it represents a non-cash investing
activity at that date.
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.
70
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 was a Canadian dollar denominated account. On a
U.S. dollar basis, the value of this account was
$62.0 million at September 30, 2007. In December 2007,
the Canadian government issued the tax clearance certificate,
thereby releasing the proceeds from restriction as of
December 31, 2007. To hedge against foreign currency
exchange risk related to the cash being held in escrow, the
Company held a forward contract to sell Canadian dollars. For
presentation purposes on the Consolidated Statement of Cash
Flows, for the year ended September 30, 2008, the Cash Held
in Escrow line item within Investing Activities reflects the net
proceeds to the Company (received on January 8,
2008) after adjusting for the impact of the foreign
currency hedge.
Other
Current Assets
Other Current Assets consist of prepayments in the amounts of
$10.6 million and $14.1 million at September 30,
2008 and 2007, respectively, prepaid property and other taxes of
$11.2 million and $14.1 million at September 30,
2008 and 2007, respectively, federal income taxes receivable in
the amounts of $27.5 million and $8.7 million at
September 30, 2008 and 2007, respectively, state income
taxes receivable in the amounts of $5.0 million and zero at
September 30, 2008 and 2007, respectively, and fair values
of firm commitments in the amounts of $10.9 million and
$8.2 million at September 30, 2008 and 2007,
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. For purposes of
determining earnings per common share, 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 2008, there were 7,344
stock-settled SARs excluded as being antidilutive, and there
were no stock options excluded as being antidilutive. 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.
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
71
NATIONAL
FUEL GAS COMPANY
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
after the date of each grant. Restricted stock is subject to
restrictions on vesting and transferability. Restricted stock
awards entitle the participants to full dividend and voting
rights. Certificates for shares of restricted stock awarded
under the Companys stock option and stock award plans are
held by the Company during the periods in which the restrictions
on vesting are effective. Restrictions on restricted stock
awards generally lapse ratably over a period of not more than
ten years after the date of each grant.
Prior to October 1, 2005, the Company accounted for its
stock-based compensation under the recognition and measurement
principles of APB 25 and related interpretations. Under that
method, no compensation expense was recognized for options
granted under the Companys stock option and stock award
plans. The Company did record, in accordance with APB 25,
compensation expense for the market value of restricted stock on
the date of the award over the periods during which the vesting
restrictions existed.
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 no stock options granted during
the year ended September 30, 2008. There were 448,000 and
317,000 stock options granted during the years ended
September 30, 2007 and 2006, respectively. The Company
granted 321,000 performance based stock-settled SARs during the
year ended September 30, 2008. There were no performance
based stock-settled SARs granted during the year ended
September 30, 2007. The Company granted 50,000
non-performance based stock-settled SARs during the year ended
September 30, 2007. There were no non-performance based
stock-settled SARs granted during the year ended
September 30, 2008. There were no performance based or
non-performance based stock-settled SARs granted during the year
ended September 30, 2006. The accounting treatment for such
performance based and non-performance based stock-settled SARs
is the same under SFAS 123R as the accounting for stock
options under SFAS 123R. The performance based
stock-settled SARs granted for the year ended September 30,
2008 vest and become exercisable annually, in one-third
increments, provided that a performance condition for diluted
earnings per share is met for the prior fiscal year. The
weighted average grant date fair value of the performance based
stock-settled SARs granted during 2008 was estimated on the date
of grant using the same accounting treatment that is applied for
stock options under SFAS 123R, and assumes that the
performance conditions specified will be achieved. If such
conditions are not met, no compensation expense is recognized
and any recognized compensation expense is reversed. The Company
also granted 25,000, 25,000 and 16,000 restricted share awards
(non-vested stock as defined by SFAS 123R) during the years
ended September 30, 2008, 2007 and 2006, respectively.
Stock-based compensation expense for the years ended
September 30, 2008, 2007 and 2006 was approximately
$2,332,000, $3,727,000, and $1,705,000, 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, 2008, 2007 and
2006 was approximately $945,000, $1,488,000 and $653,000,
respectively. There were no capitalized stock-based compensation
costs during the years ended September 30, 2008 and 2007.
72
NATIONAL
FUEL GAS COMPANY
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Stock
Options
The total intrinsic value of stock options exercised during the
years ended September 30, 2008, 2007 and 2006 totaled
approximately $24.6 million, $38.7 million, and
$30.9 million, respectively. For 2008, 2007 and 2006, the
amount of cash received by the Company from the exercise of such
stock options was approximately $18.5 million,
$26.0 million, and $30.1 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, 2007, 2006, and 2005, the
Company realized a tax benefit of $4.4 million,
$3.2 million, and $0.9 million, respectively. For
stock options exercised during the period of January 1,
2008 through September 30, 2008, the Company will realize a
tax benefit of approximately $4.3 million in the quarter
ended December 31, 2008. For stock options exercised during
the period of January 1, 2007 through September 30,
2007, the Company realized 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. The weighted average grant date fair
value of options granted in 2007 and 2006 is $7.27 per share and
$6.68 per share, respectively. For the years ended
September 30, 2008, 2007 and 2006, 358,000, 327,501 and
89,665 stock options became fully vested, respectively. The
total fair value of these stock options was approximately
$2.6 million, $2.1 million and $0.4 million,
respectively, for the years ended September 30, 2008, 2007
and 2006. As of September 30, 2008, unrecognized
compensation expense related to stock options totaled
approximately $0.3 million, which will be recognized over a
weighted average period of 8.6 months. For a summary of
transactions during 2008 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 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
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
Risk Free Interest Rate
|
|
|
N/A
|
|
|
|
4.46
|
%
|
|
|
5.08
|
%
|
Expected Life (Years)
|
|
|
N/A
|
|
|
|
7.0
|
|
|
|
7.0
|
|
Expected Volatility
|
|
|
N/A
|
|
|
|
17.73
|
%
|
|
|
17.71
|
%
|
Expected Dividend Yield (Quarterly)
|
|
|
N/A
|
|
|
|
0.76
|
%
|
|
|
0.83
|
%
|
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 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.
Non-Performance
Based Stock-settled SARs
There were no non-performance based stock-settled SARs exercised
during the years ended September 30, 2008, 2007 and 2006 as
none of the non-performance based stock-settled SARs granted
have vested. There were 50,000 non-performance based
stock-settled SARs granted during 2007. The weighted average
grant date fair value of non-performance based stock-settled
SARs granted in 2007 is $7.81 per share. There were no
non-performance based stock-settled SARs granted during 2008 or
2006. As of September 30, 2008, unrecognized compensation
expense related to non-performance based stock-settled SARs
totaled approximately $0.2 million, which will be
recognized over a weighted average period of 10.2 months.
For a summary of transactions during
73
NATIONAL
FUEL GAS COMPANY
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
2008 involving non-performance based stock-settled SARs for all
plans, refer to Note E Capitalization and
Short-Term Borrowings.
The fair value of non-performance based 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 non-performance based stock-settled SARs. 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.
Performance
Based Stock-settled SARs
There were no performance based stock-settled SARs exercised
during the years ended September 30, 2008, 2007 and 2006 as
none of the performance based stock-settled SARs granted have
vested. There were 321,000 performance based stock-settled SARs
granted during 2008. The weighted average grant date fair value
of performance based stock-settled SARs granted in 2008 is $9.06
per share. There were no performance based stock-settled SARs
granted during 2007 or 2006. For the years ended
September 30, 2008, 2007 and 2006, there were no
performance based stock-settled SARs that became fully vested.
As of September 30, 2008, unrecognized compensation expense
related to performance based stock-settled SARs totaled
approximately $1.9 million, which will be recognized over a
weighted average period of 1.1 years. For a summary of
transactions during 2008 involving performance based
stock-settled SARs for all plans, refer to
Note E Capitalization and Short-Term Borrowings.
The fair value of performance based 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,
|
|
|
|
2008
|
|
|
Risk Free Interest Rate
|
|
|
3.78
|
%
|
Expected Life (Years)
|
|
|
7.25
|
|
Expected Volatility
|
|
|
17.69
|
%
|
Expected Dividend Yield (Quarterly)
|
|
|
0.64
|
%
|
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 performance based stock-settled SARs. The expected life
and expected volatility are based on historical experience.
For grants during the year ended September 30, 2008, it was
assumed that there would be no forfeitures, based on the vesting
term and the number of grantees.
74
NATIONAL
FUEL GAS COMPANY
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Restricted
Share Awards
The weighted average fair value of restricted share awards
granted in 2008, 2007 and 2006 is $48.41 per share, $40.18 per
share and $34.94 per share, respectively. As of
September 30, 2008, unrecognized compensation expense
related to restricted share awards totaled approximately
$1.6 million, which will be recognized over a weighted
average period of 2.5 years. For a summary of transactions
during 2008 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 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. In accordance with
FASB Staff Position
FAS No. 157-2,
SFAS 157 is effective for financial assets and financial
liabilities that are recognized or disclosed at fair value on a
recurring basis as of the Companys first quarter of fiscal
2009. The same FASB Staff Position delays the effective date for
nonfinancial assets and nonfinancial liabilities, except for
items that are recognized or disclosed at fair value on a
recurring basis, until the Companys first quarter of
fiscal 2010. The Company does not expect that SFAS 157 will
have a significant impact 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 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.
75
NATIONAL
FUEL GAS COMPANY
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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 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 does
not plan to elect the fair value measurement option for any of
its financial instruments other than those that are already
being measured at fair value.
In December 2007, the FASB issued SFAS 141R, Business
Combinations. SFAS 141R will significantly change the
accounting for business combinations in a number of areas
including the treatment of contingent consideration,
contingencies, acquisition costs, in process research and
development and restructuring costs. In addition, under
SFAS 141R, changes in deferred tax asset valuation
allowances and acquired income tax uncertainties in a business
combination after the measurement period will impact income tax
expense. SFAS 141R is effective as of the Companys
first quarter of fiscal 2010.
In December 2007, the FASB issued SFAS 160,
Noncontrolling Interests in Consolidated Financial
Statements, an Amendment of ARB 51. SFAS 160 will
change the accounting and reporting for minority interests,
which will be recharacterized as noncontrolling interests (NCI)
and classified as a component of equity. This new consolidation
method will significantly change the accounting for transactions
with minority interest holders. SFAS 160 is effective as of
the Companys first quarter of fiscal 2010. The Company
currently does not have any NCI.
In March 2008, the FASB issued SFAS 161, Disclosures
about Derivative Instruments and Hedging Activities, an
Amendment of SFAS 133. SFAS 161 requires
entities to provide enhanced disclosures related to an
entitys derivative instruments and hedging activities in
order to enable investors to better understand how derivative
instruments and hedging activities impact an entitys
financial reporting. The additional disclosures include how and
why an entity uses derivative instruments, how derivative
instruments and related hedged items are accounted for under
SFAS 133 and its related interpretations, and how
derivative instruments and related hedged items affect an
entitys financial position, financial performance, and
cash flows. SFAS 161 is effective as of the Companys
second quarter of fiscal 2009. The Company is currently
evaluating the impact that the adoption of SFAS 161 will
have on its disclosures in the notes to the 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
76
NATIONAL
FUEL GAS COMPANY
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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 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, 2008 and 2007, the costs of removal
reclassified to other regulatory liabilities amounted to
$103.1 million and $91.2 million, respectively.
A reconciliation of the Companys asset retirement
obligation calculated in accordance with SFAS 143 is shown
below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended September 30
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
|
|
|
(Thousands)
|
|
|
|
|
|
Balance at Beginning of Year
|
|
$
|
75,939
|
|
|
$
|
77,392
|
|
|
$
|
41,411
|
|
Additions Adoption of FIN 47
|
|
|
|
|
|
|
|
|
|
|
23,234
|
|
Liabilities Incurred and Revisions of Estimates
|
|
|
18,739
|
|
|
|
(932
|
)
|
|
|
11,244
|
|
Liabilities Settled
|
|
|
(6,871
|
)
|
|
|
(6,108
|
)
|
|
|
(1,303
|
)
|
Accretion Expense
|
|
|
5,440
|
|
|
|
5,394
|
|
|
|
2,671
|
|
Exchange Rate Impact
|
|
|
|
|
|
|
193
|
|
|
|
135
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at End of Year
|
|
$
|
93,247
|
|
|
$
|
75,939
|
|
|
$
|
77,392
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
77
NATIONAL
FUEL GAS COMPANY
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
Note C
|
Regulatory
Matters
|
Regulatory
Assets and Liabilities
The Company has recorded the following regulatory assets and
liabilities:
|
|
|
|
|
|
|
|
|
|
|
At September 30
|
|
|
|
2008
|
|
|
2007
|
|
|
|
(Thousands)
|
|
|
Regulatory Assets(1):
|
|
|
|
|
|
|
|
|
Pension and Other Post-Retirement Benefit Costs(2) (Note G)
|
|
$
|
147,909
|
|
|
$
|
98,787
|
|
Recoverable Future Taxes (Note D)
|
|
|
82,506
|
|
|
|
83,954
|
|
Unrecovered Purchased Gas Costs (See Regulatory Mechanisms in
Note A)
|
|
|
37,708
|
|
|
|
14,769
|
|
Environmental Site Remediation Costs(2) (Note H)
|
|
|
22,530
|
|
|
|
20,738
|
|
Asset Retirement Obligations(2) (Note B)
|
|
|
8,155
|
|
|
|
8,315
|
|
Unamortized Debt Expense (Note A)
|
|
|
7,524
|
|
|
|
8,470
|
|
Recoverable Worker Compensation Expense(2)
|
|
|
4,518
|
|
|
|
4,445
|
|
Other(2)
|
|
|
6,475
|
|
|
|
5,292
|
|
|
|
|
|
|
|
|
|
|
Total Regulatory Assets
|
|
|
317,325
|
|
|
|
244,770
|
|
|
|
|
|
|
|
|
|
|
Regulatory Liabilities:
|
|
|
|
|
|
|
|
|
Cost of Removal Regulatory Liability (Note B)
|
|
|
103,100
|
|
|
|
91,226
|
|
Pension and Other Post-Retirement Benefit Costs(3) (Note G)
|
|
|
42,994
|
|
|
|
21,676
|
|
Tax Benefit on Medicare Part D Subsidy(3)
|
|
|
23,502
|
|
|
|
19,147
|
|
New York Rate Settlements(3)
|
|
|
19,012
|
|
|
|
27,964
|
|
Taxes Refundable to Customers (Note D)
|
|
|
18,449
|
|
|
|
14,026
|
|
Deferred Insurance Proceeds(3)
|
|
|
3,933
|
|
|
|
7,422
|
|
Amounts Payable to Customers (See Regulatory Mechanisms in
Note A)
|
|
|
2,753
|
|
|
|
10,409
|
|
Other(3)
|
|
|
2,492
|
|
|
|
450
|
|
|
|
|
|
|
|
|
|
|
Total Regulatory Liabilities
|
|
|
216,235
|
|
|
|
192,320
|
|
|
|
|
|
|
|
|
|
|
Net Regulatory Position
|
|
$
|
101,090
|
|
|
$
|
52,450
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
The Company recovers the cost of its regulatory assets but, with
the exception of Unrecovered Purchased Gas Costs, does not earn
a return on them. |
|
(2) |
|
Included in Other Regulatory Assets on the Consolidated Balance
Sheets. |
|
(3) |
|
Included in Other Regulatory Liabilities on the Consolidated
Balance Sheets. |
If for any reason the Company ceases to meet the criteria for
application of regulatory accounting treatment for all or part
of its operations, the regulatory assets and liabilities related
to those portions ceasing to meet such criteria would be
eliminated from the balance sheet and included in income of the
period in which the discontinuance of regulatory accounting
treatment occurs. Such amounts would be classified as an
extraordinary item.
78
NATIONAL
FUEL GAS COMPANY
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
New
York Rate Settlements
With respect to utility services provided in New York, the
Company has entered into rate settlements approved by the NYPSC.
The rate settlements have given rise to several significant
liabilities, which are described as follows:
Gross Receipts Tax Over-Collections In accordance
with NYPSC policies, Distribution Corporation deferred the
difference between the revenues it collects under a New York
State gross receipts tax surcharge and its actual New York State
income tax expense. Distribution Corporations cumulative
gross receipts tax revenues exceeded its New York State income
tax expense, resulting in a regulatory liability at
September 30, 2008 and 2007 of $4.1 million and
$6.7 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 was 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, 2008 and 2007
amounted to $0.3 million and $7.4 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, 2008 and 2007
amounted to $3.0 million and $3.6 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 $11.6 million and
$10.3 million at September 30, 2008 and 2007,
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
The Company, in its Utility and Pipeline and Storage segments,
has deferred environmental insurance settlement proceeds
amounting to $3.9 million and $7.4 million at
September 30, 2008 and 2007, respectively. 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.
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.
79
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
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
|
|
|
(Thousands)
|
|
|
|
|
|
Current Income Taxes
|
|
|
|
|
|
|
|
|
|
|
|
|
Federal
|
|
$
|
75,079
|
|
|
$
|
99,608
|
|
|
$
|
65,593
|
|
State
|
|
|
20,257
|
|
|
|
21,700
|
|
|
|
13,511
|
|
Foreign
|
|
|
90
|
|
|
|
22
|
|
|
|
2,212
|
|
Deferred Income Taxes
|
|
|
|
|
|
|
|
|
|
|
|
|
Federal
|
|
|
56,668
|
|
|
|
39,340
|
|
|
|
19,111
|
|
State
|
|
|
15,828
|
|
|
|
10,751
|
|
|
|
9,024
|
|
Foreign
|
|
|
|
|
|
|
2,756
|
|
|
|
(33,365
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
167,922
|
|
|
|
174,177
|
|
|
|
76,086
|
|
Deferred Investment Tax Credit
|
|
|
(697
|
)
|
|
|
(697
|
)
|
|
|
(697
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Income Taxes
|
|
$
|
167,225
|
|
|
$
|
173,480
|
|
|
$
|
75,389
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Presented as Follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Income
|
|
$
|
(697
|
)
|
|
$
|
(697
|
)
|
|
$
|
(697
|
)
|
Income Tax Expense Continuing Operations
|
|
|
167,922
|
|
|
|
131,813
|
|
|
|
108,245
|
|
Discontinued Operations
|
|
|
|
|
|
|
|
|
|
|
|
|
Income From Operations
|
|
|
|
|
|
|
2,792
|
|
|
|
(32,159
|
)
|
Gain on Disposal
|
|
|
|
|
|
|
39,572
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Income Taxes
|
|
$
|
167,225
|
|
|
$
|
173,480
|
|
|
$
|
75,389
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The U.S. and foreign components of income (loss) before
income taxes are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended September 30
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
|
|
|
(Thousands)
|
|
|
|
|
|
U.S.
|
|
$
|
435,982
|
|
|
$
|
496,074
|
|
|
$
|
293,887
|
|
Foreign
|
|
|
(29
|
)
|
|
|
14,861
|
|
|
|
(80,407
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
435,953
|
|
|
$
|
510,935
|
|
|
$
|
213,480
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
80
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
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
|
|
|
(Thousands)
|
|
|
|
|
|
Income Tax Expense, Computed at U.S. Federal Statutory Rate of
35%
|
|
$
|
152,584
|
|
|
$
|
178,827
|
|
|
$
|
74,718
|
|
Increase in Taxes Resulting from:
|
|
|
|
|
|
|
|
|
|
|
|
|
State Income Taxes
|
|
|
23,455
|
|
|
|
21,093
|
|
|
|
14,648
|
|
Foreign Tax Differential
|
|
|
69
|
|
|
|
(20,980
|
)
|
|
|
(3,718
|
)
|
Reversal of Capital Loss Valuation Allowance
|
|
|
|
|
|
|
|
|
|
|
(2,877
|
)
|
Miscellaneous
|
|
|
(8,883
|
)
|
|
|
(5,460
|
)
|
|
|
(7,382
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Income Taxes
|
|
$
|
167,225
|
|
|
$
|
173,480
|
|
|
$
|
75,389
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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. 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
|
|
|
|
2008
|
|
|
2007
|
|
|
|
(Thousands)
|
|
|
Deferred Tax Liabilities:
|
|
|
|
|
|
|
|
|
Property, Plant and Equipment
|
|
$
|
673,313
|
|
|
$
|
612,648
|
|
Pension and Other Post-Retirement Benefit Costs
SFAS 158
|
|
|
43,340
|
|
|
|
21,892
|
|
Other
|
|
|
55,391
|
|
|
|
39,724
|
|
|
|
|
|
|
|
|
|
|
Total Deferred Tax Liabilities
|
|
|
772,044
|
|
|
|
674,264
|
|
|
|
|
|
|
|
|
|
|
Deferred Tax Assets:
|
|
|
|
|
|
|
|
|
Pension and Other Post-Retirement Benefit Costs
SFAS 158
|
|
|
(43,340
|
)
|
|
|
(21,892
|
)
|
Other
|
|
|
(92,461
|
)
|
|
|
(85,566
|
)
|
|
|
|
|
|
|
|
|
|
Total Deferred Tax Assets
|
|
|
(135,801
|
)
|
|
|
(107,458
|
)
|
|
|
|
|
|
|
|
|
|
Total Net Deferred Income Taxes
|
|
$
|
636,243
|
|
|
$
|
566,806
|
|
|
|
|
|
|
|
|
|
|
Presented as Follows:
|
|
|
|
|
|
|
|
|
Net Deferred Tax Liability/(Asset) Current
|
|
$
|
1,871
|
|
|
$
|
(8,550
|
)
|
Net Deferred Tax Liability Non-Current
|
|
|
634,372
|
|
|
|
575,356
|
|
|
|
|
|
|
|
|
|
|
Total Net Deferred Income Taxes
|
|
$
|
636,243
|
|
|
$
|
566,806
|
|
|
|
|
|
|
|
|
|
|
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 $18.4 million and $14.0 million at
September 30, 2008 and 2007, 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
$82.5 million and $84.0 million at September 30,
2008 and 2007, respectively.
81
NATIONAL
FUEL GAS COMPANY
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The Company adopted FIN 48 on October 1, 2007. As of
the date of adoption, a cumulative effect adjustment was
recorded that resulted in a decrease to retained earnings of
$0.4 million. Upon adoption, the unrecognized tax benefits
were $1.7 million, all of which would impact the effective
tax rate (net of federal benefit) if recognized.
A tabular reconciliation of the change in unrecognized tax
benefits for the twelve months ended September 30, 2008 is
as follows:
|
|
|
|
|
|
|
Amount
|
|
|
|
(thousands)
|
|
|
Opening Balance of Unrecognized Tax Benefits
October 1, 2007
|
|
$
|
1,700
|
|
Gross Increase Tax Positions in Prior Periods
|
|
|
|
|
Gross Decrease Tax Positions in Prior Periods
|
|
|
|
|
Gross Increase Tax Positions in Current Periods
|
|
|
|
|
Gross Decrease Tax Positions in Current Periods
|
|
|
|
|
Decrease in Unrecognized Tax Benefits Related to Tax Settlements
|
|
|
|
|
Reduction to Unrecognized Tax Benefits Due to Lapse of Statute
of Limitations
|
|
|
|
|
|
|
|
|
|
Ending Balance of Unrecognized Tax Benefits
September 30, 2008
|
|
$
|
1,700
|
|
|
|
|
|
|
Within the next twelve months, the Company believes it is
reasonably possible that the total amount of unrecognized tax
benefits may be eliminated. This potential decrease in the
amount of unrecognized tax benefits is associated with the
anticipated completion of state income tax audits for various
prior years.
The Company recognizes estimated interest payable relating to
income taxes in Other Interest Expense and estimated penalties
relating to income taxes in Other Income. The Company has
accrued interest of $0.5 million through September 30,
2008 and has not accrued any penalties.
The Company files U.S. federal and various state income tax
returns. The Internal Revenue Service (IRS) is currently
conducting an examination of the Company for fiscal 2008 in
accordance with the Compliance Assurance Process
(CAP). The CAP audit employs a real time review of
the Companys books and tax records by the IRS that is
intended to permit issue resolution prior to the filing of the
tax return. While the federal statute of limitations remains
open for fiscal 2005 and later years, IRS examinations for
fiscal 2007 and prior years have been completed and the Company
believes such years are effectively settled.
For the major states in which the various subsidiary companies
operate, the earliest tax year open for examination is as
follows:
|
|
|
New York
|
|
Fiscal 2002
|
Pennsylvania
|
|
Fiscal 2003
|
California
|
|
Fiscal 2004
|
Texas
|
|
Fiscal 2004
|
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, 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
|
|
|
|
(6,203
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income Available for Common Stock
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
268,728
|
|
|
|
|
|
Dividends Declared on Common Stock ($1.27 Per Share)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(103,523
|
)
|
|
|
|
|
Cumulative Effect of the Adoption of FIN 48
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(406
|
)
|
|
|
|
|
Other Comprehensive Loss, Net of Tax
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
9,166
|
|
Share-Based Payment Expense(2)
|
|
|
|
|
|
|
|
|
|
|
2,332
|
|
|
|
|
|
|
|
|
|
Common Stock Issued Under Stock and Benefit Plans(1)
|
|
|
854
|
|
|
|
854
|
|
|
|
33,335
|
|
|
|
|
|
|
|
|
|
Share Repurchases
|
|
|
(5,194
|
)
|
|
|
(5,194
|
)
|
|
|
(37,036
|
)
|
|
|
(194,776
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at September 30, 2008
|
|
|
79,121
|
|
|
$
|
79,121
|
|
|
$
|
567,716
|
|
|
$
|
953,799
|
(3)
|
|
$
|
2,963
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Paid in Capital includes tax benefits of $16.3 million,
$13.7 million and $6.5 million for September 30,
2008, 2007 and 2006, 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,
2008, $808.8 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 2008, the Company issued 890,944 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 2008, 72,205 shares of
common stock were tendered to the Company for such purposes. The
Company considers all shares tendered as cancelled shares
restored to the status of authorized but unissued shares, in
accordance with New Jersey law.
The Company also has a director stock program under which it
issues shares of Company common stock to the non-employee
directors of the Company who receive compensation under the
Companys Retainer Policy for Non-Employee Directors, as
partial consideration for their services as directors. Under
this program, the Company issued 9,600 original issue shares of
common stock during 2008.
In December 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 eight million shares in the
open market or through privately negotiated transactions. The
Company completed the repurchase of the eight million shares
during 2008 for a total program cost of $324.2 million (of
which 4,165,122 shares were repurchased during the year
ended September 30, 2008 for $191.0 million). In
September 2008, the Companys Board of Directors authorized
the repurchase of an additional eight million shares. Under this
new authorization, the Company repurchased 1,028,981 shares
for $46.0 million through September 17, 2008. The
Company stopped repurchasing shares after September 17,
2008 in light of the unsettled nature of the credit markets.
However, such repurchases may be made in the future if
conditions improve. All share repurchases mentioned above were
funded with cash provided by operating activities
and/or
through the use of the Companys lines of credit.
Shareholder
Rights Plan
In 1996, the Companys Board of Directors adopted a
shareholder rights plan (Plan). The Plan has been amended five
times since it was adopted and is now embodied in an Amended and
Restated Rights Agreement effective July 11, 2008, 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 is initially
evidenced by the Companys common stock certificates
representing the outstanding shares of common stock.
The Rights have anti-takeover effects because they will cause
substantial dilution of the Companys common stock if a
person attempts to acquire the Company on terms not approved by
the Board of Directors (an Acquiring Person).
The Rights become exercisable upon the occurrence of a
Distribution Date as described below, but after a Distribution
Date Rights that are owned by an Acquiring Person will be null
and void. At any time following a
84
NATIONAL
FUEL GAS COMPANY
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Distribution Date, each holder of a Right may exercise its right
to receive a number of shares of common stock determined in
accordance with a Plan formula that is based on the current
market value of the Companys common stock. Under certain
circumstances, each holder of a Right may instead receive other
property of the Company. 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
(including Synthetic Long Positions as defined in the Plan)
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 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 a
number of shares of common stock determined in accordance with a
Plan formula based on the current market value of the
Companys common stock, or other property of the Company.
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 Distribution Date, 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 Distribution Date,
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.
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, 2018, unless
earlier than that date, they are exchanged or redeemed or the
Plan is amended to extend the expiration date.
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, 2007
|
|
|
7,360,041
|
|
|
$
|
25.89
|
|
|
|
|
|
|
|
|
|
Granted in 2008
|
|
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
Exercised in 2008
|
|
|
(890,944
|
)
|
|
$
|
23.78
|
|
|
|
|
|
|
|
|
|
Forfeited in 2008
|
|
|
(4,400
|
)
|
|
$
|
27.97
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at September 30, 2008
|
|
|
6,464,697
|
|
|
$
|
26.17
|
|
|
|
3.11
|
|
|
$
|
103,477
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Option shares exercisable at September 30, 2008
|
|
|
6,337,697
|
|
|
$
|
25.94
|
|
|
|
3.02
|
|
|
$
|
102,909
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Option shares available for future grant at September 30,
2008(1)
|
|
|
745,797
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Including shares available for stock-settled SARs and restricted
stock grants. |
Transactions involving non-performance based 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, 2007
|
|
|
50,000
|
|
|
$
|
41.20
|
|
|
|
|
|
|
|
|
|
Granted in 2008
|
|
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
Exercised in 2008
|
|
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
Forfeited in 2008
|
|
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at September 30, 2008
|
|
|
50,000
|
|
|
$
|
41.20
|
|
|
|
8.45
|
|
|
$
|
49
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock-settled SARs exercisable at September 30, 2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
86
NATIONAL
FUEL GAS COMPANY
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Transactions involving performance based 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, 2007
|
|
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
Granted in 2008
|
|
|
321,000
|
|
|
$
|
48.46
|
|
|
|
|
|
|
|
|
|
Exercised in 2008
|
|
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
Forfeited in 2008
|
|
|
(6,000
|
)
|
|
$
|
58.99
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at September 30, 2008
|
|
|
315,000
|
|
|
$
|
48.26
|
|
|
|
9.42
|
|
|
$
|
(1,914
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock-settled SARs exercisable at September 30, 2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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, 2007
|
|
|
36,328
|
|
|
$
|
38.16
|
|
Granted in 2008
|
|
|
25,000
|
|
|
$
|
48.41
|
|
Vested in 2008
|
|
|
(2,500
|
)
|
|
$
|
34.94
|
|
Forfeited in 2008
|
|
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
Restricted Share Awards Outstanding at September 30, 2008
|
|
|
58,828
|
|
|
$
|
42.65
|
|
|
|
|
|
|
|
|
|
|
Vesting restrictions for the outstanding shares of non-vested
restricted stock at September 30, 2008 will lapse as
follows: 2009 2,500 shares; 2010
28,828 shares; 2011
2,500 shares; 2012 5,000 shares;
2013 5,000 shares; 2014
5,000 shares; 2015 5,000 shares; and
2016 5,000 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
|
|
|
|
2008
|
|
|
2007
|
|
|
|
(Thousands)
|
|
|
Medium-Term Notes(1):
|
|
|
|
|
|
|
|
|
6.0% to 7.50% due March 2009 to June 2025
|
|
$
|
549,000
|
|
|
$
|
749,000
|
|
Notes(1):
|
|
|
|
|
|
|
|
|
5.25% to 6.5% due March 2013 to September 2022(2)
|
|
|
550,000
|
|
|
|
250,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,099,000
|
|
|
|
999,000
|
|
|
|
|
|
|
|
|
|
|
Other Notes:
|
|
|
|
|
|
|
|
|
Unsecured
|
|
|
|
|
|
|
24
|
|
|
|
|
|
|
|
|
|
|
Total Long-Term Debt
|
|
|
1,099,000
|
|
|
|
999,024
|
|
Less Current Portion
|
|
|
100,000
|
|
|
|
200,024
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
999,000
|
|
|
$
|
799,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
The medium-term notes and notes are unsecured. |
|
(2) |
|
In April 2008, the Company issued $300.0 million of
6.50% senior, unsecured notes in a private placement exempt
from registration under the Securities Act of 1933. The notes
have a term of 10 years, with a maturity date in April
2018. The holders of the notes may require the Company to
repurchase their notes in the event of a change in control at a
price equal to 101% of the principal amount. In addition, the
Company is required to either offer to exchange the notes for
substantially similar notes registered under the Securities Act
of 1933 or, in certain circumstances, register the resale of the
notes. The Company used $200.0 million of the proceeds from
the sale of the notes to refund $200.0 million of 6.303%
medium-term notes that subsequently matured on May 27, 2008. |
As of September 30, 2008, the aggregate principal amounts
of long-term debt maturing during the next five years and
thereafter are as follows: $100.0 million in 2009, zero in
2010, $200.0 million in 2011, $150.0 million in 2012,
$250.0 million in 2013, and $399.0 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 uncommitted credit lines, which aggregate to
$420.0 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, 2008 and 2007, 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 through
September 30, 2010. At September 30, 2008, the
Companys debt to capitalization ratio (as calculated under
the facility) was .41. The constraints specified in the
committed credit facility would permit an additional
$1.88 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 committed
credit facility, 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, 2008, the Company would have been permitted
to issue up to a maximum of $1.3 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
$199.0 million (or 18%) of the Companys long-term
debt (as of September 30, 2008) 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, 2008, 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
|
|
|
|
2008 Carrying
|
|
|
2008 Fair
|
|
|
2007 Carrying
|
|
|
2007 Fair
|
|
|
|
Amount
|
|
|
Value
|
|
|
Amount
|
|
|
Value
|
|
|
|
(Thousands)
|
|
|
Long-Term Debt
|
|
$
|
1,099,000
|
|
|
$
|
1,027,098
|
|
|
$
|
999,024
|
|
|
$
|
1,024,417
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 or net
present value 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 include cash surrender values of insurance
contracts (net present value in the case of split-dollar
collateral assignment arrangements) and marketable equity
securities. The values of the insurance contracts amounted to
$53.6 million and $54.7 million at September 30,
2008 and 2007, respectively. The fair value of the equity mutual
fund was $12.4 million and $14.7 million at
September 30, 2008 and 2007, respectively. The gross
unrealized loss on this equity mutual fund was
$(1.0) million at September 30, 2008. The equity
mutual fund was in a gross unrealized gain position of
$2.2 million at September 30, 2007. The fair value of
the stock of an insurance company was $14.5 million and
$16.3 million at September 30, 2008 and 2007,
respectively. The gross unrealized gain on this stock was
$12.1 million and $13.8 million at September 30,
2008 and 2007, 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, 2008, the Company had natural gas price swap
agreements covering a notional amount of 15.1 Bcf extending
through 2011 at a weighted average fixed rate of $9.69 per Mcf.
Of this amount, 0.9 Bcf is accounted for as fair value
hedges at a weighted average fixed rate of $9.64 per Mcf. The
remaining 14.2 Bcf are accounted for as cash flow hedges at
a weighted average fixed rate of $9.69 per Mcf. At
September 30, 2008, the Company would have received a net
$20.3 million to terminate the price swap agreements. The
Company also had crude oil price swap agreements covering a
notional amount of 1,920,000 bbls extending through 2011 at a
weighted average fixed rate of $90.50 per bbl. At
September 30, 2008, the Company would have had to pay a net
$0.8 million to terminate the price swap agreements. The
Energy Marketing segment also used natural gas swaps to hedge
basis risk on their fixed price purchase commitments. At
September 30, 2008, the Company had natural gas swap
agreements covering 1.4 Bcf at a weighted average fixed
rate of $0.47 per Mcf. These are treated as fair value hedges
and the Company would have had to pay $0.2 million at
September 30, 2008 to terminate the agreements.
At September 30, 2008, the Company had long (purchased)
futures contracts covering 9.1 Bcf of gas extending through
2012 at a weighted average contract price of $9.24 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 $9.9 million to terminate these
futures contracts at September 30, 2008.
90
NATIONAL
FUEL GAS COMPANY
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
At September 30, 2008, the Company had short (sold) futures
contracts covering 6.7 Bcf of gas extending through 2010 at
a weighted average contract price of $11.02 per Mcf. Of this
amount, 3.5 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 3.2 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
$18.6 million to terminate these futures contracts at
September 30, 2008.
The Company may be exposed to credit risk on any of the
derivative financial instruments that are in a gain position.
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, 2008, the Company had eleven
counterparties for its over the counter derivative financial
instruments and no individual counterparty represented greater
than 42% of total credit risk (measured as volumes hedged by an
individual counterparty as a percentage of the Companys
total over the counter volumes hedged). The Company recorded a
$0.6 million reduction to the fair market value of its
derivative contracts that are in a gain position based on its
assessment of counterparty credit risk. This credit reserve was
determined by applying default probabilities to the anticipated
cash flows that the Company is expecting from its counterparties.
|
|
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 65% of the employees of the Company. The
Retirement Plan covers certain non-collectively bargained
employees hired before July 1, 2003 and certain
collectively bargained employees hired before November 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 $0.6 million through September 30, 2008
(with $0.2 million, $0.2 million and $0.1 million
of costs occurring in 2008, 2007 and 2006, respectively). Costs
associated with the Companys contributions to the
Tax-Deferred Savings Plans were $4.0 million,
$4.1 million, and $4.1 million for the years ended
September 30, 2008, 2007 and 2006, respectively.
The Company provides health care and life insurance benefits
(other post-retirement benefits) for a majority of its retired
employees. The other post-retirement benefits cover certain
non-collectively bargained employees hired before
January 1, 2003 and certain collectively bargained
employees hired before October 31, 2003.
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 other
post-retirement benefits. 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 other post-retirement benefits, as well as
benefits as they are paid to current retirees. In addition, the
Company has established 401(h) accounts for its other
post-retirement benefits. They are separate accounts within the
Retirement Plan used to pay retiree medical benefits for the
associated participants in the Retirement Plan. Although these
accounts are in the Retirement Plan, for funding status purposes
as shown below, the 401(h) accounts are included in Fair Value
of Assets under Other Post-Retirement Benefits. Contributions
are tax-deductible when made, subject to limitations contained
in the Internal Revenue Code and regulations. Retirement Plan,
VEBA trust and 401(h) account assets primarily consist of equity
and fixed income investments or units in commingled funds or
money market funds.
91
NATIONAL
FUEL GAS COMPANY
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The expected return on plan assets, a component of net periodic
benefit cost shown in the tables below, is applied to the
market-related value of plan assets. The market-related value of
plan assets is 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 other post-retirement benefits are shown in the tables
below. The date used to measure the Benefit Obligations, Plan
Assets and Funded Status is June 30, 2008, 2007 and 2006,
respectively.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Retirement Plan
|
|
|
Other Post-Retirement Benefits
|
|
|
|
Year Ended September 30
|
|
|
Year Ended September 30
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(Thousands)
|
|
|
Change in Benefit Obligation
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Benefit Obligation at Beginning of Period
|
|
$
|
742,519
|
|
|
$
|
732,207
|
|
|
$
|
825,204
|
|
|
$
|
444,545
|
|
|
$
|
445,931
|
|
|
$
|
546,273
|
|
Service Cost
|
|
|
12,597
|
|
|
|
12,898
|
|
|
|
16,416
|
|
|
|
5,104
|
|
|
|
5,614
|
|
|
|
8,029
|
|
Interest Cost
|
|
|
44,949
|
|
|
|
44,350
|
|
|
|
40,196
|
|
|
|
27,081
|
|
|
|
27,198
|
|
|
|
26,804
|
|
Plan Participants Contributions
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,990
|
|
|
|
1,566
|
|
|
|
1,559
|
|
Retiree Drug Subsidy Receipts
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,532
|
|
|
|
1,325
|
|
|
|
|
|
Amendments(1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(31,874
|
)
|
|
|
|
|
|
|
|
|
Actuarial (Gain) Loss
|
|
|
(34,189
|
)
|
|
|
(2,986
|
)
|
|
|
(108,112
|
)
|
|
|
(14,390
|
)
|
|
|
(14,450
|
)
|
|
|
(115,052
|
)
|
Benefits Paid
|
|
|
(46,817
|
)
|
|
|
(43,950
|
)
|
|
|
(41,497
|
)
|
|
|
(22,443
|
)
|
|
|
(22,639
|
)
|
|
|
(21,682
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Benefit Obligation at End of Period
|
|
$
|
719,059
|
|
|
$
|
742,519
|
|
|
$
|
732,207
|
|
|
$
|
411,545
|
|
|
$
|
444,545
|
|
|
$
|
445,931
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Change in Plan Assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value of Assets at Beginning of Period
|
|
$
|
765,144
|
|
|
$
|
664,521
|
|
|
$
|
616,462
|
|
|
$
|
412,371
|
|
|
$
|
325,624
|
|
|
$
|
271,636
|
|
Actual Return on Plan Assets
|
|
|
(39,206
|
)
|
|
|
119,662
|
|
|
|
68,649
|
|
|
|
(43,478
|
)
|
|
|
65,552
|
|
|
|
34,785
|
|
Employer Contributions
|
|
|
3,817
|
|
|
|
16,488
|
|
|
|
20,907
|
|
|
|
29,200
|
|
|
|
42,268
|
|
|
|
39,326
|
|
Employer Contributions During Period from Measurement Date to
Fiscal Year End
|
|
|
12,151
|
|
|
|
8,423
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Plan Participants Contributions
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,990
|
|
|
|
1,566
|
|
|
|
1,559
|
|
Benefits Paid
|
|
|
(46,817
|
)
|
|
|
(43,950
|
)
|
|
|
(41,497
|
)
|
|
|
(22,443
|
)
|
|
|
(22,639
|
)
|
|
|
(21,682
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value of Assets at End of Period
|
|
$
|
695,089
|
|
|
$
|
765,144
|
|
|
$
|
664,521
|
|
|
$
|
377,640
|
|
|
$
|
412,371
|
|
|
$
|
325,624
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reconciliation of Funded Status
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Funded Status
|
|
$
|
(23,970
|
)
|
|
$
|
22,625
|
|
|
$
|
(67,686
|
)
|
|
$
|
(33,905
|
)
|
|
$
|
(32,174
|
)
|
|
$
|
(120,307
|
)
|
Unrecognized Net Actuarial Loss
|
|
|
|
|
|
|
|
|
|
|
107,626
|
|
|
|
|
|
|
|
|
|
|
|
54,487
|
|
Unrecognized Transition Obligation
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
49,890
|
|
Unrecognized Prior Service Cost
|
|
|
|
|
|
|
|
|
|
|
7,185
|
|
|
|
|
|
|
|
|
|
|
|
12
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Amount Recognized at End of Period
|
|
$
|
(23,970
|
)
|
|
$
|
22,625
|
|
|
$
|
47,125
|
|
|
$
|
(33,905
|
)
|
|
$
|
(32,174
|
)
|
|
$
|
(15,918
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(Thousands)
|
|
|
Amounts Recognized in the Balance Sheets Consist of:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accrued Benefit Liability
|
|
$
|
(23,970
|
)
|
|
$
|
|
|
|
$
|
|
|
|
$
|
(54,939
|
)
|
|
$
|
(70,555
|
)
|
|
$
|
(32,918
|
)
|
Prepaid Benefit Cost
|
|
|
|
|
|
|
22,625
|
|
|
|
47,125
|
|
|
|
21,034
|
|
|
|
38,381
|
|
|
|
17,000
|
|
Intangible Assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated Other Comprehensive Loss from Additional Minimum
Pension Liability Adjustment (Pre-Tax)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Amount Recognized at End of Period
|
|
$
|
(23,970
|
)
|
|
$
|
22,625
|
|
|
$
|
47,125
|
|
|
$
|
(33,905
|
)
|
|
$
|
(32,174
|
)
|
|
$
|
(15,918
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted Average Assumptions Used to Determine Benefit
Obligation at September 30
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Discount Rate
|
|
|
6.75
|
%
|
|
|
6.25
|
%
|
|
|
6.25
|
%
|
|
|
6.75
|
%
|
|
|
6.25
|
%
|
|
|
6.25
|
%
|
Expected Return on Plan Assets
|
|
|
8.25
|
%
|
|
|
8.25
|
%
|
|
|
8.25
|
%
|
|
|
8.25
|
%
|
|
|
8.25
|
%
|
|
|
8.25
|
%
|
Rate of Compensation Increase
|
|
|
5.00
|
%
|
|
|
5.00
|
%
|
|
|
5.00
|
%
|
|
|
5.00
|
%
|
|
|
5.00
|
%
|
|
|
5.00
|
%
|
Components of Net Periodic Benefit Cost
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Service Cost
|
|
$
|
12,598
|
|
|
$
|
12,898
|
|
|
$
|
16,416
|
|
|
$
|
5,104
|
|
|
$
|
5,614
|
|
|
$
|
8,029
|
|
Interest Cost
|
|
|
44,949
|
|
|
|
44,350
|
|
|
|
40,196
|
|
|
|
27,081
|
|
|
|
27,198
|
|
|
|
26,804
|
|
Expected Return on Plan Assets
|
|
|
(55,000
|
)
|
|
|
(51,235
|
)
|
|
|
(49,943
|
)
|
|
|
(33,715
|
)
|
|
|
(26,960
|
)
|
|
|
(22,302
|
)
|
Amortization of Prior Service Cost
|
|
|
808
|
|
|
|
882
|
|
|
|
957
|
|
|
|
4
|
|
|
|
4
|
|
|
|
4
|
|
Amortization of Transition Amount
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
7,127
|
|
|
|
7,127
|
|
|
|
7,127
|
|
Recognition of Actuarial Loss(2)
|
|
|
11,063
|
|
|
|
13,528
|
|
|
|
23,108
|
|
|
|
2,927
|
|
|
|
8,214
|
|
|
|
23,402
|
|
Net Amortization and Deferral for Regulatory Purposes
|
|
|
6,008
|
|
|
|
1,211
|
|
|
|
(6,409
|
)
|
|
|
22,264
|
|
|
|
16,220
|
|
|
|
(11,084
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Periodic Benefit Cost
|
|
$
|
20,426
|
|
|
$
|
21,634
|
|
|
$
|
24,325
|
|
|
$
|
30,792
|
|
|
$
|
37,417
|
|
|
$
|
31,980
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Comprehensive (Income) Loss (Pre-Tax) Attributable to
Change In Additional Minimum Liability Recognition
|
|
$
|
|
|
|
$
|
|
|
|
$
|
(165,914
|
)
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated Other Comprehensive Loss (Pre-Tax) Attributable to
Adoption of SFAS 158
|
|
|
NA
|
|
|
$
|
11,256
|
|
|
|
NA
|
|
|
|
NA
|
|
|
$
|
778
|
|
|
|
NA
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted Average Assumptions Used to Determine Net Periodic
Benefit Cost 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
|
%
|
93
NATIONAL
FUEL GAS COMPANY
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
(1) |
|
In Fiscal 2008, the Company passed an amendment, for most of the
subsidiaries, which increased the participant contributions for
active employees at the time of the amendment. This decreased
the benefit obligation. |
|
(2) |
|
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. |
The Net Periodic Benefit Cost in the table above includes the
effects of regulation. The Company recovers pension and other
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 other 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 other 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, previously
unrecognized prior service costs, and a previously unrecognized
transition obligation 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 as of 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 Other 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 Other
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 Other 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 Other
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 Other 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. |
In order to adjust the funded status of its pension and other
post-retirement
benefit plans at September 30, 2008, the Company recorded a
$57.2 million increase to Other Regulatory Assets in the
Companys Utility and Pipeline and Storage segments and a
$7.3 million (net of deferred tax benefits of
$4.4 million) increase to Accumulated Other Comprehensive
Loss.
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 2008, as
well as the amounts expected to be recognized in net periodic
benefit cost in fiscal 2009 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)
|
|
$
|
(71,637
|
)
|
|
$
|
(53,108
|
)
|
|
$
|
(13,530
|
)
|
Transition Obligation
|
|
|
|
|
|
|
(11,326
|
)
|
|
|
|
|
Prior Service (Cost) Credit
|
|
|
(5,495
|
)
|
|
|
7,561
|
|
|
|
(11
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Amount Recognized
|
|
$
|
(77,132
|
)
|
|
$
|
(56,873
|
)
|
|
$
|
(13,541
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amounts Expected to be Recognized in Net Periodic Benefit
Cost in the Next Fiscal Year(1)
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Actuarial Gain/(Loss)
|
|
$
|
(5,676
|
)
|
|
$
|
(9,271
|
)
|
|
$
|
(1,322
|
)
|
Transition Obligation
|
|
|
|
|
|
|
(2,265
|
)
|
|
|
|
|
Prior Service (Cost) Credit
|
|
|
(731
|
)
|
|
|
1,074
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Amount Expected to be Recognized
|
|
$
|
(6,407
|
)
|
|
$
|
(10,462
|
)
|
|
$
|
(1,322
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(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 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 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:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(Thousands)
|
|
|
Projected Benefit Obligation
|
|
$
|
719,059
|
|
|
$
|
742,519
|
|
|
$
|
732,207
|
|
Accumulated Benefit Obligation
|
|
$
|
659,004
|
|
|
$
|
672,340
|
|
|
$
|
660,026
|
|
Fair Value of Plan Assets
|
|
$
|
695,089
|
|
|
$
|
765,144
|
|
|
$
|
664,520
|
|
The effect of the discount rate change for the Retirement Plan
in 2008 was to decrease the projected benefit obligation of the
Retirement Plan by $38.6 million. In 2008, other actuarial
experience increased the projected benefit obligation for the
Retirement Plan by $4.4 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.
96
NATIONAL
FUEL GAS COMPANY
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The Company made cash contributions totaling $16.0 million
to the Retirement Plan during the year ended September 30,
2008. The Company expects that the annual contribution to the
Retirement Plan in 2009 will be in the range of
$15.0 million to $20.0 million. As a result of the
recent downturn in the stock markets and general economic
conditions, it is likely that the Company will have to fund
larger amounts to the Retirement Plan subsequent to 2009 in
order to be in compliance with the Pension Protection Act of
2006. The following benefit payments, which reflect expected
future service, are expected to be paid during the next five
years and the five years thereafter: $50.5 million in 2009;
$51.0 million in 2010; $51.4 million in 2011;
$51.9 million in 2012; $52.9 million in 2013; and
$286.7 million in the five years thereafter.
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 $5.0 million,
$5.5 million and $5.4 million in 2008, 2007 and 2006,
respectively. At September 30, 2008, an $8.0 million
(pre-tax) loss was included in accumulated other comprehensive
income (loss) on the Consolidated Balance Sheet. This was first
recognized in 2007 upon 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. The accumulated benefit obligation for this
plan was $31.8 million and $28.8 million at
September 30, 2008 and 2007, respectively. The projected
benefit obligation for the plan was $47.5 million and
$43.8 million at September 30, 2008 and 2007,
respectively. The actuarial valuations for this plan were
determined based on a discount rate of 6.75%, 6.25% and 6.25% as
of September 30, 2008, 2007 and 2006, respectively; a rate
of compensation increase of 10.0% as of September 30, 2008,
2007 and 2006; and an expected long-term rate of return on plan
assets of 8.25% at September 30, 2008, 2007 and 2006.
The effect of the discount rate change in 2008 was to decrease
the other post-retirement benefit obligation by
$26.3 million. Effective July 1, 2008, 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 $20.0 million. Other actuarial
experience decreased the other post-retirement benefit
obligation in 2008 by $8.1 million.
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.
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 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.
97
NATIONAL
FUEL GAS COMPANY
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The estimated gross benefit payments and gross amount of subsidy
receipts are as follows:
|
|
|
|
|
|
|
|
|
|
|
Benefit Payments
|
|
|
Subsidy Receipts
|
|
|
2009
|
|
$
|
26,210,000
|
|
|
$
|
(1,714,000
|
)
|
2010
|
|
$
|
28,248,000
|
|
|
$
|
(1,942,000
|
)
|
2011
|
|
$
|
30,122,000
|
|
|
$
|
(2,167,000
|
)
|
2012
|
|
$
|
31,484,000
|
|
|
$
|
(2,437,000
|
)
|
2013
|
|
$
|
32,687,000
|
|
|
$
|
(2,719,000
|
)
|
2014 through 2018
|
|
$
|
181,354,000
|
|
|
$
|
(17,304,000
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
Rate of Increase for Pre Age 65 Participants
|
|
|
9.0
|
%(1)
|
|
|
8.0
|
%(2)
|
|
|
9.0
|
%(2)
|
Rate of Increase for Post Age 65 Participants
|
|
|
7.0
|
%(1)
|
|
|
6.67
|
%(2)
|
|
|
7.0
|
%(2)
|
Annual Rate of Increase in the Per Capita Cost of Covered
Prescription Drug Benefits
|
|
|
10.0
|
%(1)
|
|
|
10.0
|
%(2)
|
|
|
11.0
|
%(2)
|
Annual Rate of Increase in the Per Capita Medicare Part B
Reimbursement
|
|
|
7.0
|
%(1)
|
|
|
7.0
|
%(3)
|
|
|
5.25
|
%(4)
|
|
|
|
(1) |
|
It was assumed that this rate would gradually decline to 5.0% by
2018. |
|
(2) |
|
It was assumed that this rate would gradually decline to 5.0% by
2014. |
|
(3) |
|
It was assumed that this rate would gradually decline to 5.0% by
2016. |
|
(4) |
|
It was assumed that this rate would gradually decline to 5.0% by
2017. |
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, 2008
would increase by $45.1 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 2008
by $4.7 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, 2008 would decrease by
$38.4 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
$3.9 million.
The Company made cash contributions totaling $29.1 million
to the VEBA trusts and 401(h) accounts during the year ended
September 30, 2008. In addition, the Company made direct
payments of $0.1 million to retirees not covered by the
VEBA trusts and 401(h) accounts during the year ended
September 30, 2008. The Company expects that the annual
contribution to the VEBA trusts and 401(h) accounts in 2009 will
be in the range of $25.0 million to $30.0 million.
The Companys Retirement Plan weighted average asset
allocations (excluding the 401(h) accounts) at
September 30, 2008, 2007 and 2006 by asset category are as
follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Percentage of Plan
|
|
|
|
Target Allocation
|
|
|
Assets at September 30
|
|
Asset Category
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
Equity Securities
|
|
|
60-75
|
%
|
|
|
67
|
%
|
|
|
70
|
%
|
|
|
67
|
%
|
Fixed Income Securities
|
|
|
20-35
|
%
|
|
|
29
|
%
|
|
|
24
|
%
|
|
|
26
|
%
|
Other
|
|
|
0-15
|
%
|
|
|
4
|
%
|
|
|
6
|
%
|
|
|
7
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
|
|
|
100
|
%
|
|
|
100
|
%
|
|
|
100
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
98
NATIONAL
FUEL GAS COMPANY
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The Companys weighted average asset allocations for its
VEBA trusts and 401(h) accounts at September 30, 2008, 2007
and 2006 by asset category are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Percentage of Plan
|
|
|
|
Target Allocation
|
|
|
Assets at September 30
|
|
Asset Category
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
Equity Securities
|
|
|
85-100
|
%
|
|
|
93
|
%
|
|
|
95
|
%
|
|
|
95
|
%
|
Fixed Income Securities
|
|
|
0-15
|
%
|
|
|
2
|
%
|
|
|
1
|
%
|
|
|
1
|
%
|
Other
|
|
|
0-15
|
%
|
|
|
5
|
%
|
|
|
4
|
%
|
|
|
4
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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,
the VEBA trusts and the 401(h) accounts 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 Companys other
post-retirement benefits is 6.75% as of September 30, 2008.
The Company 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.
|
|
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, 2008, 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
$19.4 million to $23.6 million. The minimum estimated
liability of $19.4 million has been recorded on the
Consolidated Balance Sheet at September 30, 2008. The
Company expects to recover its environmental
clean-up
costs from a combination of rate recovery and deferred insurance
proceeds that are currently recorded as a regulatory liability
on the Consolidated Balance Sheet (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, changes in
environmental regulations, new information or other factors
could adversely impact the Company.
99
NATIONAL
FUEL GAS COMPANY
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
(i)
|
Former
Manufactured Gas Plant Sites
|
The Company has incurred investigation
and/or
clean-up
costs at several former manufactured gas plant sites in New York
and Pennsylvania. The Company continues to be responsible for
future ongoing monitoring and long-term maintenance at two sites.
With respect to another 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 Court dismissed the appeal in January 2008. The
Company filed a notice of appeal in February 2008. In July 2008,
the Company withdrew its appeal and, without admitting liability
or fault, agreed to the terms of an Order on Consent issued by
the NYDEC. Pursuant to the order, the Company will remediate the
site consistent with the remedy selected in the NYDECs
Record of Decision. The Company reimbursed the NYDEC in the
amount of approximately $1.5 million for costs incurred in
connection with the site from 1998 through May 30, 2007.
The Company acknowledged that additional charges related to the
site will be billed to the Company at a later date, including
costs incurred by the NYDEC after May 30, 2007 and any
costs incurred by the New York Department of Health. The Company
has not received and does not expect to receive any estimates of
such additional costs. The Company has submitted a Remedial
Design/Remedial Action work plan to the NYDEC in accordance with
the Order on Consent and has increased its recorded estimated
minimum liability for this site to $16.5 million.
In June 2007, the NYDEC notified the Company, as well as a
number of other companies, of their potential liability with
respect to a remedial action at a waste disposal site in New
York. The notification identified the Company as one of
approximately 500 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
participates in an organized group with other PRPs who are
addressing 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: $793.2 million in
2009, $168.0 million in 2010, $55.6 million in 2011,
$47.0 million in 2012, $21.6 million in 2013, and
$100.7 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: $6.0 million in 2009,
$4.6 million in 2010, $3.6 million in 2011,
$3.2 million in 2012, $2.5 million in 2013, and
$12.4 million thereafter.
100
NATIONAL
FUEL GAS COMPANY
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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 December
2008. As of September 30, 2008, the future contractual
commitments related to the construction of the Empire Connector
during 2009 is $13.5 million.
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
are they expected to have a material adverse effect on the
financial condition of the Company.
|
|
Note I
|
Discontinued
Operations
|
On August 31, 2007, the Company, in its Exploration and
Production segment, completed the sale of SECI, Senecas
wholly owned subsidiary that operated in Canada. 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. In December 2007, the Canadian government issued the
tax clearance certificate, thereby releasing the proceeds from
restriction as of December 31, 2007. 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,
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 Appalachia, the Gulf of Mexico,
and California. 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
|
|
|
|
(Thousands)
|
|
|
Operating Revenues
|
|
$
|
50,495
|
|
|
$
|
71,984
|
|
Operating Expenses
|
|
|
33,306
|
|
|
|
151,532
|
|
|
|
|
|
|
|
|
|
|
Operating Income (Loss)
|
|
|
17,189
|
|
|
|
(79,548
|
)
|
Interest Income
|
|
|
1,082
|
|
|
|
866
|
|
|
|
|
|
|
|
|
|
|
Income (Loss) before Income Taxes
|
|
|
18,271
|
|
|
|
(78,682
|
)
|
Income Tax Expense (Benefit)
|
|
|
2,792
|
|
|
|
(32,159
|
)
|
|
|
|
|
|
|
|
|
|
Income (Loss) from Discontinued Operations
|
|
|
15,479
|
|
|
|
(46,523
|
)
|
Gain on Disposal, Net of Taxes of $39,572
|
|
|
120,301
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (Loss) from Discontinued Operations
|
|
$
|
135,780
|
|
|
$
|
(46,523
|
)
|
|
|
|
|
|
|
|
|
|
101
NATIONAL
FUEL GAS COMPANY
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
Note J
|
Business
Segment Information
|
The Company reports financial results for five business
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 is constructing
the Empire Connector project, which consists of a compressor
station and a pipeline extension from near Rochester, New York
to an interconnection near Corning, New York with the
unaffiliated Millennium Pipeline. The Empire Connector is
anticipated to be ready to commence service in early December
2008, on or before the in-service date of the Millennium
Pipeline. 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.
The Energy Marketing segment is comprised of NFRs
operations. NFR markets natural gas to industrial, wholesale,
commercial, public authority and residential customers primarily
in western and central New York and northwestern Pennsylvania,
offering competitively priced natural gas for its customers.
The Timber segments operations are carried out by the
Northeast division of Seneca and by Highland. This segment has
timber holdings (primarily high quality hardwoods) in the
northeastern United States and sawmills and kilns in
Pennsylvania.
The data presented in the tables below reflect financial
information for the 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.
102
NATIONAL
FUEL GAS COMPANY
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended September 30, 2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Corporate
|
|
|
|
|
|
|
|
|
|
Pipeline
|
|
|
Exploration
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
|
|
and
|
|
|
|
|
|
|
|
|
|
and
|
|
|
and
|
|
|
Energy
|
|
|
|
|
|
Reported
|
|
|
All
|
|
|
Intersegment
|
|
|
Total
|
|
|
|
Utility
|
|
|
Storage
|
|
|
Production
|
|
|
Marketing
|
|
|
Timber
|
|
|
Segments
|
|
|
Other
|
|
|
Eliminations
|
|
|
Consolidated
|
|
|
|
(Thousands)
|
|
|
Revenue from External Customers
|
|
$
|
1,194,657
|
|
|
$
|
135,052
|
|
|
$
|
466,760
|
|
|
$
|
549,932
|
|
|
$
|
49,516
|
|
|
$
|
2,395,917
|
|
|
$
|
3,749
|
|
|
$
|
695
|
|
|
$
|
2,400,361
|
|
Intersegment Revenues
|
|
$
|
15,612
|
|
|
$
|
81,504
|
|
|
$
|
|
|
|
$
|
1,300
|
|
|
$
|
|
|
|
$
|
98,416
|
|
|
$
|
14,115
|
|
|
$
|
(112,531
|
)
|
|
$
|
|
|
Interest Income
|
|
$
|
1,836
|
|
|
$
|
843
|
|
|
$
|
10,921
|
|
|
$
|
323
|
|
|
$
|
1,053
|
|
|
$
|
14,976
|
|
|
$
|
179
|
|
|
$
|
(4,340
|
)
|
|
$
|
10,815
|
|
Interest Expense
|
|
$
|
27,683
|
|
|
$
|
13,783
|
|
|
$
|
41,645
|
|
|
$
|
175
|
|
|
$
|
3,142
|
|
|
$
|
86,428
|
|
|
$
|
640
|
|
|
$
|
(13,099
|
)
|
|
$
|
73,969
|
|
Depreciation, Depletion and Amortization
|
|
$
|
39,113
|
|
|
$
|
32,871
|
|
|
$
|
92,221
|
|
|
$
|
42
|
|
|
$
|
4,904
|
|
|
$
|
169,151
|
|
|
$
|
783
|
|
|
$
|
689
|
|
|
$
|
170,623
|
|
Income Tax Expense
|
|
$
|
36,303
|
|
|
$
|
34,008
|
|
|
$
|
92,686
|
|
|
$
|
3,180
|
|
|
$
|
(378
|
)
|
|
$
|
165,799
|
|
|
$
|
2,564
|
|
|
$
|
(441
|
)
|
|
$
|
167,922
|
|
Income from Unconsolidated Subsidiaries
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
6,303
|
|
|
$
|
|
|
|
$
|
6,303
|
|
Segment Profit: Net Income (Loss)
|
|
$
|
61,472
|
|
|
$
|
54,148
|
|
|
$
|
146,612
|
|
|
$
|
5,889
|
|
|
$
|
107
|
|
|
$
|
268,228
|
|
|
$
|
5,672
|
|
|
$
|
(5,172
|
)
|
|
$
|
268,728
|
|
Expenditures for Additions to Long-Lived Assets
|
|
$
|
57,457
|
|
|
$
|
165,520
|
|
|
$
|
192,187
|
|
|
$
|
39
|
|
|
$
|
1,354
|
|
|
$
|
416,557
|
|
|
$
|
131
|
|
|
$
|
(2,186
|
)
|
|
$
|
414,502
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
At September 30, 2008
|
|
|
|
(Thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment Assets
|
|
$
|
1,643,665
|
|
|
$
|
948,984
|
|
|
$
|
1,416,120
|
|
|
$
|
89,527
|
|
|
$
|
149,896
|
|
|
$
|
4,248,192
|
|
|
$
|
67,978
|
|
|
$
|
(185,983
|
)
|
|
$
|
4,130,187
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended September 30, 2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Corporate
|
|
|
|
|
|
|
|
|
|
Pipeline
|
|
|
Exploration
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
|
|
and
|
|
|
|
|
|
|
|
|
|
and
|
|
|
and
|
|
|
Energy
|
|
|
|
|
|
Reported
|
|
|
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
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended September 30, 2006
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Corporate
|
|
|
|
|
|
|
|
|
|
Pipeline
|
|
|
Exploration
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
|
|
and
|
|
|
|
|
|
|
|
|
|
and
|
|
|
and
|
|
|
Energy
|
|
|
|
|
|
Reported
|
|
|
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: 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
|
|
103
NATIONAL
FUEL GAS COMPANY
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
(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). |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For The Year Ended September 30
|
|
Geographic Information
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(Thousands)
|
|
|
Revenues from External Customers(1):
|
|
|
|
|
|
|
|
|
|
|
|
|
United States
|
|
$
|
2,400,361
|
|
|
$
|
2,039,566
|
|
|
$
|
2,239,675
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
At September 30
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(Thousands)
|
|
|
Long-Lived Assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
United States
|
|
$
|
3,630,709
|
|
|
$
|
3,334,274
|
|
|
$
|
3,181,769
|
|
Assets of Discontinued Operations
|
|
|
|
|
|
|
|
|
|
|
97,234
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
3,630,709
|
|
|
$
|
3,334,274
|
|
|
$
|
3,279,003
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Revenue is based upon the country in which the sale originates.
This table excludes revenues from Canadian discontinued
operations of $50,495 and $71,984 for September 30, 2007
and 2006, 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.
A summary of the Companys investments in unconsolidated
subsidiaries at September 30, 2008 and 2007 is as follows:
|
|
|
|
|
|
|
|
|
|
|
At September 30
|
|
|
|
2008
|
|
|
2007
|
|
|
|
(Thousands)
|
|
|
ESNE
|
|
$
|
3,958
|
|
|
$
|
4,652
|
|
Seneca Energy
|
|
|
10,589
|
|
|
|
12,033
|
|
Model City
|
|
|
1,732
|
|
|
|
1,571
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
16,279
|
|
|
$
|
18,256
|
|
|
|
|
|
|
|
|
|
|
104
NATIONAL
FUEL GAS COMPANY
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
Note L
|
Intangible
Assets
|
As a result of the Empire and Toro acquisitions, the Company
acquired certain intangible assets during 2003. In the case of
the Empire acquisition, the intangible assets represent the fair
value of various long-term transportation contracts with
Empires customers. In the case of the Toro acquisition,
the intangible assets represent the fair value of various
long-term gas purchase contracts with the various landfills.
These intangible assets are being amortized over the lives of
the transportation and gas purchase contracts with no residual
value at the end of the amortization period. The
weighted-average amortization period for the gross carrying
amount of the transportation contracts is 8 years. The
weighted-average amortization period for the gross carrying
amount of the gas purchase contracts is 20 years. Details
of these intangible assets are as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
At September 30,
|
|
|
|
At September 30, 2008
|
|
|
2007
|
|
|
|
Gross Carrying
|
|
|
Accumulated
|
|
|
Net Carrying
|
|
|
Net Carrying
|
|
|
|
Amount
|
|
|
Amortization
|
|
|
Amount
|
|
|
Amount
|
|
|
Intangible Assets Subject to Amortization:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-Term Transportation Contracts
|
|
$
|
8,580
|
|
|
$
|
(6,058
|
)
|
|
$
|
2,522
|
|
|
$
|
3,591
|
|
Long-Term Gas Purchase Contracts
|
|
|
31,864
|
|
|
|
(8,212
|
)
|
|
|
23,652
|
|
|
|
25,245
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
40,444
|
|
|
$
|
(14,270
|
)
|
|
$
|
26,174
|
|
|
$
|
28,836
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Aggregate Amortization Expense:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Year Ended September 30, 2008
|
|
$
|
2,662
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Year Ended September 30, 2007
|
|
$
|
2,662
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Year Ended September 30, 2006
|
|
$
|
2,662
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The gross carrying amount of intangible assets subject to
amortization at September 30, 2008 remained unchanged from
September 30, 2007. 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
$0.5 million in 2009, and $0.4 million in 2010, 2011,
2012 and 2013. Amortization expense for the long-term gas
purchase contracts is estimated to be $1.6 million annually
for 2009, 2010, 2011, 2012 and 2013.
|
|
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.
105
NATIONAL
FUEL GAS COMPANY
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
|
|
|
Income
|
|
|
Available
|
|
|
Earnings from
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
from
|
|
|
from
|
|
|
for
|
|
|
Continuing Operations per
|
|
|
|
|
|
|
|
Quarter
|
|
Operating
|
|
|
Operating
|
|
|
Continuing
|
|
|
Discontinued
|
|
|
Common
|
|
|
Common Share
|
|
|
Earnings per Common Share
|
|
Ended
|
|
Revenues
|
|
|
Income
|
|
|
Operations
|
|
|
Operations
|
|
|
Stock
|
|
|
Basic
|
|
|
Diluted
|
|
|
Basic
|
|
|
Diluted
|
|
|
|
(Thousands, except per common share amounts)
|
|
|
2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
9/30/2008
|
|
$
|
397,858
|
|
|
$
|
79,149
|
|
|
$
|
43,266
|
|
|
$
|
|
|
|
$
|
43,266
|
|
|
$
|
0.54
|
|
|
$
|
0.52
|
|
|
$
|
0.54
|
|
|
$
|
0.52
|
|
6/30/2008
|
|
$
|
548,382
|
|
|
$
|
110,947
|
|
|
$
|
59,855
|
|
|
$
|
|
|
|
$
|
59,855
|
|
|
$
|
0.74
|
|
|
$
|
0.72
|
|
|
$
|
0.74
|
|
|
$
|
0.72
|
|
3/31/2008
|
|
$
|
885,853
|
|
|
$
|
170,020
|
|
|
$
|
95,003
|
(1)
|
|
$
|
|
|
|
$
|
95,003
|
(1)
|
|
$
|
1.14
|
|
|
$
|
1.11
|
|
|
$
|
1.14
|
|
|
$
|
1.11
|
|
12/31/2007
|
|
$
|
568,268
|
|
|
$
|
126,009
|
|
|
$
|
70,604
|
|
|
$
|
|
|
|
$
|
70,604
|
|
|
$
|
0.84
|
|
|
$
|
0.82
|
|
|
$
|
0.84
|
|
|
$
|
0.82
|
|
2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
9/30/2007
|
|
$
|
302,030
|
|
|
$
|
73,504
|
|
|
$
|
34,295
|
|
|
$
|
123,395
|
(2)
|
|
$
|
157,690
|
(2)
|
|
$
|
0.41
|
|
|
$
|
0.40
|
|
|
$
|
1.89
|
|
|
$
|
1.84
|
|
6/30/2007
|
|
$
|
448,779
|
|
|
$
|
83,933
|
|
|
$
|
41,212
|
(3)
|
|
$
|
5,586
|
|
|
$
|
46,798
|
(3)
|
|
$
|
0.49
|
|
|
$
|
0.48
|
|
|
$
|
0.56
|
|
|
$
|
0.55
|
|
3/31/2007
|
|
$
|
798,100
|
|
|
$
|
142,404
|
|
|
$
|
75,480
|
(4)
|
|
$
|
2,967
|
|
|
$
|
78,447
|
(4)
|
|
$
|
0.91
|
|
|
$
|
0.89
|
|
|
$
|
0.95
|
|
|
$
|
0.92
|
|
12/31/2006
|
|
$
|
490,657
|
|
|
$
|
96,657
|
|
|
$
|
50,688
|
(5)
|
|
$
|
3,832
|
|
|
$
|
54,520
|
(5)
|
|
$
|
0.61
|
|
|
$
|
0.60
|
|
|
$
|
0.66
|
|
|
$
|
0.64
|
|
|
|
|
(1) |
|
Includes a $0.6 million gain on sale of turbine. |
|
(2) |
|
Includes a $120.3 million gain on the sale of SECI. |
|
(3) |
|
Includes $4.8 million of income associated with the
reversal of reserve for preliminary project costs associated
with the Empire Connector project. |
|
(4) |
|
Includes $2.3 million of income associated with the
reversal of a purchased gas expense accrual related to the
resolution of a contingency. |
|
(5) |
|
Includes a $1.9 million positive earnings impact associated
with the discontinuance of hedge accounting on an interest rate
collar. |
|
|
Note N
|
Market
for Common Stock and Related Shareholder Matters
(unaudited)
|
At September 30, 2008, there were 16,544 registered
shareholders of Company common stock. The common stock is listed
and traded on the New York Stock Exchange. Information related
to restrictions on the payment of dividends can be found in
Note E Capitalization and Short-Term
Borrowings. The quarterly price ranges (based on
intra-day
prices) and quarterly dividends declared for the fiscal years
ended September 30, 2008 and 2007, are shown below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Price Range
|
|
|
|
|
Quarter Ended
|
|
High
|
|
|
Low
|
|
|
Dividends Declared
|
|
|
2008
|
|
|
|
|
|
|
|
|
|
|
|
|
9/30/2008
|
|
$
|
60.36
|
|
|
$
|
39.16
|
|
|
$
|
.325
|
|
6/30/2008
|
|
$
|
63.71
|
|
|
$
|
47.00
|
|
|
$
|
.325
|
|
3/31/2008
|
|
$
|
48.78
|
|
|
$
|
38.04
|
|
|
$
|
.31
|
|
12/31/2007
|
|
$
|
50.29
|
|
|
$
|
45.20
|
|
|
$
|
.31
|
|
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
|
|
106
NATIONAL
FUEL GAS COMPANY
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
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
|
|
|
|
2008
|
|
|
2007
|
|
|
|
(Thousands)
|
|
|
Proved Properties(1)
|
|
$
|
1,783,276
|
|
|
$
|
1,583,956
|
|
Unproved Properties
|
|
|
23,285
|
|
|
|
20,005
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,806,561
|
|
|
|
1,603,961
|
|
Less Accumulated Depreciation, Depletion and
Amortization
|
|
|
718,166
|
|
|
|
627,073
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
1,088,395
|
|
|
$
|
976,888
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Includes asset retirement costs of $60.9 million and
$40.9 million at September 30, 2008 and 2007,
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, 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
as of
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
September 30,
|
|
|
Year Costs Incurred
|
|
|
|
2008
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
Prior
|
|
|
|
(Thousands)
|
|
|
Acquisition Costs
|
|
$
|
23,285
|
|
|
$
|
7,914
|
|
|
$
|
2,433
|
|
|
$
|
11,918
|
|
|
$
|
1,020
|
|
107
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
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(Thousands)
|
|
|
United States
|
|
|
|
|
|
|
|
|
|
|
|
|
Property Acquisition Costs:
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved
|
|
$
|
16,474
|
|
|
$
|
2,621
|
|
|
$
|
5,339
|
|
Unproved
|
|
|
8,449
|
|
|
|
3,210
|
|
|
|
8,844
|
|
Exploration Costs
|
|
|
56,274
|
|
|
|
26,891
|
|
|
|
64,087
|
|
Development Costs
|
|
|
106,975
|
|
|
|
113,206
|
|
|
|
87,738
|
|
Asset Retirement Costs
|
|
|
20,048
|
|
|
|
2,139
|
|
|
|
10,965
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
208,220
|
|
|
|
148,067
|
|
|
|
176,973
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canada Discontinued Operations
|
|
|
|
|
|
|
|
|
|
|
|
|
Property Acquisition Costs:
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved
|
|
|
|
|
|
|
(1,404
|
)
|
|
|
(427
|
)
|
Unproved
|
|
|
|
|
|
|
(1,142
|
)
|
|
|
6,492
|
|
Exploration Costs
|
|
|
|
|
|
|
20,134
|
|
|
|
20,778
|
|
Development Costs
|
|
|
|
|
|
|
11,414
|
|
|
|
14,385
|
|
Asset Retirement Costs
|
|
|
|
|
|
|
167
|
|
|
|
279
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
29,169
|
|
|
|
41,507
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
|
|
Property Acquisition Costs:
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved
|
|
|
16,474
|
|
|
|
1,217
|
|
|
|
4,912
|
|
Unproved
|
|
|
8,449
|
|
|
|
2,068
|
|
|
|
15,336
|
|
Exploration Costs
|
|
|
56,274
|
|
|
|
47,025
|
|
|
|
84,865
|
|
Development Costs
|
|
|
106,975
|
|
|
|
124,620
|
|
|
|
102,123
|
|
Asset Retirement Costs
|
|
|
20,048
|
|
|
|
2,306
|
|
|
|
11,244
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
208,220
|
|
|
$
|
177,236
|
|
|
$
|
218,480
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the years ended September 30, 2008, 2007 and 2006, the
Company spent $25.4 million, $30.3 million and
$55.6 million, respectively, developing proved undeveloped
reserves.
108
NATIONAL
FUEL GAS COMPANY
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Results
of Operations for Producing Activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended September 30
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(Thousands, except per Mcfe amounts)
|
|
|
United States
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas (includes revenues from sales to affiliates of $443,
$325 and $106, respectively)
|
|
$
|
216,623
|
|
|
$
|
135,399
|
|
|
$
|
152,451
|
|
Oil, Condensate and Other Liquids
|
|
|
305,887
|
|
|
|
189,539
|
|
|
|
195,050
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Operating Revenues(1)
|
|
|
522,510
|
|
|
|
324,938
|
|
|
|
347,501
|
|
Production/Lifting Costs
|
|
|
66,685
|
|
|
|
48,410
|
|
|
|
41,354
|
|
Accretion Expense
|
|
|
4,056
|
|
|
|
3,704
|
|
|
|
2,412
|
|
Depreciation, Depletion and Amortization ($2.23, $1.97 and $1.74
per Mcfe of production)
|
|
|
91,093
|
|
|
|
77,452
|
|
|
|
66,488
|
|
Income Tax Expense
|
|
|
144,922
|
|
|
|
78,928
|
|
|
|
88,104
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Results of Operations for Producing Activities (excluding
corporate overheads and interest charges)
|
|
|
215,754
|
|
|
|
116,444
|
|
|
|
149,143
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canada Discontinued Operations
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas
|
|
|
|
|
|
|
39,114
|
|
|
|
54,819
|
|
Oil, Condensate and Other Liquids
|
|
|
|
|
|
|
10,313
|
|
|
|
13,985
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Operating Revenues(1)
|
|
|
|
|
|
|
49,427
|
|
|
|
68,804
|
|
Production/Lifting Costs
|
|
|
|
|
|
|
14,846
|
|
|
|
14,628
|
|
Accretion Expense
|
|
|
|
|
|
|
249
|
|
|
|
258
|
|
Depreciation, Depletion and Amortization ($0, $1.67 and $2.95
per Mcfe of production)
|
|
|
|
|
|
|
12,787
|
|
|
|
27,439
|
|
Impairment of Oil and Gas Producing Properties(2)
|
|
|
|
|
|
|
|
|
|
|
104,739
|
|
Income Tax Expense (Benefit)
|
|
|
|
|
|
|
3,703
|
|
|
|
(31,987
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Results of Operations for Producing Activities (excluding
corporate overheads and interest charges)
|
|
|
|
|
|
|
17,842
|
|
|
|
(46,273
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
109
NATIONAL
FUEL GAS COMPANY
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended September 30
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(Thousands, except per Mcfe amounts)
|
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas (includes revenues from sales to affiliates of $443,
$325 and $106, respectively)
|
|
|
216,623
|
|
|
|
174,513
|
|
|
|
207,270
|
|
Oil, Condensate and Other Liquids
|
|
|
305,887
|
|
|
|
199,852
|
|
|
|
209,035
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Operating Revenues(1)
|
|
|
522,510
|
|
|
|
374,365
|
|
|
|
416,305
|
|
Production/Lifting Costs
|
|
|
66,685
|
|
|
|
63,256
|
|
|
|
55,982
|
|
Accretion Expense
|
|
|
4,056
|
|
|
|
3,953
|
|
|
|
2,670
|
|
Depreciation, Depletion and Amortization ($2.23, $1.92 and $1.98
per Mcfe of production)
|
|
|
91,093
|
|
|
|
90,239
|
|
|
|
93,927
|
|
Impairment of Oil and Gas Producing Properties(2)
|
|
|
|
|
|
|
|
|
|
|
104,739
|
|
Income Tax Expense
|
|
|
144,922
|
|
|
|
82,631
|
|
|
|
56,117
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Results of Operations for Producing Activities (excluding
corporate overheads and interest charges)
|
|
$
|
215,754
|
|
|
$
|
134,286
|
|
|
$
|
102,870
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(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. |
110
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, 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
|
|
Extensions and Discoveries
|
|
|
8,759
|
|
|
|
|
|
|
|
31,322
|
|
|
|
40,081
|
|
|
|
|
|
|
|
40,081
|
|
Revisions of Previous Estimates
|
|
|
2,156
|
|
|
|
566
|
|
|
|
(3,460
|
)
|
|
|
(738
|
)
|
|
|
|
|
|
|
(738
|
)
|
Production
|
|
|
(11,033
|
)
|
|
|
(4,039
|
)
|
|
|
(7,269
|
)
|
|
|
(22,341
|
)
|
|
|
|
|
|
|
(22,341
|
)
|
Purchases of Minerals in Place
|
|
|
|
|
|
|
4,539
|
|
|
|
727
|
|
|
|
5,266
|
|
|
|
|
|
|
|
5,266
|
|
Sales of Minerals in Place
|
|
|
(377
|
)
|
|
|
(1,381
|
)
|
|
|
|
|
|
|
(1,758
|
)
|
|
|
|
|
|
|
(1,758
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
September 30, 2008
|
|
|
24,641
|
|
|
|
72,860
|
|
|
|
128,398
|
|
|
|
225,899
|
|
|
|
|
|
|
|
225,899
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved Developed Reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
|
|
September 30, 2008
|
|
|
18,242
|
|
|
|
68,453
|
|
|
|
115,824
|
|
|
|
202,519
|
|
|
|
|
|
|
|
202,519
|
|
111
NATIONAL
FUEL GAS COMPANY
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil Mbbl
|
|
|
|
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, 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
|
|
Extensions and Discoveries
|
|
|
298
|
|
|
|
471
|
|
|
|
58
|
|
|
|
827
|
|
|
|
|
|
|
|
827
|
|
Revisions of Previous Estimates
|
|
|
203
|
|
|
|
(34
|
)
|
|
|
(64
|
)
|
|
|
105
|
|
|
|
|
|
|
|
105
|
|
Production
|
|
|
(505
|
)
|
|
|
(2,460
|
)
|
|
|
(105
|
)
|
|
|
(3,070
|
)
|
|
|
|
|
|
|
(3,070
|
)
|
Purchases of Minerals in Place
|
|
|
|
|
|
|
2,084
|
|
|
|
|
|
|
|
2,084
|
|
|
|
|
|
|
|
2,084
|
|
Sales of Minerals in Place
|
|
|
(73
|
)
|
|
|
(1,261
|
)
|
|
|
|
|
|
|
(1,334
|
)
|
|
|
|
|
|
|
(1,334
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
September 30, 2008
|
|
|
1,358
|
|
|
|
44,444
|
|
|
|
396
|
|
|
|
46,198
|
|
|
|
|
|
|
|
46,198
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved Developed Reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
|
|
September 30, 2008
|
|
|
1,313
|
|
|
|
37,224
|
|
|
|
357
|
|
|
|
38,894
|
|
|
|
|
|
|
|
38,894
|
|
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.
112
NATIONAL
FUEL GAS COMPANY
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended September 30
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(Thousands)
|
|
|
United States
|
|
|
|
|
|
|
|
|
|
|
|
|
Future Cash Inflows
|
|
$
|
5,845,214
|
|
|
$
|
4,879,496
|
|
|
$
|
3,911,059
|
|
Less:
|
|
|
|
|
|
|
|
|
|
|
|
|
Future Production Costs
|
|
|
1,231,705
|
|
|
|
872,536
|
|
|
|
758,258
|
|
Future Development Costs
|
|
|
265,515
|
|
|
|
229,987
|
|
|
|
205,497
|
|
Future Income Tax Expense at Applicable Statutory Rate
|
|
|
1,645,351
|
|
|
|
1,423,707
|
|
|
|
1,019,307
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Future Net Cash Flows
|
|
|
2,702,643
|
|
|
|
2,353,266
|
|
|
|
1,927,997
|
|
Less:
|
|
|
|
|
|
|
|
|
|
|
|
|
10% Annual Discount for Estimated Timing of Cash Flows
|
|
|
1,434,799
|
|
|
|
1,292,804
|
|
|
|
1,066,338
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Standardized Measure of Discounted Future Net Cash Flows
|
|
|
1,267,844
|
|
|
|
1,060,462
|
|
|
|
861,659
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canada Discontinued Operations
|
|
|
|
|
|
|
|
|
|
|
|
|
Future Cash Inflows
|
|
|
|
|
|
|
|
|
|
|
197,227
|
|
Less:
|
|
|
|
|
|
|
|
|
|
|
|
|
Future Production Costs
|
|
|
|
|
|
|
|
|
|
|
92,234
|
|
Future Development Costs
|
|
|
|
|
|
|
|
|
|
|
11,520
|
|
Future Income Tax Expense at Applicable Statutory Rate
|
|
|
|
|
|
|
|
|
|
|
(151
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Future Net Cash Flows
|
|
|
|
|
|
|
|
|
|
|
93,624
|
|
Less:
|
|
|
|
|
|
|
|
|
|
|
|
|
10% Annual Discount for Estimated Timing of Cash Flows
|
|
|
|
|
|
|
|
|
|
|
19,375
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Standardized Measure of Discounted Future Net Cash Flows
|
|
|
|
|
|
|
|
|
|
|
74,249
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
|
|
Future Cash Inflows
|
|
|
5,845,214
|
|
|
|
4,879,496
|
|
|
|
4,108,286
|
|
Less:
|
|
|
|
|
|
|
|
|
|
|
|
|
Future Production Costs
|
|
|
1,231,705
|
|
|
|
872,536
|
|
|
|
850,492
|
|
Future Development Costs
|
|
|
265,515
|
|
|
|
229,987
|
|
|
|
217,017
|
|
Future Income Tax Expense at Applicable Statutory Rate
|
|
|
1,645,351
|
|
|
|
1,423,707
|
|
|
|
1,019,156
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Future Net Cash Flows
|
|
|
2,702,643
|
|
|
|
2,353,266
|
|
|
|
2,021,621
|
|
Less:
|
|
|
|
|
|
|
|
|
|
|
|
|
10% Annual Discount for Estimated Timing of Cash Flows
|
|
|
1,434,799
|
|
|
|
1,292,804
|
|
|
|
1,085,713
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Standardized Measure of Discounted Future Net Cash Flows
|
|
$
|
1,267,844
|
|
|
$
|
1,060,462
|
|
|
$
|
935,908
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
113
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
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(Thousands)
|
|
|
United States
|
|
|
|
|
|
|
|
|
|
|
|
|
Standardized Measure of Discounted Future
Net Cash Flows at Beginning of Year
|
|
$
|
1,060,462
|
|
|
$
|
861,659
|
|
|
$
|
1,491,532
|
|
Sales, Net of Production Costs
|
|
|
(455,825
|
)
|
|
|
(276,529
|
)
|
|
|
(306,147
|
)
|
Net Changes in Prices, Net of Production Costs
|
|
|
509,705
|
|
|
|
539,895
|
|
|
|
(941,545
|
)
|
Purchases of Minerals in Place
|
|
|
67,768
|
|
|
|
|
|
|
|
7,607
|
|
Sales of Minerals in Place
|
|
|
(31,642
|
)
|
|
|
484
|
|
|
|
|
|
Extensions and Discoveries
|
|
|
143,394
|
|
|
|
98,751
|
|
|
|
66,975
|
|
Changes in Estimated Future Development Costs
|
|
|
(100,684
|
)
|
|
|
(83,199
|
)
|
|
|
(83,750
|
)
|
Previously Estimated Development Costs Incurred
|
|
|
65,156
|
|
|
|
58,710
|
|
|
|
67,048
|
|
Net Change in Income Taxes at Applicable Statutory Rate
|
|
|
(119,585
|
)
|
|
|
(174,920
|
)
|
|
|
404,176
|
|
Revisions of Previous Quantity Estimates
|
|
|
(3,936
|
)
|
|
|
(140,203
|
)
|
|
|
4,850
|
|
Accretion of Discount and Other
|
|
|
133,031
|
|
|
|
175,814
|
|
|
|
150,913
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Standardized Measure of Discounted Future Net Cash Flows at End
of Year
|
|
|
1,267,844
|
|
|
|
1,060,462
|
|
|
|
861,659
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canada Discontinued Operations
|
|
|
|
|
|
|
|
|
|
|
|
|
Standardized Measure of Discounted Future
Net Cash Flows at Beginning of Year
|
|
|
|
|
|
|
74,249
|
|
|
|
206,643
|
|
Sales, Net of Production Costs
|
|
|
|
|
|
|
(34,581
|
)
|
|
|
(54,176
|
)
|
Net Changes in Prices, Net of Production Costs
|
|
|
|
|
|
|
35,628
|
|
|
|
(180,216
|
)
|
Sales of Minerals in Place
|
|
|
|
|
|
|
(151,236
|
)
|
|
|
(238
|
)
|
Extensions and Discoveries
|
|
|
|
|
|
|
6,908
|
|
|
|
10,369
|
|
Changes in Estimated Future Development Costs
|
|
|
|
|
|
|
5,722
|
|
|
|
(3,282
|
)
|
Previously Estimated Development Costs Incurred
|
|
|
|
|
|
|
5,798
|
|
|
|
4,450
|
|
Net Change in Income Taxes at Applicable Statutory Rate
|
|
|
|
|
|
|
(10,075
|
)
|
|
|
82,966
|
|
Revisions of Previous Quantity Estimates
|
|
|
|
|
|
|
34,998
|
|
|
|
(15,478
|
)
|
Accretion of Discount and Other
|
|
|
|
|
|
|
32,589
|
|
|
|
23,211
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Standardized Measure of Discounted Future Net Cash Flows at End
of Year
|
|
|
|
|
|
|
|
|
|
|
74,249
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
114
NATIONAL
FUEL GAS COMPANY
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended September 30
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(Thousands)
|
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
|
|
Standardized Measure of Discounted Future
Net Cash Flows at Beginning of Year
|
|
|
1,060,462
|
|
|
|
935,908
|
|
|
|
1,698,175
|
|
Sales, Net of Production Costs
|
|
|
(455,825
|
)
|
|
|
(311,110
|
)
|
|
|
(360,323
|
)
|
Net Changes in Prices, Net of Production Costs
|
|
|
509,705
|
|
|
|
575,523
|
|
|
|
(1,121,761
|
)
|
Purchases of Minerals in Place
|
|
|
67,768
|
|
|
|
|
|
|
|
7,607
|
|
Sales of Minerals in Place
|
|
|
(31,642
|
)
|
|
|
(150,752
|
)
|
|
|
(238
|
)
|
Extensions and Discoveries
|
|
|
143,394
|
|
|
|
105,659
|
|
|
|
77,344
|
|
Changes in Estimated Future Development Costs
|
|
|
(100,684
|
)
|
|
|
(77,477
|
)
|
|
|
(87,032
|
)
|
Previously Estimated Development Costs Incurred
|
|
|
65,156
|
|
|
|
64,508
|
|
|
|
71,498
|
|
Net Change in Income Taxes at Applicable Statutory Rate
|
|
|
(119,585
|
)
|
|
|
(184,995
|
)
|
|
|
487,142
|
|
Revisions of Previous Quantity Estimates
|
|
|
(3,936
|
)
|
|
|
(105,205
|
)
|
|
|
(10,628
|
)
|
Accretion of Discount and Other
|
|
|
133,031
|
|
|
|
208,403
|
|
|
|
174,124
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Standardized Measure of Discounted Future Net Cash Flows at End
of Year
|
|
$
|
1,267,844
|
|
|
$
|
1,060,462
|
|
|
$
|
935,908
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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(1)
|
|
|
Deductions(2)
|
|
|
Period
|
|
|
|
(Thousands)
|
|
|
Year Ended September 30, 2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allowance for Uncollectible Accounts
|
|
$
|
28,654
|
|
|
$
|
27,274
|
|
|
$
|
2,734
|
|
|
$
|
25,545
|
|
|
$
|
33,117
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended September 30, 2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allowance for Uncollectible Accounts
|
|
$
|
31,427
|
|
|
$
|
27,652
|
|
|
$
|
1,414
|
|
|
$
|
31,839
|
|
|
$
|
28,654
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended September 30, 2006
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allowance for Uncollectible Accounts
|
|
$
|
26,940
|
|
|
$
|
29,088
|
|
|
$
|
907
|
|
|
$
|
25,508
|
|
|
$
|
31,427
|
|
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) |
|
Amounts represent net accounts receivable written-off. |
115
|
|
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, 2008.
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, 2008. 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, 2008.
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, 2008. 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, 2008 that have materially affected, or are
reasonably likely to materially affect, the Companys
internal control over financial reporting.
|
|
Item 9B
|
Other
Information
|
None
PART III
|
|
Item 10
|
Directors,
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 2009
116
Annual Meeting of Stockholders will be filed with the SEC not
later than 120 days after September 30, 2008. 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
2012, Directors Whose Terms Expire in 2011,
Directors Whose Terms Expire in 2010, 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 2009
Annual Meeting of Stockholders will be filed with the SEC not
later than 120 days after September 30, 2008. 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 2009
Annual Meeting of Stockholders will be filed with the SEC not
later than 120 days after September 30, 2008. 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 2009
Annual Meeting of Stockholders will be filed with the SEC not
later than 120 days after September 30, 2008. 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 2009
Annual Meeting of Stockholders will be filed with the SEC not
later than 120 days after September 30, 2008. The
information concerning security ownership of
117
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 2009
Annual Meeting of Stockholders will be filed with the SEC not
later than 120 days after September 30, 2008. 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 2009
Annual Meeting of Stockholders will be filed with the SEC not
later than 120 days after September 30, 2008. The
information concerning principal accountant fees and services is
set forth in the definitive Proxy Statement under the heading
Audit Fees and is incorporated herein by reference.
PART IV
|
|
Item 15
|
Exhibits
and Financial Statement Schedules
|
(a)1. Financial
Statements
Financial statements filed as part of this report are listed in
the index included in Item 8 of this
Form 10-K,
and reference is made thereto.
(a)2. Financial
Statement Schedules
Financial statement schedules filed as part of this report are
listed in the index included in Item 8 of this
Form 10-K,
and reference is made thereto.
(a)3. Exhibits
|
|
|
|
|
Exhibit
|
|
Description of
|
Number
|
|
Exhibits
|
|
|
3(i)
|
|
|
Articles of Incorporation:
|
|
|
|
|
Restated Certificate of Incorporation of National Fuel Gas
Company dated September 21, 1998 (Exhibit 3.1,
Form 10-K
for fiscal year ended September 30, 1998 in File
No. 1-3880)
|
|
|
|
|
Certificate of Amendment of Restated Certificate of
Incorporation (Exhibit 3(ii),
Form 8-K
dated March 14, 2005 in File
No. 1-3880)
|
|
3(ii)
|
|
|
By-Laws:
|
|
|
|
|
National Fuel Gas Company By-Laws as amended June 11, 2008
(Exhibit 3.1,
Form 8-K
dated June 16, 2008 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)
|
118
|
|
|
|
|
Exhibit
|
|
Description of
|
Number
|
|
Exhibits
|
|
|
|
|
|
Third Supplemental Indenture, dated as of December 1, 1982,
to Indenture dated as of October 15, 1974, between the
Company and The Bank of New York (formerly Irving
Trust Company) (Exhibit 4(a)(4) in File
No. 33-49401)
|
|
|
|
|
Eleventh Supplemental Indenture, dated as of May 1, 1992,
to Indenture dated as of October 15, 1974, between the
Company and The Bank of New York (formerly Irving
Trust Company) (Exhibit 4(b),
Form 8-K
dated February 14, 1992 in File
No. 1-3880)
|
|
|
|
|
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)
|
|
|
|
|
Officers Certificate establishing 6.50% Notes due
2018, dated April 11, 2008 (Exhibit 4.1,
Form 10-Q
for the quarterly period ended June 30, 2008 in File
No. 1-3880)
|
|
|
|
|
Amended and Restated Rights Agreement, dated as of July 11,
2008, between the Company and The Bank of New York, as rights
agent (Exhibit 4.1,
Form 8-K
dated July 15, 2008 in File
No. 1-3880)
|
|
10
|
|
|
Material Contracts:
|
|
|
|
|
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)
|
|
|
|
|
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)
|
|
|
|
|
Settlement Agreement dated January 24, 2008 among the
Company, New Mountain Vantage GP, L.L.C. (Vantage)
and certain of Vantages affiliates (Exhibit 10.1,
Form 8-K
dated January 24, 2008 in File
No. 1-3880)
|
|
|
|
|
Director Services Agreement, dated as of June 1, 2008,
between the Company and Philip C. Ackerman (Exhibit 99,
Form 8-K
dated June 16, 2008 in File
No. 1-3880)
|
|
|
|
|
Resolutions adopted by the National Fuel Gas Company Board of
Directors on February 21, 2008 regarding director stock
ownership guidelines (Exhibit 10.5,
Form 10-Q
for the quarterly period ended March 31, 2008 in File
No. 1-3880)
|
|
10
|
.1
|
|
Form of Amended and Restated Employment Continuation and
Noncompetition Agreement among the Company, a subsidiary of the
Company and each of Karen M. Camiolo, Carl M. Carlotti, Anna
Marie Cellino, Paula M. Ciprich, Donna L. DeCarolis, John R.
Pustulka, James D. Ramsdell, David F. Smith and Ronald J. Tanski
|
|
10
|
.2
|
|
Form of Amended and Restated Employment Continuation and
Noncompetition Agreement 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)
|
119
|
|
|
|
|
Exhibit
|
|
Description of
|
Number
|
|
Exhibits
|
|
|
|
|
|
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)
|
|
|
|
|
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 July 23, 2007 (Exhibit 10.4,
Form 10-Q
for the quarterly period ended March 31, 2008 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)
|
|
|
|
|
Form of Stock Appreciation Right Award Notice under National
Fuel Gas Company 1997 Award and Option Plan (Exhibit 10.2,
Form 10-Q
for the quarterly period ended March 31, 2008 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)
|
|
10
|
.3
|
|
Amended and Restated National Fuel Gas Company 2007 Annual At
Risk Compensation Incentive Program
|
|
|
|
|
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)
|
|
|
|
|
Description of performance goals for certain executive officers
under the Companys Annual At Risk Compensation Incentive
Program (Exhibit 10.1,
Form 10-Q
for the quarterly period ended December 31, 2007 in File
No. 1-3880)
|
|
10
|
.4
|
|
National Fuel Gas Company Executive Annual Cash Incentive Program
|
|
|
|
|
Administrative Rules of the Compensation Committee of the Board
of Directors of National Fuel Gas Company, as amended and
restated effective February 20, 2008 (Exhibit 10.3,
Form 10-Q
for the quarterly period ended March 31, 2008 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)
|
120
|
|
|
|
|
Exhibit
|
|
Description of
|
Number
|
|
Exhibits
|
|
|
|
|
|
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)
|
|
|
|
|
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)
|
|
|
|
|
National Fuel Gas Company Tophat Plan, as amended
September 20, 2007 (Exhibit 10.3,
Form 10-K
for the fiscal year ended September 30, 2007 in File
No. 1-3880)
|
|
|
|
|
Amended and Restated Split Dollar Insurance and Death Benefit
Agreement, dated September 17, 1997 between the Company and
Philip C. Ackerman (Exhibit 10.5,
Form 10-K
for fiscal year ended September 30, 1997 in File
No. 1-3880)
|
|
|
|
|
Amendment Number 1 to Amended and Restated Split Dollar
Insurance and Death Benefit Agreement by and between the Company
and Philip C. Ackerman, dated March 23, 1999
(Exhibit 10.3,
Form 10-K
for fiscal year ended September 30, 1999 in File
No. 1-3880)
|
|
|
|
|
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)
|
121
|
|
|
|
|
Exhibit
|
|
Description of
|
Number
|
|
Exhibits
|
|
|
|
|
|
Amendments to National Fuel Gas Company and Participating
Subsidiaries Executive Retirement Plan, effective
September 16, 1999 (Exhibit 10.15,
Form 10-K
for fiscal year ended September 30, 1999 in File
No. 1-3880)
|
|
|
|
|
Amendment to National Fuel Gas Company and Participating
Subsidiaries Executive Retirement Plan, effective
September 5, 2001 (Exhibit 10.4,
Form 10-K/A
for fiscal year ended September 30, 2001, in File
No. 1-3880)
|
|
|
|
|
National Fuel Gas Company and Participating Subsidiaries
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)
|
|
|
|
|
National Fuel Gas Company and Participating Subsidiaries
Executive Retirement Plan, Amended and Restated as of
September 20, 2007 (Exhibit 10.4,
Form 10-K
for the fiscal year ended September 30, 2007 in File
No. 1-3880)
|
|
10
|
.5
|
|
National Fuel Gas Company and Participating Subsidiaries
Executive Retirement Plan, Amended and Restated as of
September 24, 2008
|
|
|
|
|
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)
|
|
|
|
|
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
(Exhibit 10.5,
Form 10-K
for the fiscal year ended September 30, 2007 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 10.7,
Form 10-Q
for the quarterly period ended December 31, 2006 in
File No. 1-3880)
|
|
|
|
|
Description of long-term performance incentives under the
National Fuel Gas Company Performance Incentive Program
(Exhibit 10.1,
Form 10-Q
for the quarterly period ended March 31, 2008 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)
|
|
12
|
|
|
Statements regarding Computation of Ratios: Ratio of Earnings to
Fixed Charges for the fiscal years ended September 30, 2004
through 2008
|
|
21
|
|
|
Subsidiaries of the Registrant
|
|
23
|
|
|
Consents of Experts:
|
|
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
|
122
|
|
|
|
|
Exhibit
|
|
Description of
|
Number
|
|
Exhibits
|
|
|
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
|
123
Signatures
Pursuant to the requirements of Section 13 or 15(d) of the
Securities Exchange Act of 1934, the registrant has duly caused
this report to be signed on its behalf by the undersigned,
thereunto duly authorized.
National Fuel Gas Company
(Registrant)
D. F. Smith
President and Chief Executive Officer
Date: November 26, 2008
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 and Director
|
|
Date: November 26, 2008
|
|
|
|
|
|
/s/ R.
T. Brady
R.
T. Brady
|
|
Director
|
|
Date: November 26, 2008
|
|
|
|
|
|
/s/ R.
D. Cash
R.
D. Cash
|
|
Director
|
|
Date: November 26, 2008
|
|
|
|
|
|
/s/ S.
E. Ewing
S.
E. Ewing
|
|
Director
|
|
Date: November 26, 2008
|
|
|
|
|
|
/s/ R.
E. Kidder
R.
E. Kidder
|
|
Director
|
|
Date: November 26, 2008
|
|
|
|
|
|
/s/ C.
G. Matthews
C.
G. Matthews
|
|
Director
|
|
Date: November 26, 2008
|
|
|
|
|
|
/s/ G.
L. Mazanec
G.
L. Mazanec
|
|
Director
|
|
Date: November 26, 2008
|
|
|
|
|
|
/s/ R.
G. Reiten
R.
G. Reiten
|
|
Director
|
|
Date: November 26, 2008
|
|
|
|
|
|
/s/ F.
V. Salerno
F.
V. Salerno
|
|
Director
|
|
Date: November 26, 2008
|
|
|
|
|
|
/s/ D.
F. Smith
D.
F. Smith
|
|
President, Chief Executive
Officer and Director
|
|
Date: November 26, 2008
|
124
|
|
|
|
|
|
|
Signature
|
|
Title
|
|
|
|
|
|
|
|
|
/s/ R.
J. Tanski
R.
J. Tanski
|
|
Treasurer and Principal
Financial Officer
|
|
Date: November 26, 2008
|
|
|
|
|
|
/s/ K.
M. Camiolo
K.
M. Camiolo
|
|
Controller and Principal
Accounting Officer
|
|
Date: November 26, 2008
|
125