e10vk
UNITED STATES SECURITIES AND
EXCHANGE COMMISSION
Washington, D.C.
20549
Form 10-K
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ANNUAL REPORT PURSUANT TO
SECTION 13 OR 15(d)
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OF THE SECURITIES EXCHANGE ACT
OF 1934
For the Fiscal Year Ended September 30, 2009
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TRANSITION REPORT PURSUANT TO
SECTION 13 OR 15(d)
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OF THE SECURITIES EXCHANGE ACT
OF 1934
For the Transition Period
from
to
Commission File Number 1-3880
National Fuel Gas
Company
(Exact name of registrant as
specified in its charter)
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New Jersey
(State or other jurisdiction
of
incorporation or organization)
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13-1086010
(I.R.S. Employer
Identification No.)
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6363 Main Street
Williamsville, New York
(Address of principal
executive offices)
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14221
(Zip
Code)
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(716) 857-7000
Registrants telephone number, including area code
Securities registered pursuant to Section 12(b) of the
Act:
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Name of
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Each Exchange
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on Which
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Title of Each Class
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Registered
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Common Stock, $1 Par Value, and
Common Stock Purchase Rights
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New York Stock Exchange
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Securities registered pursuant to Section 12(g) of the
Act:
None
Indicate by check mark if the registrant is a well-known
seasoned issuer, as defined in Rule 405 of the Securities
Act. Yes þ No o
Indicate by check mark if the registrant is not required to file
reports pursuant to Section 13 or Section 15
(d) of the
Act. Yes o No þ
Indicate by check mark whether the registrant (1) has filed
all reports required to be filed by Section 13 or 15(d) of
the Securities Exchange Act of 1934 during the preceding
12 months and (2) has been subject to such filing
requirements for the past
90 days. Yes þ No o
Indicate by check mark whether the registrant has submitted
electronically and posted on its corporate Web site, if any,
every Interactive Data File required to be submitted and posted
pursuant to Rule 405 of
Regulation S-T
(§ 232.405 of this chapter) during the preceding
12 months (or for such shorter period that the registrant
was required to submit and post such
files). Yes o No o
Indicate by check mark if disclosure of delinquent filers
pursuant to Item 405 of
Regulation S-K
is not contained herein, and will not be contained, to the best
of the registrants knowledge, in definitive proxy or
information statements incorporated by reference in
Part III of this
Form 10-K
or any amendment to this
Form 10-K. þ
Indicate by check mark whether the registrant is a large
accelerated filer, an accelerated filer, 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 $2,414,082,000 as of
March 31, 2009.
Common Stock, $1 Par Value, outstanding as of
October 31, 2009: 80,560,665 shares.
DOCUMENTS
INCORPORATED BY REFERENCE
Portions of the registrants definitive Proxy Statement for
its 2010 Annual Meeting of Stockholders are incorporated by
reference into Part III of this report.
Glossary
of Terms
Frequently used abbreviations,
acronyms, or terms used in this report:
National
Fuel Gas Companies
Company
The Registrant, the
Registrant and its subsidiaries or the Registrants
subsidiaries as appropriate in the context of the disclosure
Distribution Corporation
National Fuel Gas
Distribution Corporation
Empire
Empire Pipeline, Inc.
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.
Midstream Corporation
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.
Regulatory
Agencies
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
Other
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. The Company 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 oil and gas 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.
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)
MMBtu
Million British thermal
units
MMcf
Million cubic feet (of
natural gas)
MMcfe
Million cubic feet
equivalent
NGA
The Natural Gas Act of
1938, as amended; the federal law regulating interstate natural
gas pipeline and storage companies, among other things, codified
beginning at 15 U.S.C. Section 717.
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 those 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 pipeline
and/or
utility industry by statutory or regulatory process.
Restructuring of federally regulated natural gas pipelines
resulted in the separation (or unbundling) 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.
S&P
Standard &
Poors Ratings Service
SAR
Stock-settled stock
appreciation right
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, 2009
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 and important factors 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,
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 four 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 Pipeline,
Inc. (Empire), a New York corporation. 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
interstate pipeline company, 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, 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, and the Empire Connector, which is a
76-mile
pipeline extension from near Rochester, New York to an
interconnection with the unaffiliated Millennium Pipeline near
Corning, New York. The Millennium Pipeline serves the New York
City area. The Empire Connector was placed into service on
December 10, 2008.
3. The Exploration and Production segment operations are
carried out by Seneca Resources Corporation (Seneca), a
Pennsylvania corporation. Seneca is engaged in the exploration
for, and the development and purchase of, natural gas and oil
reserves in California, in the Appalachian region of the United
States, and in the Gulf Coast region of Texas and Louisiana,
including offshore areas in federal waters and some state
waters. At September 30, 2009, the Company had
U.S. proved developed and undeveloped reserves of 46,587
Mbbl of oil and 248,954 MMcf of natural gas.
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In 2007, Seneca sold its subsidiary, Seneca Energy Canada Inc.
(SECI), which conducted exploration and production operations in
the provinces of Alberta, Saskatchewan and British Columbia in
Canada.
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.
Financial information about each of the Companys business
segments can be found in Item 7, MD&A and also in
Item 8 at Note K Business Segment
Information.
The Companys other direct wholly owned subsidiaries are
not included in any of the four reported business segments and
include the following active companies:
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Highland Forest Resources, Inc. (Highland), a New York
corporation which, together with a division of Seneca known as
its Northeast Division, markets timber from New York and
Pennsylvania land holdings, owns two sawmills in northwestern
Pennsylvania and processes timber consisting primarily of high
quality hardwoods. At September 30, 2009, the Company owned
103,317 acres of timber property and managed an additional
3,424 acres of timber rights;
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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. In July 2005, Horizon B.V. sold its entire
85.16% interest in United Energy, a.s., a district heating and
electric generation business in the Czech Republic;
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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;
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Horizon Power, Inc. (Horizon Power), a New York corporation
which is an exempt wholesale generator under PUHCA
2005 and is developing or operating mid-range independent power
production facilities and landfill gas electric generation
facilities; and
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National Fuel Gas Midstream Corporation (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 2009.
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 A Summary of Significant
Accounting Policies (Regulatory Mechanisms) and
Note C Regulatory Matters.
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The Pipeline and Storage segments rates, services and
other matters are regulated by the FERC. 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 A Summary of Significant Accounting
Policies (Regulatory Mechanisms) and Note C
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 58.3% of the
Companys 2009 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 47.0%
of the Companys 2009 net income available for common
stock.
Supply Corporation has
year-to-year
or longer 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 2010, 82.9%
of Supply Corporations total firm storage capacity was
committed under contracts that, subject to 2009 shipper or
Supply Corporation notifications, could have been terminated
effective in 2010. Supply Corporation did not issue or receive
any such storage contract termination notifications in 2009. The
strong demand for market-area storage enabled Supply Corporation
to provide all of its
year-to-year
or longer storage services in 2009 at the maximum tariff rates.
Supply Corporations firm transportation capacity is not a
fixed quantity, due to the diverse web-like 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 2,189 MDth
per day (contracted transportation capacity). The Utility
segment accounts for approximately 1,065 MDth per day or 48.7%
of contracted transportation capacity, and the Energy Marketing
and Exploration and Production segments represent another 112
MDth per day or 5.1% of contracted transportation capacity. The
remaining 1,012 MDth or 46.2% of contracted transportation
capacity is subject to firm contracts with nonaffiliated
customers.
At the beginning of 2010, 52.7% of Supply Corporations
contracted transportation capacity was committed under affiliate
contracts that were scheduled to expire in 2010 or, subject to
2009 shipper or Supply Corporation notifications, could have
been terminated effective in 2010. Based on contract expirations
and termination notices received in 2009 for 2010 termination,
and taking into account any known contract
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additions, contracted transportation capacity with affiliates is
expected to increase 3.0% in 2010. Similarly, 33.0% of
contracted transportation capacity was committed under
unaffiliated shipper contracts that were scheduled to expire in
2010 or, subject to 2009 shipper or Supply Corporation
notifications, could have been terminated effective in 2010.
Based on contract expirations and termination notices received
in 2009 for 2010 termination, and taking into account any known
contract additions, contracted transportation capacity with
unaffiliated shippers is expected to increase 5.3% in 2010. 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
2009-2010
winter period, Empire has service agreements in place for firm
transportation capacity totaling approximately 689 MDth per day
(including capacity on the new Empire Connector facilities
discussed below). Most of Empires firm contracted capacity
(93.0%) has been contracted as long-term full-year deals. Two of
those contracts are due to expire during 2010, representing just
0.1% of Empires firm contracted capacity. In addition,
Empire has some seasonal (winter-only) contracts that extend for
multiple years, representing 2.5% of Empires firm
contracted capacity. One of those seasonal contracts is due to
expire during 2010, representing just 0.1% of Empires firm
contracted capacity. Arrangements for the remaining 4.5% of
Empires firm contracted capacity are single-season or
single-year contracts that expire during 2010 or early in 2011.
Empire expects that all available capacity arising from expiring
agreements will be re-contracted as seasonal or full-year
agreements. The Utility segment accounts for 6.1% of
Empires firm contracted capacity, and the Energy Marketing
segment accounts for 1.2% of Empires firm contracted
capacity, with the remaining 92.7% of Empires firm
contracted capacity subject to contracts with nonaffiliated
customers.
Empires new facilities (the Empire Connector project) were
placed into service on December 10, 2008. 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 Connectors total capacity.
None of this contracted capacity will expire during fiscal 2010.
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 incurred a net loss in
2009. The impact of this net loss in relation to the
Companys 2009 net income available for common stock
was negative 10.2%. The net loss in the Exploration and
Production segment was largely driven by an impairment charge of
$182.8 million ($108.2 million after tax).
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 7.1% of
the Companys 2009 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.
All Other
Category and Corporate Operations
The All Other category and Corporate operations incurred a net
loss in 2009. The impact of this net loss in relation to the
Companys 2009 net income available for common stock
was negative 2.2%.
6
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.
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 2009, the Utility segment purchased 76.8 Bcf of
gas for delivery to its customers. 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 56% of these
purchases. Purchases of gas under contracts for one month or
less accounted for 44% of the Utility segments 2009
purchases. Purchases from Total Gas & Power
North America Inc. (20%), Chevron Natural Gas (15%), BP
Canada (14%) and ConocoPhillips Company (12%) accounted for 61%
of the Utilitys 2009 gas purchases. No other producer or
supplier provided the Utility segment with more than 10% of its
gas requirements in 2009.
Supply Corporation transports and stores gas owned by its
customers, whose gas originates in the southwestern,
mid-continent and Appalachian regions of the United States as
well as in Canada. Empire transports gas owned by its customers,
whose gas originates in the southwestern and mid-continent
regions of the United States as well as in Canada. Additional
discussion of proposed pipeline projects appears below under
Competition: The Pipeline and Storage Segment and in
Item 7, MD&A.
The Exploration and Production segment seeks to discover and
produce raw materials (natural gas, oil and hydrocarbon liquids)
as further described in this report in Item 7, MD&A
and Item 8 at Note K Business Segment
Information and Note Q Supplementary
Information for Oil and Gas Producing Activities.
The Energy Marketing segment depends on an adequate supply of
natural gas to deliver to its customers. In 2009, this segment
purchased 62.5 Bcf of gas, including 60.9 Bcf for
delivery to its customers. The remaining 1.6 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.
7
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. With respect to gas
commodity service, in both New York and Pennsylvania,
Distribution Corporation has retained a substantial majority of
small sales customers. Almost all large-volume load, however, is
served by unregulated retail marketers. In New York,
approximately 20% of Distribution Corporations
small-volume residential and commercial customers purchase their
supplies from unregulated marketers. In Pennsylvania, the PaPUC
is currently revising regulations and business practices to
promote the growth of small-volume retail competition. Retail
competition for gas commodity service does not pose an acute
competitive threat for Distribution Corporation because in both
jurisdictions, LDC cost of service is recovered through
distribution rates and charges, not through charges for gas
commodity service. Over the longer run, however, rate design
changes resulting from further customer migration to marketer
service (e.g., unbundling) can expose utility
companies such as Distribution Corporation to stranded costs and
revenue erosion in the absence of compensating rate relief.
Competition for transportation service to 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.
The Utility segment competes in its most vulnerable markets (the
large commercial and industrial markets) by offering unbundled,
flexible, high quality services. The Utility segment continues
to develop or promote new sources and uses of natural gas or new
services, rates and contracts.
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. New productive areas in the
Appalachian region related to the development of the Marcellus
Shale formation, in addition to the aforementioned regions,
offer 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 has
constructed the Empire Connector project, which expands its
natural gas pipeline and enables 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.
8
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.
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 an upward adjustment to customers
current bills, while weather that is colder than normal results
in a downward adjustment, so that in either case projected
operating costs calculated at normal temperatures will be
recovered.
Volumes transported and stored by Supply Corporation and volumes
transported by Empire may vary materially depending on weather,
without materially affecting revenues. Supply Corporations
and Empires allowed rates are based on a straight
fixed-variable rate design which allows recovery of fixed costs
in fixed monthly reservation charges. Variable charges based on
volumes are designed to recover only the variable costs
associated with actual transportation or storage of gas.
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.
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 I Commitments and Contingencies.
Miscellaneous
The Company and its wholly owned or majority-owned subsidiaries
had a total of 1,949 full-time employees at
September 30, 2009. This compares to 1,943 employees
in the Companys operations at September 30, 2008.
The Company has agreements in place with collective bargaining
units in New York and Pennsylvania. The agreements in New York
are scheduled to expire in February 2013 and the agreements in
Pennsylvania are scheduled to expire in April 2014 and May 2014.
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.
9
Executive
Officers of the Company as of November 15,
2009(1)
|
|
|
|
|
Current Company
|
|
|
Positions and
|
|
|
Other Material
|
|
|
Business Experience
|
Name and Age (as of
|
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During Past
|
November 15, 2009)
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Five Years
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David F. Smith
(56)
|
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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
(57)
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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;
and Senior Vice President of Distribution Corporation from July
2001 through January 2006.
|
Matthew D. Cabell
(51)
|
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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. Mr. Cabells prior employer is not a subsidiary or
affiliate of the Company.
|
Anna Marie Cellino
(56)
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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.
|
Karen M. Camiolo
(50)
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Controller and Principal Accounting Officer of the Company since
April 2004; and Controller of Distribution Corporation and
Supply Corporation since April 2004.
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Carl M. Carlotti
(54)
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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
(49)
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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.
|
Donna L. DeCarolis
(50)
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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.
|
John R. Pustulka
(57)
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Senior Vice President of Supply Corporation since July 2001.
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James D. Ramsdell
(54)
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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. |
10
As a
holding company, the Company depends on its operating
subsidiaries to meet its financial obligations.
The Company is a holding company with no significant assets
other than the stock of its operating subsidiaries. In order to
meet its financial needs, the Company relies exclusively on
repayments of principal and interest on intercompany loans made
by the Company 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.
The
Company is dependent on credit markets to successfully execute
its business strategies.
The Company relies upon short-term bank borrowings, commercial
paper markets and longer-term capital markets to finance capital
requirements not satisfied by cash flow from operations. The
Company is dependent on these capital sources to provide capital
to its subsidiaries to fund operations, acquire, maintain and
develop properties, and execute growth strategies. The
availability and cost of credit sources may be cyclical and
these capital sources may not remain available to the Company.
Turmoil in credit markets may make it difficult for the Company
to obtain financing on acceptable terms or at all for working
capital, capital expenditures and other investments, or to
refinance maturing debt on favorable terms. These difficulties
could adversely affect the Companys growth strategies,
operations and financial performance. The Companys ability
to borrow under its credit facilities and commercial paper
agreements, and its ability to issue long-term debt under its
indentures, depend on the Companys compliance with its
obligations under the facilities, agreements and indentures. In
addition, the Companys 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, resulting in exposure to interest
rate fluctuations in the absence of interest rate hedging
transactions. The cost of long-term debt, the interest rates on
the Companys short-term bank loans and the ability of the
Company 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. A downgrade in the
Companys credit ratings could increase borrowing costs and
negatively impact the availability of capital from banks,
commercial paper purchasers and other sources.
The
Company 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 the Companys revenues and cash
flows or restrict its future growth. Economic conditions in the
Companys utility service territories and energy marketing
territories also impact its collections of accounts receivable.
All of the Companys 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 instability or other
adverse effects at any of our suppliers or customers. For
example, counterparties to the Companys commodity hedging
arrangements or commodity sales contracts might not be able to
perform their obligations under these arrangements or contracts.
Customers of the Companys 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 the Companys results of operations,
financial condition and cash flows.
The
Companys credit ratings may not reflect all the risks of
an investment in its securities.
The Companys 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. The
11
Companys 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.
The
Companys 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 the Company 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 the Companys
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 the Companys Utility segment, the operations of
Distribution Corporation are subject to the jurisdiction of the
NYPSC, the PaPUC and, with respect to certain transactions, the
FERC. 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 to the extent 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 gas commodity from
unregulated marketers, in addition to utility companies. To date
those efforts have been more successful in New York, where
approximately 20% of Distribution Corporations retail
sales customers purchase gas commodity from unregulated
marketers, than in Pennsylvania, where retail competition
remains a fledgling movement. The PaPUC, however, has undertaken
recent measures to enhance competition in that state. Retail
competition for gas commodity service does not pose an acute
competitive threat for Distribution Corporation, because in both
jurisdictions, it recovers its cost of service through
distribution rates and charges, and not through any
mark-up on
the gas commodity purchased by its customers. Over the longer
run, however, rate design changes resulting from further
customer migration to marketer service (unbundling)
can expose utilities such as Distribution Corporation to
stranded costs and revenue erosion in the absence of
compensating rate relief.
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 New York, aggressive generic statewide programs created under
the label of efficiency or conservation continue to generate a
sizable utility funding requirement for state agencies that
administer those programs. Although utilities are authorized to
recover the cost of efficiency and conservation program funding
through special rates and surcharges, the resulting upward
pressure on customer rates, coupled with increased assessments
and taxes, could affect future tolerance for traditional utility
rate increases, especially if gas costs were to increase.
The Company is subject to the jurisdiction of the FERC with
respect to Supply Corporation, Empire and some transactions
performed by other Company subsidiaries, including Seneca
Resources, Distribution
12
Corporation and NFR. The FERC, among other things, approves the
rates that Supply Corporation and Empire 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 and Empires 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. The FERC also possesses
significant penalty authority with respect to violations of the
laws and regulations it administers. Supply Corporation, Empire
and, to the extent subject to FERC jurisdiction, the
Companys other subsidiaries are subject to the FERCs
penalty authority.
The
Companys 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 the Companys capital resources. The
Company has issued commercial paper and used short-term
borrowings in the past to temporarily finance storage
inventories and purchased gas costs, and although the Company
expects to do so in the future, it may not be able to access the
markets for such borrowings at attractive interest rates or at
all. Distribution Corporation is required to file an accounting
reconciliation with the regulators in each of the Utility
segments service territories regarding the costs of
purchased gas. Due to the nature of the regulatory process,
there is a risk of a disallowance of full recovery of these
costs during any period in which there has been a substantial
upward spike in these costs. Any material disallowance of
purchased gas costs could have a material adverse effect on cash
flow and earnings. In addition, even when Distribution
Corporation is allowed full recovery of these purchased gas
costs, during periods when natural gas prices are significantly
higher than historical levels, customers may 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 the Companys ability to
finance capital expenditures and to refinance maturing
debt.
The Companys 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, the
Companys authorized rate of return in its regulated
businesses is based upon certain assumptions regarding interest
rates. If interest rates are lower than assumed rates, the
Companys authorized rate of return could be reduced. If
interest rates are higher than assumed rates, the Companys
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.
The Companys 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
13
regulations, such as regulation of natural gas transportation,
royalties, and price controls. The Company sells most of its oil
and natural gas at current market prices rather than through
fixed-price contracts, although as discussed below, the Company
frequently hedges the price of a significant portion of its
future production in the financial markets. The prices the
Company receives depend upon factors beyond the Companys
control, including the factors affecting price mentioned above.
The Company believes that any prolonged reduction in oil and
natural gas prices would restrict its ability to continue the
level of exploration and production activity the Company
otherwise would pursue, which could have a material adverse
effect on its revenues, cash flows and results of operations.
The
Company 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, the Company regularly
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 the Companys expected energy
production during the upcoming
12-month
period. These contracts reduce exposure to subsequent price
drops but can also limit the Companys 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 gas stored underground. The Companys
Pipeline and Storage segment enters into hedging arrangements
with respect to certain sales of efficiency gas.
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 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 the Company 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 the Companys 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. The Company maintains a system of
internal controls to monitor compliance with its policy.
However, unauthorized speculative trades, if they were to occur,
could expose the Company 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.
14
You
should not place undue reliance on reserve information because
such information represents estimates.
This
Form 10-K
contains estimates of the Companys proved oil and natural
gas reserves and the future net cash flows from those reserves
that were prepared by the Companys petroleum engineers and
audited by independent petroleum engineers. Petroleum engineers
consider many factors and make assumptions in estimating 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 the
Companys reserves will vary from any estimates, and these
variations may be material. Accordingly, the accuracy of the
Companys reserve estimates is a function of the quality of
available data and of engineering and geological interpretation
and judgment.
If conditions remain constant, then the Company 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 the
Companys proved reserves is the current market value of
the Companys estimated oil and natural gas reserves. In
accordance with SEC requirements, the Company 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 the
Companys 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 the Companys reserve 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 the Companys 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 the Companys
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
the Companys earnings. The total and timing of actual
future production may vary significantly from reserves and
production estimates. The Companys 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, including completion of environmental impact
analyses and compliance with other environmental laws and
regulations, and shortages or delays in the delivery of
equipment and services can delay drilling operations or result
in their
15
cancellation. The cost of drilling, completing, and operating
wells is often uncertain, and new wells may not be productive or
the Company may not recover all or any portion of its
investment. Without continued successful exploitation or
acquisition activities, the Companys reserves and revenues
will decline as a result of its current reserves being depleted
by production. The Company 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 the Companys
profitability.
The Company accounts for its exploration and production
activities under the full cost method of accounting. Each
quarter, the Company 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 the Company to
recognize an immediate expense in that quarter, and its earnings
would be reduced. The Companys Exploration and Production
segment recorded an impairment charge under the full cost method
of accounting in the quarter ended December 31, 2008. If
spot market prices at a subsequent quarter end are lower than
prices at December 31, 2008, absent any changes in other
factors affecting the present value of the future net revenue
projected to be recovered from the Companys oil and
natural gas properties, the Company would be required to record
an additional impairment charge. Depending on the magnitude of
the decrease in prices, that charge could be material.
Environmental
regulation significantly affects the Companys
business.
The Companys 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
and greenhouse gases into the environment, the reporting of such
matters, and the general protection of public health, natural
resources, wildlife and the environment. Costs of compliance and
liabilities could negatively affect the Companys results
of operations, financial condition and cash flows. In addition,
compliance with environmental laws and regulations could require
unexpected capital expenditures at the Companys facilities
or delay or cause the cancellation of expansion projects or oil
and natural gas drilling activities. Because the costs of
complying with environmental regulations are significant,
additional regulation could negatively affect the Companys
business. Although the Company cannot predict the impact of the
interpretation or enforcement of EPA standards or other federal,
state and local regulations, the Companys costs could
increase if environmental laws and regulations become more
strict.
The
nature of the Companys operations presents inherent risks
of loss that could adversely affect its results of operations,
financial condition and cash flows.
The Companys 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, the Companys 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, the Company maintains insurance coverage against some,
but not all, potential losses. In addition, many of the
agreements that the Company executes with contractors provide
for the division of responsibilities between the contractor and
the Company, and the Company seeks to obtain an indemnification
from the contractor for certain of these risks. The Company is
not always able, however, to
16
secure written agreements with its contractors that contain
indemnification, and sometimes the Company is required to
indemnify others.
Insurance or indemnification agreements when obtained may not
adequately protect the Company 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 the Company . 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, the Company 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 the Companys results of operations, financial
condition and cash flows.
Hazards and risks faced by the Company, and insurance and
indemnification obtained or provided by the Company, may subject
the Company to litigation or administrative proceedings from
time to time. Such litigation or proceedings could result in
substantial monetary judgments, fines or penalties against the
Company or be resolved on unfavorable terms, the result of which
could have a material adverse effect on the Companys
results of operations, financial condition and cash flows.
The
increasing costs of certain employee and retiree benefits could
adversely affect the Companys results.
The Companys 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, the Company 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 the Companys financial results.
Significant
shareholders or potential shareholders may attempt to effect
changes at the Company or acquire control over the Company,
which could adversely affect the Companys results of
operations and financial condition.
In January 2008, the Company 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 the Companys
Board of Directors at the Companys 2008 Annual Meeting of
Stockholders. That settlement agreement expired on
September 15, 2009. Vantage or other existing or potential
shareholders may engage in proxy solicitations or advance
shareholder proposals after the Companys 2010 Annual
Meeting of Stockholders, or otherwise attempt to effect changes
or acquire control over the Company.
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 financial
restructuring, increased debt, 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 the Companys
operations and diverting the attention of the Companys
Board of Directors and senior management from the pursuit of
business strategies. As a result, shareholder campaigns could
adversely affect the Companys results of operations and
financial condition.
|
|
Item 1B
|
Unresolved
Staff Comments
|
None
17
General
Information on Facilities
The net investment of the Company in property, plant and
equipment was $3.1 billion at September 30, 2009.
Approximately 63% 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 (33%), is
primarily located in California, in the Appalachian region of
the United States, and in the Gulf Coast region of Texas and
Louisiana. The remaining net investment in property, plant and
equipment consisted of the All Other and Corporate operations
(4%). 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 $125.3 million, or 4.2%, since 2004. 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, 2009. The
net investment in its gas distribution network (including
14,837 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, 2009.
The Pipeline and Storage segment had a net investment of
$839.4 million in property, plant and equipment at
September 30, 2009. Transmission pipeline represents 43% of
this segments total net investment and includes
2,364 miles of pipeline utilized to move large volumes of
gas throughout its service area. Storage facilities represent
20% 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 428 miles of pipeline.
Net investment in storage facilities includes $89.7 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 28 compressor stations with 95,949 installed
compressor horsepower that represent 10% of this segments
total net investment in property, plant and equipment.
The Exploration and Production segment had a net investment in
property, plant and equipment of $1.0 billion at
September 30, 2009.
The Utility and Pipeline and Storage segments facilities
provided the capacity to meet the Companys 2009 peak day
sendout, including transportation service, of 1,733 MMcf,
which occurred on January 15, 2009. Withdrawals from
storage of 694.1 MMcf provided approximately 40.1% 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, and
in the Gulf Coast region of Texas and Louisiana. 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 J
Discontinued Operations. Further discussion of oil and gas
producing activities is included in Item 8,
Note Q Supplementary Information for Oil and
Gas Producing Activities. Note Q sets forth proved
developed and undeveloped reserve information for Seneca.
Senecas proved developed and undeveloped natural gas
reserves increased from 226 Bcf at September 30, 2008
to 249 Bcf at September 30, 2009. This increase is
attributed primarily to extensions and discoveries
(59.2 Bcf), primarily in the Appalachian region
(49.2 Bcf). This increase was partially offset by
production of
18
22.3 Bcf, negative revisions of previous estimates
(9.6 Bcf) and sales of minerals in place (4.7 Bcf) in
the Gulf Coast region. Senecas proved developed and
undeveloped oil reserves increased from 46,198 Mbbl at
September 30, 2008 to 46,587 Mbbl at September 30,
2009. This increase is attributed to purchases of minerals in
place (2,115 Mbbl) in the West Coast region, extensions and
discoveries (1,213 Mbbl), and revisions of previous estimates
(449 Mbbl). These increases were largely offset by production
(3,373 Mbbl), primarily occurring in the West Coast region
(2,674 Mbbl). On a Bcfe basis, Senecas proved developed
and undeveloped reserves increased from 503 Bcfe at
September 30, 2008 to 528 Bcfe at September 30,
2009.
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 the West Coast region (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 oil and gas reserves reported in Item 8 at
Note Q as of September 30, 2009 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 227 Bcf and 47,630
Mbbl of gas and oil reserves, respectively, which differs from
the reserve information summarized in Item 8 at
Note Q. 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 Q
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 Q 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 Q, which are reported on a net revenue
interest basis.
The following is a summary of certain oil and gas information
taken from Senecas records. All monetary amounts are
expressed in U.S. dollars.
Production
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For The Year Ended September 30
|
|
|
2009
|
|
2008
|
|
2007
|
|
United States
|
|
|
|
|
|
|
|
|
|
|
|
|
Gulf Coast Region
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Sales Price per Mcf of Gas
|
|
$
|
4.54
|
|
|
$
|
10.03
|
|
|
$
|
6.58
|
|
Average Sales Price per Barrel of Oil
|
|
$
|
54.58
|
|
|
$
|
107.27
|
|
|
$
|
63.04
|
|
Average Sales Price per Mcf of Gas (after hedging)
|
|
$
|
5.28
|
|
|
$
|
9.49
|
|
|
$
|
6.87
|
|
Average Sales Price per Barrel of Oil (after hedging)
|
|
$
|
54.58
|
|
|
$
|
98.56
|
|
|
$
|
64.09
|
|
Average Production (Lifting) Cost per Mcf Equivalent of Gas and
Oil Produced
|
|
$
|
1.53
|
|
|
$
|
1.63
|
|
|
$
|
1.08
|
|
Average Production per Day (in MMcf Equivalent of Gas and Oil
Produced)
|
|
|
38
|
|
|
|
38
|
|
|
|
40
|
|
West Coast Region
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Sales Price per Mcf of Gas
|
|
$
|
3.91
|
|
|
$
|
8.71
|
|
|
$
|
6.54
|
|
Average Sales Price per Barrel of Oil
|
|
$
|
50.90
|
|
|
$
|
98.17
|
|
|
$
|
56.86
|
|
Average Sales Price per Mcf of Gas (after hedging)
|
|
$
|
7.37
|
|
|
$
|
8.22
|
|
|
$
|
6.82
|
|
Average Sales Price per Barrel of Oil (after hedging)
|
|
$
|
67.61
|
|
|
$
|
77.64
|
|
|
$
|
47.43
|
|
19
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For The Year Ended September 30
|
|
|
2009
|
|
2008
|
|
2007
|
|
Average Production (Lifting) Cost per Mcf Equivalent of Gas and
Oil Produced
|
|
$
|
1.68
|
|
|
$
|
2.01
|
|
|
$
|
1.54
|
|
Average Production per Day (in MMcf Equivalent of Gas and Oil
Produced)
|
|
|
55
|
|
|
|
51
|
|
|
|
50
|
|
Appalachian Region
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Sales Price per Mcf of Gas
|
|
$
|
5.52
|
|
|
$
|
9.73
|
|
|
$
|
7.48
|
|
Average Sales Price per Barrel of Oil
|
|
$
|
56.15
|
|
|
$
|
97.40
|
|
|
$
|
62.26
|
|
Average Sales Price per Mcf of Gas (after hedging)
|
|
$
|
8.69
|
|
|
$
|
8.85
|
|
|
$
|
8.25
|
|
Average Sales Price per Barrel of Oil (after hedging)
|
|
$
|
56.15
|
|
|
$
|
97.40
|
|
|
$
|
62.26
|
|
Average Production (Lifting) Cost per Mcf Equivalent of Gas and
Oil Produced
|
|
$
|
0.89
|
|
|
$
|
0.77
|
|
|
$
|
0.69
|
|
Average Production per Day (in MMcf Equivalent of Gas and Oil
Produced)
|
|
|
24
|
|
|
|
22
|
|
|
|
17
|
|
Total United States
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Sales Price per Mcf of Gas
|
|
$
|
4.79
|
|
|
$
|
9.70
|
|
|
$
|
6.82
|
|
Average Sales Price per Barrel of Oil
|
|
$
|
51.69
|
|
|
$
|
99.64
|
|
|
$
|
58.43
|
|
Average Sales Price per Mcf of Gas (after hedging)
|
|
$
|
6.94
|
|
|
$
|
9.05
|
|
|
$
|
7.25
|
|
Average Sales Price per Barrel of Oil (after hedging)
|
|
$
|
64.94
|
|
|
$
|
81.75
|
|
|
$
|
51.68
|
|
Average Production (Lifting) Cost per Mcf Equivalent of Gas and
Oil Produced
|
|
$
|
1.47
|
|
|
$
|
1.64
|
|
|
$
|
1.23
|
|
Average Production per Day (in MMcf Equivalent of Gas and Oil
Produced)
|
|
|
116
|
|
|
|
111
|
|
|
|
108
|
|
Canada Discontinued Operations
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Sales Price per Mcf of Gas
|
|
$
|
|
|
|
$
|
|
|
|
$
|
6.09
|
|
Average Sales Price per Barrel of Oil
|
|
$
|
|
|
|
$
|
|
|
|
$
|
50.06
|
|
Average Sales Price per Mcf of Gas (after hedging)
|
|
$
|
|
|
|
$
|
|
|
|
$
|
6.17
|
|
Average Sales Price per Barrel of Oil (after hedging)
|
|
$
|
|
|
|
$
|
|
|
|
$
|
50.06
|
|
Average Production (Lifting) Cost per Mcf Equivalent of Gas and
Oil Produced
|
|
$
|
|
|
|
$
|
|
|
|
$
|
1.94
|
|
Average Production per Day (in MMcf Equivalent of Gas and Oil
Produced)
|
|
|
|
|
|
|
|
|
|
|
21
|
|
Total Company
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Sales Price per Mcf of Gas
|
|
$
|
4.79
|
|
|
$
|
9.70
|
|
|
$
|
6.64
|
|
Average Sales Price per Barrel of Oil
|
|
$
|
51.69
|
|
|
$
|
99.64
|
|
|
$
|
57.93
|
|
Average Sales Price per Mcf of Gas (after hedging)
|
|
$
|
6.94
|
|
|
$
|
9.05
|
|
|
$
|
6.98
|
|
Average Sales Price per Barrel of Oil (after hedging)
|
|
$
|
64.94
|
|
|
$
|
81.75
|
|
|
$
|
51.58
|
|
Average Production (Lifting) Cost per Mcf Equivalent of Gas and
Oil Produced
|
|
$
|
1.47
|
|
|
$
|
1.64
|
|
|
$
|
1.35
|
|
Average Production per Day (in MMcf Equivalent of Gas and Oil
Produced)
|
|
|
116
|
|
|
|
111
|
|
|
|
129
|
|
20
Productive
Wells
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gulf Coast
|
|
West Coast
|
|
Appalachian
|
|
|
|
|
Region
|
|
Region
|
|
Region
|
|
Total Company
|
At September 30, 2009
|
|
Gas
|
|
Oil
|
|
Gas
|
|
Oil
|
|
Gas
|
|
Oil
|
|
Gas
|
|
Oil
|
|
Productive Wells Gross
|
|
|
20
|
|
|
|
42
|
|
|
|
|
|
|
|
1,510
|
|
|
|
2,848
|
|
|
|
6
|
|
|
|
2,868
|
|
|
|
1,558
|
|
Productive Wells Net
|
|
|
12
|
|
|
|
14
|
|
|
|
|
|
|
|
1,484
|
|
|
|
2,766
|
|
|
|
5
|
|
|
|
2,778
|
|
|
|
1,503
|
|
Developed
and Undeveloped Acreage
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gulf
|
|
West
|
|
|
|
|
|
|
Coast
|
|
Coast
|
|
Appalachian
|
|
Total
|
At September 30, 2009
|
|
Region
|
|
Region
|
|
Region
|
|
Company
|
|
Developed Acreage
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross
|
|
|
113,934
|
|
|
|
15,118
|
|
|
|
532,872
|
|
|
|
661,924
|
|
Net
|
|
|
80,852
|
|
|
|
12,926
|
|
|
|
504,783
|
|
|
|
598,561
|
|
Undeveloped Acreage
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross
|
|
|
142,118
|
|
|
|
19,002
|
|
|
|
458,182
|
|
|
|
619,302
|
|
Net
|
|
|
102,831
|
|
|
|
10,177
|
|
|
|
437,408
|
|
|
|
550,416
|
|
Total Developed and Undeveloped Acreage
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross
|
|
|
256,052
|
|
|
|
34,120
|
|
|
|
991,054
|
|
|
|
1,281,226
|
|
Net
|
|
|
183,683
|
|
|
|
23,103
|
|
|
|
942,191
|
|
|
|
1,148,977
|
|
As of September 30, 2009, the aggregate amount of gross
undeveloped acreage expiring in the next three years and
thereafter are as follows: 34,887 acres in 2010
(16,764 net acres), 90,456 acres in 2011
(70,162 net acres), 22,222 acres in 2012
(20,532 net acres), and 471,737 acres thereafter
(442,958 net acres).
Drilling
Activity
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive
|
|
Dry
|
For the Year Ended September 30
|
|
2009
|
|
2008
|
|
2007
|
|
2009
|
|
2008
|
|
2007
|
|
United States
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gulf Coast Region
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Wells Completed
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploratory
|
|
|
0.29
|
|
|
|
1.14
|
|
|
|
1.31
|
|
|
|
|
|
|
|
0.37
|
|
|
|
1.42
|
|
Development
|
|
|
|
|
|
|
|
|
|
|
1.00
|
|
|
|
0.30
|
|
|
|
|
|
|
|
0.67
|
|
West Coast Region
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Wells Completed
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploratory
|
|
|
|
|
|
|
1.00
|
|
|
|
0.50
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Development
|
|
|
27.00
|
|
|
|
62.00
|
|
|
|
58.99
|
|
|
|
|
|
|
|
1.00
|
|
|
|
2.00
|
|
Appalachian Region
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Wells Completed
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploratory
|
|
|
2.00
|
|
|
|
8.00
|
|
|
|
8.10
|
|
|
|
3.00
|
|
|
|
1.00
|
|
|
|
|
|
Development
|
|
|
250.00
|
|
|
|
186.00
|
|
|
|
184.00
|
|
|
|
|
|
|
|
|
|
|
|
2.00
|
|
Total United States
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Wells Completed
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploratory
|
|
|
2.29
|
|
|
|
10.14
|
|
|
|
9.91
|
|
|
|
3.00
|
|
|
|
1.37
|
|
|
|
1.42
|
|
Development
|
|
|
277.00
|
|
|
|
248.00
|
|
|
|
243.99
|
|
|
|
0.30
|
|
|
|
1.00
|
|
|
|
4.67
|
|
Canada Discontinued Operations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Wells Completed
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploratory
|
|
|
|
|
|
|
|
|
|
|
6.38
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Development
|
|
|
|
|
|
|
|
|
|
|
1.80
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Wells Completed
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploratory
|
|
|
2.29
|
|
|
|
10.14
|
|
|
|
16.29
|
|
|
|
3.00
|
|
|
|
1.37
|
|
|
|
1.42
|
|
Development
|
|
|
277.00
|
|
|
|
248.00
|
|
|
|
245.79
|
|
|
|
0.30
|
|
|
|
1.00
|
|
|
|
4.67
|
|
21
Present
Activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gulf
|
|
West
|
|
|
|
|
|
|
Coast
|
|
Coast
|
|
Appalachian
|
|
Total
|
At September 30, 2009
|
|
Region
|
|
Region
|
|
Region
|
|
Company
|
|
Wells in Process of Drilling(1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross
|
|
|
|
|
|
|
|
|
|
|
118.00
|
|
|
|
118.00
|
|
Net
|
|
|
|
|
|
|
|
|
|
|
108.50
|
|
|
|
108.50
|
|
|
|
|
(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 I 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 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, 2009.
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 P Market for Common Stock and Related
Shareholder Matters (unaudited).
On July 1, 2009, the Company issued a total of 2,800
unregistered shares of Company common stock to the seven
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,
400 shares to each such director. On September 30,
2009, the Company issued 65 unregistered shares of Company
common stock to Frederic V. Salerno, a non-employee director of
the Company, under the Companys Retainer Policy for
Non-Employee Directors. All of these unregistered shares were
issued as partial consideration for such directors
services during the quarter ended September 30, 2009. These
transactions were exempt from registration under
Section 4(2) of the Securities Act of 1933, as transactions
not involving a public offering.
22
Issuer
Purchases of Equity Securities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Number
|
|
|
Maximum Number
|
|
|
|
|
|
|
|
|
|
of Shares
|
|
|
of Shares
|
|
|
|
|
|
|
|
|
|
Purchased as
|
|
|
that May
|
|
|
|
|
|
|
|
|
|
Part of
|
|
|
Yet Be
|
|
|
|
|
|
|
|
|
|
Publicly Announced
|
|
|
Purchased Under
|
|
|
|
Total Number
|
|
|
Average Price
|
|
|
Share Repurchase
|
|
|
Share Repurchase
|
|
|
|
of Shares
|
|
|
Paid per
|
|
|
Plans or
|
|
|
Plans or
|
|
Period
|
|
Purchased(a)
|
|
|
Share
|
|
|
Programs
|
|
|
Programs(b)
|
|
|
July 1-31, 2009
|
|
|
9,709
|
|
|
$
|
37.77
|
|
|
|
|
|
|
|
6,971,019
|
|
Aug. 1-31, 2009
|
|
|
10,919
|
|
|
$
|
44.52
|
|
|
|
|
|
|
|
6,971,019
|
|
Sept. 1-30, 2009
|
|
|
8,269
|
|
|
$
|
45.98
|
|
|
|
|
|
|
|
6,971,019
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
28,897
|
|
|
$
|
42.67
|
|
|
|
|
|
|
|
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, and (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. During the
quarter ended September 30, 2009, the Company did not
purchase any shares of its common stock pursuant to its publicly
announced share repurchase program. Of the 28,897 shares
purchased other than through a publicly announced share
repurchase program, 26,682 were purchased for the Companys
401(k) plans and 2,215 were purchased as a result of shares
tendered to the Company by holders of stock options or shares of
restricted stock. |
|
(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, 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, either in the open market
or through private transactions. |
23
|
|
Item 6
|
Selected
Financial Data
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended September 30
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(Thousands)
|
|
|
Summary of Operations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Revenues
|
|
$
|
2,057,852
|
|
|
$
|
2,400,361
|
|
|
$
|
2,039,566
|
|
|
$
|
2,239,675
|
|
|
$
|
1,860,774
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchased Gas
|
|
|
1,001,782
|
|
|
|
1,235,157
|
|
|
|
1,018,081
|
|
|
|
1,267,562
|
|
|
|
959,827
|
|
Operation and Maintenance
|
|
|
402,856
|
|
|
|
432,871
|
|
|
|
396,408
|
|
|
|
395,289
|
|
|
|
388,094
|
|
Property, Franchise and Other Taxes
|
|
|
72,163
|
|
|
|
75,585
|
|
|
|
70,660
|
|
|
|
69,202
|
|
|
|
68,164
|
|
Depreciation, Depletion and Amortization
|
|
|
173,410
|
|
|
|
170,623
|
|
|
|
157,919
|
|
|
|
151,999
|
|
|
|
156,502
|
|
Impairment of Oil and Gas Producing Properties
|
|
|
182,811
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,833,022
|
|
|
|
1,914,236
|
|
|
|
1,643,068
|
|
|
|
1,884,052
|
|
|
|
1,572,587
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Income
|
|
|
224,830
|
|
|
|
486,125
|
|
|
|
396,498
|
|
|
|
355,623
|
|
|
|
288,187
|
|
Other Income (Expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from Unconsolidated Subsidiaries
|
|
|
3,366
|
|
|
|
6,303
|
|
|
|
4,979
|
|
|
|
3,583
|
|
|
|
3,362
|
|
Impairment of Investment in Partnership
|
|
|
(1,804
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(4,158
|
)
|
Other Income
|
|
|
6,576
|
|
|
|
7,376
|
|
|
|
4,936
|
|
|
|
2,825
|
|
|
|
12,744
|
|
Interest Income
|
|
|
5,776
|
|
|
|
10,815
|
|
|
|
1,550
|
|
|
|
9,409
|
|
|
|
6,236
|
|
Interest Expense on Long-Term Debt
|
|
|
(79,419
|
)
|
|
|
(70,099
|
)
|
|
|
(68,446
|
)
|
|
|
(72,629
|
)
|
|
|
(73,244
|
)
|
Other Interest Expense
|
|
|
(7,497
|
)
|
|
|
(3,870
|
)
|
|
|
(6,029
|
)
|
|
|
(5,952
|
)
|
|
|
(9,069
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from Continuing Operations Before Income Taxes
|
|
|
151,828
|
|
|
|
436,650
|
|
|
|
333,488
|
|
|
|
292,859
|
|
|
|
224,058
|
|
Income Tax Expense
|
|
|
51,120
|
|
|
|
167,922
|
|
|
|
131,813
|
|
|
|
108,245
|
|
|
|
85,621
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from Continuing Operations
|
|
|
100,708
|
|
|
|
268,728
|
|
|
|
201,675
|
|
|
|
184,614
|
|
|
|
138,437
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Discontinued Operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (Loss) from Operations, Net of Tax
|
|
|
|
|
|
|
|
|
|
|
15,479
|
|
|
|
(46,523
|
)
|
|
|
25,277
|
|
Gain on Disposal, Net of Tax
|
|
|
|
|
|
|
|
|
|
|
120,301
|
|
|
|
|
|
|
|
25,774
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (Loss) from Discontinued Operations, Net of Tax
|
|
|
|
|
|
|
|
|
|
|
135,780
|
|
|
|
(46,523
|
)
|
|
|
51,051
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income Available for Common Stock
|
|
$
|
100,708
|
|
|
$
|
268,728
|
|
|
$
|
337,455
|
|
|
$
|
138,091
|
|
|
$
|
189,488
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
24
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended September 30
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(Thousands)
|
|
|
Per Common Share Data
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic Earnings from Continuing Operations per Common Share
|
|
$
|
1.26
|
|
|
$
|
3.27
|
|
|
$
|
2.43
|
|
|
$
|
2.20
|
|
|
$
|
1.66
|
|
Diluted Earnings from Continuing Operations per Common Share
|
|
$
|
1.25
|
|
|
$
|
3.18
|
|
|
$
|
2.37
|
|
|
$
|
2.15
|
|
|
$
|
1.63
|
|
Basic Earnings per Common Share(1)
|
|
$
|
1.26
|
|
|
$
|
3.27
|
|
|
$
|
4.06
|
|
|
$
|
1.64
|
|
|
$
|
2.27
|
|
Diluted Earnings per Common Share(1)
|
|
$
|
1.25
|
|
|
$
|
3.18
|
|
|
$
|
3.96
|
|
|
$
|
1.61
|
|
|
$
|
2.23
|
|
Dividends Declared
|
|
$
|
1.32
|
|
|
$
|
1.27
|
|
|
$
|
1.22
|
|
|
$
|
1.18
|
|
|
$
|
1.14
|
|
Dividends Paid
|
|
$
|
1.31
|
|
|
$
|
1.26
|
|
|
$
|
1.21
|
|
|
$
|
1.17
|
|
|
$
|
1.13
|
|
Dividend Rate at Year-End
|
|
$
|
1.34
|
|
|
$
|
1.30
|
|
|
$
|
1.24
|
|
|
$
|
1.20
|
|
|
$
|
1.16
|
|
At September 30:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Number of Registered Shareholders
|
|
|
16,098
|
|
|
|
16,544
|
|
|
|
16,989
|
|
|
|
17,767
|
|
|
|
18,369
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Property, Plant and Equipment
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Utility
|
|
$
|
1,144,002
|
|
|
$
|
1,125,859
|
|
|
$
|
1,099,280
|
|
|
$
|
1,084,080
|
|
|
$
|
1,064,588
|
|
Pipeline and Storage
|
|
|
839,424
|
|
|
|
826,528
|
|
|
|
681,940
|
|
|
|
674,175
|
|
|
|
680,574
|
|
Exploration and Production(2)
|
|
|
1,041,846
|
|
|
|
1,095,960
|
|
|
|
982,698
|
|
|
|
1,002,265
|
|
|
|
974,806
|
|
Energy Marketing
|
|
|
71
|
|
|
|
98
|
|
|
|
102
|
|
|
|
59
|
|
|
|
97
|
|
All Other
|
|
|
99,787
|
|
|
|
98,338
|
|
|
|
106,637
|
|
|
|
108,333
|
|
|
|
112,924
|
|
Corporate
|
|
|
6,915
|
|
|
|
7,317
|
|
|
|
7,748
|
|
|
|
8,814
|
|
|
|
6,311
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Net Plant
|
|
$
|
3,132,045
|
|
|
$
|
3,154,100
|
|
|
$
|
2,878,405
|
|
|
$
|
2,877,726
|
|
|
$
|
2,839,300
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Assets
|
|
$
|
4,769,129
|
|
|
$
|
4,130,187
|
|
|
$
|
3,888,412
|
|
|
$
|
3,763,748
|
|
|
$
|
3,749,753
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capitalization
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive Shareholders Equity
|
|
$
|
1,589,236
|
|
|
$
|
1,603,599
|
|
|
$
|
1,630,119
|
|
|
$
|
1,443,562
|
|
|
$
|
1,229,583
|
|
Long-Term Debt, Net of Current Portion
|
|
|
1,249,000
|
|
|
|
999,000
|
|
|
|
799,000
|
|
|
|
1,095,675
|
|
|
|
1,119,012
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Capitalization
|
|
$
|
2,838,236
|
|
|
$
|
2,602,599
|
|
|
$
|
2,429,119
|
|
|
$
|
2,539,237
|
|
|
$
|
2,348,595
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Includes discontinued operations. |
|
(2) |
|
Includes net plant of SECI discontinued operations as follows:
$0 for 2009, 2008 and 2007, $88,023 for 2006, and $170,929 for
2005. |
|
|
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 four 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;
|
25
|
|
|
|
5.
|
Contractual Obligations; and
|
|
|
6.
|
Other Matters, including: (a) 2009 and projected 2010
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
authoritative accounting and financial reporting guidance.
|
The information in MD&A should be read in conjunction with
the Companys financial statements in Item 8 of this
report.
For the year ended September 30, 2009 compared to the year
ended September 30, 2008, the Company experienced a
decrease in earnings of $168.0 million, primarily due to
lower earnings in the Exploration and Production segment. The
earnings decrease was driven largely by an impairment charge of
$182.8 million ($108.2 million after tax) recorded in
the Exploration and Production segment, along with reduced crude
oil and natural gas prices. 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. Such costs are subject to a quarterly
ceiling test prescribed by SEC
Regulation S-X
Rule 4-10
that determines a limit, or ceiling, on the amount of property
acquisition, exploration and development costs that can be
capitalized. At December 31, 2008, due to significant
declines in crude oil and natural gas commodity prices (Cushing,
Oklahoma West Texas Intermediate oil reported spot price of
$44.60 per Bbl at December 31, 2008 versus a reported price
of $100.70 per Bbl at September 30, 2008; Henry Hub natural
gas reported spot price of $5.63 per MMBtu at December 31,
2008 versus a reported price of $7.12 per MMBtu at
September 30, 2008), the book value of the Companys
oil and gas properties exceeded the ceiling, resulting in the
impairment charge mentioned above. (Note Because
actual pricing of the Companys various producing
properties varies depending on their location, the actual
various prices received for such production is utilized to
calculate the ceiling, rather than the Cushing oil and Henry Hub
prices, which are only indicative of current prices.) At
September 30, 2009, the quoted Cushing, Oklahoma spot price
for West Texas Intermediate oil was $70.46 per Bbl ($69.82 per
Bbl at June 30, 2009 and $49.64 per Bbl at March 31,
2009) and the quoted spot price for natural gas was $3.30
per MMBtu ($3.88 per MMBtu at June 30, 2009 and $3.63 per
MMBtu at March 31, 2009). At September 30, 2009, the
ceiling exceeded the book value of the Companys oil and
gas properties by approximately $212 million (and
approximately $247 million and $37 million at
June 30, 2009 and March 31, 2009, respectively). If
natural gas prices used in the ceiling test calculation at
September 30, 2009 had been $1 per MMBtu lower, the ceiling
would have exceeded the book value of the Companys oil and
gas properties by approximately $165 million. If crude oil
prices used in the ceiling test calculation at
September 30, 2009 had been $5 per Bbl lower, the ceiling
would have exceeded the book value of the Companys oil and
gas properties by approximately $160 million. If both
natural gas and crude oil prices used in the ceiling test
calculation at September 30, 2009 were lower by $1 per
MMBtu and $5 per Bbl, respectively, the ceiling would have
exceeded the book value of the Companys oil and gas
properties by approximately $113 million. These calculated
amounts are based solely on price changes and do not take into
account any other changes to the ceiling test calculation.
Despite the decrease in earnings discussed above, the
Companys balance sheet consisted of a capitalization
structure of 56% equity and 44% debt at September 30, 2009.
With its April 2009 issuance of $250.0 million of
8.75% notes due in May 2019, management believes that it
has enhanced its liquidity position at a time when there is
still uncertainty in the credit markets. At September 30,
2009, the Company did not have any short-term borrowings
outstanding. However, the Company continues to maintain a number
of individual uncommitted or discretionary lines of credit with
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, which commitment
extends through September 30, 2010.
26
The Companys liquidity position will become increasingly
important over the next three years. The Company anticipates
spending $413 million for capital expenditures in 2010. In
addition, the Company has identified possible additional
projects where capital expenditures could amount to
$723 million in 2011 and $816 million in 2012. The
majority of these expenditures have been targeted for the
Exploration and Production segment, where the Company
anticipates spending $255 million in 2010
($224 million in Appalachia). Depending on drilling success
in 2010, commodity pricing, and, subject to approval of the
Companys Board of Directors, spending could reach
$417 million in 2011 ($385 million in Appalachia), and
$497 million in 2012 ($444 million in Appalachia). The
significant rise in estimated capital expenditures in the
Exploration and Production segment, specifically in the
Appalachian region, can be attributed to a strong emphasis on
developing natural gas properties in the Marcellus Shale. The
emphasis on Marcellus Shale development will carry over into the
Pipeline and Storage segment, which is anticipating the need for
additional pipeline and storage capacity as Marcellus Shale
production comes on line. Pipeline and Storage segment capital
expenditures are anticipated to be $51 million in 2010,
with opportunities to spend up to $227 million in 2011 and
$240 million in 2012, depending on market acceptance of the
proposed projects, contractual commitments from shippers, and
approval from the Companys Board of Directors. The
projects being considered in the Pipeline and Storage segment
are discussed in detail in the Investing Cash Flow section of
the Capital Resources and Liquidity section that follows. The
Company anticipates financing these capital expenditures with
cash from operations, short-term borrowings and long-term debt.
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.
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.
27
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. At September 30, 2008, the ceiling
exceeded the book value of the Companys oil and gas
properties by approximately $500 million. Because of
declines in commodity prices subsequent to September 30,
2008, the book value of the Companys oil and gas
properties exceeded the ceiling at December 31, 2008. The
quoted Cushing, Oklahoma spot price for West Texas Intermediate
oil had declined from a reported price of $100.70 per Bbl at
September 30, 2008 to a reported price of $44.60 per Bbl at
December 31, 2008. The quoted Henry Hub spot price for
natural gas had declined from a reported price of $7.12 per
MMBtu at September 30, 2008 to a reported price of $5.63
per MMBtu at December 31, 2008. Consequently, the Company
recorded an impairment charge of $182.8 million
($108.2 million after-tax) during the quarter ended
December 31, 2008. (Note Because actual pricing
of the Companys various producing properties varies
depending on their location, the actual various prices received
for such production is utilized to calculate the ceiling, rather
than the Cushing oil and Henry Hub prices, which are only
indicative of current prices.) At September 30, 2009, the
quoted Cushing, Oklahoma spot price for West Texas Intermediate
oil was $70.46 per Bbl ($69.82 per Bbl at June 30, 2009 and
$49.64 per Bbl at March 31, 2009) and the quoted spot
price for natural gas was $3.30 per MMBtu ($3.88 per MMBtu at
June 30, 2009 and $3.63 per MMBtu at March 31, 2009).
At September 30, 2009, the ceiling exceeded the book value
of the Companys oil and gas properties by approximately
$212 million (and approximately $247 million and
$37 million at June 30, 2009 and March 31, 2009,
respectively). If natural gas prices used in the ceiling test
calculation at September 30, 2009 had been $1 per MMBtu
lower, the ceiling would have exceeded the book value of the
Companys oil and gas properties by approximately
$165 million. If crude oil prices used in the ceiling test
calculation at September 30, 2009 had been $5 per Bbl
lower, the ceiling would have exceeded the book value of the
Companys oil and gas properties by approximately
$160 million. If both natural gas and crude oil prices used
in the ceiling test calculation at September 30, 2009 were
lower by $1 per MMBtu and $5 per Bbl, respectively, the ceiling
would have exceeded the book value of the Companys oil and
gas properties by approximately $113 million. These
calculated amounts are based solely on price changes and do not
take into account any other changes to the ceiling test
calculation.
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.
In accordance with the current authoritative guidance for asset
retirement obligations, the Company records an asset retirement
obligation for plugging and abandonment costs associated with
the Exploration and Production segments crude oil and
natural gas wells and capitalizes such costs in property, plant
and equipment (i.e. the full cost pool). Under the current
authoritative guidance for asset retirement obligations, since
plugging and abandonment costs are already included in the full
cost pool, the
units-of-production
depletion calculation
28
excludes from the depletion base any estimate of future plugging
and abandonment costs that are already recorded in the full cost
pool.
As discussed above, the full cost method of accounting provides
a ceiling to the amount of costs that can be capitalized in the
full cost pool. In accordance with current authoritative
guidance, since the full cost pool includes an amount associated
with plugging and abandoning the wells, as discussed in the
preceding paragraph, the calculation of the full cost ceiling no
longer reduces the future net cash flows from proved oil and gas
reserves by an estimate of 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 the FASB authoritative
guidance regarding accounting for certain types of regulations,
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, and Pipeline and
Storage segment, 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 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 authoritative guidance for derivative
instruments and hedging activities, 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 Company adopted the
authoritative guidance for fair value measurements during the
quarter ended December 31, 2008. As such, the fair value of
such derivative financial instruments is determined under the
provisions of this guidance. The fair value of exchange traded
derivative financial instruments is determined from Level 1
inputs, which are quoted prices in active markets. The Company
determines the fair value of non exchange-traded derivative
financial instruments based on an internal model, which uses
both observable and unobservable inputs other than quoted
prices. These inputs are considered Level 2 or Level 3
inputs. All derivative financial instrument assets and
liabilities are evaluated for the probability of default by
either the counterparty or the Company. Credit reserves are
applied against the fair values of such assets or liabilities.
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
29
return on plan assets, the rate of compensation increase and,
for other post-retirement benefits, the expected annual rate of
increase in per capita cost of covered medical and prescription
benefits. The 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, as determined under the authoritative guidance
for pensions and postretirement benefits, represented 90% of the
Companys total pension and post-retirement benefit costs
for the years ended September 30, 2009 and 2008.
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 6.75% in
2008 to 5.50% in 2009. The change in the discount rate from 2008
to 2009 increased the Retirement Plan projected benefit
obligation by $102.6 million and the accumulated
post-retirement benefit obligation by $60.9 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 2009, actual
versus expected return on plan assets resulted in a decrease to
the funded status of the Retirement Plan ($157.5 million)
and the VEBA trusts and 401(h) accounts ($94.0 million).
The actual versus expected benefit payments for 2009 caused a
decrease of $2.2 million to the accumulated post-retirement
benefit obligation. 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
9 years for the Retirement Plan and 8 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 FASB revised accounting
guidance for defined benefit pensions and other postretirement
plans, and to Item 8 at Note H Retirement
Plan and Other Post Retirement Benefits.
30
RESULTS
OF OPERATIONS
EARNINGS
2009
Compared with 2008
The Companys earnings were $100.7 million in 2009
compared with earnings of $268.7 million in 2008. The
decrease in earnings of $168.0 million is primarily the
result of lower earnings in the Exploration and Production,
Pipeline and Storage and Utility segments and the All Other
category, slightly offset by a lower loss in the Corporate
category and higher earnings in the Energy Marketing segment, 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 were impacted by
several events in 2009 and 2008, including:
2009
Events
|
|
|
|
|
A non-cash $182.8 million impairment charge
($108.2 million after tax) recorded during the quarter
ended December 31, 2008 for the Exploration and Production
segments oil and gas producing properties;
|
|
|
|
A $2.8 million impairment in the value of certain landfill
gas assets in the All Other category;
|
|
|
|
A $1.1 million impairment in the value of the
Companys 50% investment in ESNE (recorded in the All Other
category), a limited liability company that owns an 80-megawatt,
combined cycle, natural gas-fired power plant in the town of
North East, Pennsylvania; and
|
|
|
|
A $2.3 million death benefit gain on life insurance
policies recognized in the Corporate category.
|
2008
Event
|
|
|
|
|
A $0.6 million gain in the All Other category associated
with the sale of Horizon Powers gas-powered turbine.
|
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 Pipeline and Storage and Energy
Marketing segments, as shown in the table below. Earnings from
continuing operations and discontinued operations were impacted
by the 2008 event discussed above and the following 2007 events:
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.
|
31
Earnings
(Loss) by Segment
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended September 30
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
(Thousands)
|
|
|
Utility
|
|
$
|
58,664
|
|
|
$
|
61,472
|
|
|
$
|
50,886
|
|
Pipeline and Storage
|
|
|
47,358
|
|
|
|
54,148
|
|
|
|
56,386
|
|
Exploration and Production
|
|
|
(10,238
|
)
|
|
|
146,612
|
|
|
|
74,889
|
|
Energy Marketing
|
|
|
7,166
|
|
|
|
5,889
|
|
|
|
7,663
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Reported Segments
|
|
|
102,950
|
|
|
|
268,121
|
|
|
|
189,824
|
|
All Other
|
|
|
(2,071
|
)
|
|
|
5,779
|
|
|
|
6,292
|
|
Corporate
|
|
|
(171
|
)
|
|
|
(5,172
|
)
|
|
|
5,559
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Earnings from Continuing Operations
|
|
|
100,708
|
|
|
|
268,728
|
|
|
|
201,675
|
|
Earnings from Discontinued Operations
|
|
|
|
|
|
|
|
|
|
|
135,780
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Consolidated
|
|
$
|
100,708
|
|
|
$
|
268,728
|
|
|
$
|
337,455
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
UTILITY
Revenues
Utility
Operating Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended September 30
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
(Thousands)
|
|
|
Retail Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
Residential
|
|
$
|
850,088
|
|
|
$
|
876,677
|
|
|
$
|
848,693
|
|
Commercial
|
|
|
128,520
|
|
|
|
135,361
|
|
|
|
136,863
|
|
Industrial
|
|
|
7,213
|
|
|
|
7,419
|
|
|
|
8,271
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
985,821
|
|
|
|
1,019,457
|
|
|
|
993,827
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Off-System Sales
|
|
|
3,740
|
|
|
|
58,225
|
|
|
|
9,751
|
|
Transportation
|
|
|
111,483
|
|
|
|
113,901
|
|
|
|
102,534
|
|
Other
|
|
|
11,980
|
|
|
|
18,686
|
|
|
|
14,612
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
1,113,024
|
|
|
$
|
1,210,269
|
|
|
$
|
1,120,724
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Utility
Throughput million cubic feet (MMcf)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended September 30
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
Retail Sales:
|
|
|
|
|
|
|
|
|
|
|
|
|
Residential
|
|
|
58,835
|
|
|
|
57,463
|
|
|
|
60,236
|
|
Commercial
|
|
|
9,551
|
|
|
|
9,769
|
|
|
|
10,713
|
|
Industrial
|
|
|
515
|
|
|
|
552
|
|
|
|
727
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
68,901
|
|
|
|
67,784
|
|
|
|
71,676
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Off-System Sales
|
|
|
513
|
|
|
|
5,686
|
|
|
|
1,355
|
|
Transportation
|
|
|
59,751
|
|
|
|
64,267
|
|
|
|
62,240
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
129,165
|
|
|
|
137,737
|
|
|
|
135,271
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
32
Degree
Days
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Percent (Warmer)
|
|
|
|
|
|
|
|
|
Colder Than
|
Year Ended September 30
|
|
|
|
Normal
|
|
Actual
|
|
Normal
|
|
Prior Year
|
|
2009:
|
|
|
Buffalo
|
|
|
|
6,692
|
|
|
|
6,701
|
|
|
|
0.1
|
%
|
|
|
6.8
|
%
|
|
|
|
Erie
|
|
|
|
6,243
|
|
|
|
6,176
|
|
|
|
(1.1
|
)%
|
|
|
6.9
|
%
|
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
|
%
|
2009
Compared with 2008
Operating revenues for the Utility segment decreased
$97.2 million in 2009 compared with 2008. This decrease
largely resulted from a $54.5 million decrease in
off-system sales revenue (see discussion below), a
$33.6 million decrease in retail gas sales revenues, a
$2.4 million decrease in transportation revenues, and a
$6.7 million decrease in other operating revenues.
The decrease in retail gas sales revenues of $33.6 million
was largely a function of the recovery of lower gas costs
(subject to certain timing variations, gas costs are recovered
dollar for dollar in revenues). The recovery of lower gas costs
resulted from a much lower cost of purchased gas. See further
discussion of purchased gas below under the heading
Purchased Gas. The decrease in transportation
revenues of $2.4 million was primarily due to a
4.5 Bcf decrease in transportation throughput, largely the
result of customer conservation efforts and the poor economy.
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. As a
result of this rate order, retail and transportation revenues
for 2009 were $2.2 million lower than revenues for 2008.
The Utility segment had off-system sales revenues of
$3.7 million and $58.2 million for 2009 and 2008,
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 2009 and 2008. The
decrease in off-system sales revenue stems from Order
No. 717 (Final Rule), which was issued by the
FERC on October 16, 2008. The Final Rule seemingly held
that a local distribution company making off-system sales on
unaffiliated pipelines would be engaging in
marketing that would require compliance with the
FERCs standards of conduct. Accordingly, pending
clarification of this issue from the FERC, as of
November 1, 2008, Distribution Corporation ceased
off-system sales activities. On October 15, 2009, the FERC
released Order
No. 717-A,
which clarified that a local distribution company making
off-system sales of gas that has been transported on
non-affiliated pipelines is not subject to the standards of
conduct. In light of and in reliance on this clarification,
Distribution Corporation determined that it may resume engaging
in off-system sales on non-affiliated pipelines. Such off-system
sales resumed in November 2009.
The decrease in other operating revenues of $6.7 million is
largely related to amounts recorded in 2008 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. In 2009, Distribution Corporation utilized only
$0.2 million of the cost mitigation reserve. The impact of
this $5.4 million decrease in other operating revenues was
offset by an equal decrease to operation and maintenance expense
(thus there is no earnings impact).
33
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. 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.
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 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).
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, Empire 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 $8.17 per Mcf in 2009, a
34
decrease of 27% from the average cost of $11.23 per Mcf in 2008.
The average cost of purchased gas in 2008 was 12% higher than
the average cost of $10.04 per Mcf in 2007. Additional
discussion of the Utility segments gas purchases appears
under the heading Sources and Availability of Raw
Materials in Item 1.
Earnings
2009
Compared with 2008
The Utility segments earnings in 2009 were
$58.7 million, a decrease of $2.8 million when
compared with earnings of $61.5 million in 2008.
In the New York jurisdiction, earnings decreased by
$3.0 million. This was primarily due to an increase in
interest expense ($2.9 million) stemming from the borrowing
by the New York jurisdiction of Distribution Corporation of a
portion of the Companys April 2009 debt issuance. The
April 2009 debt was issued at a significantly higher interest
rate than the interest rates on debt that had matured in March
2009. The negative earnings impact of the December 28, 2007
rate order discussed above ($1.4 million) and routine
regulatory adjustments ($0.7 million) also contributed to
the decrease. The decrease was partially offset by a
$2.6 million overall reduction in operating expenses
(mostly other post-retirement benefits and pension expense).
In the Pennsylvania jurisdiction, earnings increased by
$0.2 million. This was primarily due to the positive
earnings impact of colder weather ($2.1 million), routine
regulatory adjustments ($0.5 million) and lower operating
expenses ($0.9 million). A decrease in normalized usage per
account ($2.3 million), a higher effective tax rate
($1.4 million) and an increase in interest expense
($0.2 million) partially offset these increases. The phrase
usage per account refers to the average gas
consumption per customer account after factoring out any impact
that weather may have had on consumption.
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. For 2009, the WNC reduced earnings by
approximately $0.2 million, as the weather was colder than
normal. For 2008, the WNC preserved earnings of approximately
$2.5 million, as the weather was warmer than normal.
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 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.
35
PIPELINE
AND STORAGE
Revenues
Pipeline
and Storage Operating Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended September 30
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
(Thousands)
|
|
|
Firm Transportation
|
|
$
|
139,034
|
|
|
$
|
122,321
|
|
|
$
|
118,771
|
|
Interruptible Transportation
|
|
|
3,175
|
|
|
|
4,330
|
|
|
|
4,161
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
142,209
|
|
|
|
126,651
|
|
|
|
122,932
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Firm Storage Service
|
|
|
66,711
|
|
|
|
67,020
|
|
|
|
66,966
|
|
Interruptible Storage Service
|
|
|
20
|
|
|
|
14
|
|
|
|
169
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
66,731
|
|
|
|
67,034
|
|
|
|
67,135
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
|
|
|
10,333
|
|
|
|
22,871
|
|
|
|
21,899
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
219,273
|
|
|
$
|
216,556
|
|
|
$
|
211,966
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pipeline
and Storage Throughput (MMcf)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended September 30
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
Firm Transportation
|
|
|
356,771
|
|
|
|
353,173
|
|
|
|
351,113
|
|
Interruptible Transportation
|
|
|
4,070
|
|
|
|
5,197
|
|
|
|
4,975
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
360,841
|
|
|
|
358,370
|
|
|
|
356,088
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009
Compared with 2008
Operating revenues for the Pipeline and Storage segment
increased $2.7 million in 2009 as compared with 2008. The
increase was primarily due to a $15.6 million increase in
transportation revenue primarily due to higher revenues from the
Empire Connector and new contracts for transportation service.
Partially offsetting this increase, efficiency gas revenues
decreased $11.5 million (reported as a part of other
revenue in the table above). The majority of this decrease was
due to significantly lower gas prices in 2009 as compared to
2008. Under Supply Corporations tariff with suppliers,
Supply Corporation is allowed to retain a set percentage of
shipper-supplied gas to cover compressor fuel costs and other
operational purposes. To the extent that Supply Corporation does
not need all of the gas to cover such operational needs, it is
allowed to keep the excess gas as inventory. That inventory is
later sold to customers. The excess gas that is retained as
inventory represents efficiency gas revenue to Supply
Corporation.
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 and 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)
primarily due to higher gas prices in the current year.
Earnings
2009
Compared with 2008
The Pipeline and Storage segments earnings in 2009 were
$47.4 million, a decrease of $6.7 million when
compared with earnings of $54.1 million in 2008. The
decrease was primarily due to the earnings impact
36
associated with a decrease in efficiency gas revenues
($7.5 million), as discussed above. In addition, higher
interest expense ($5.1 million), higher depreciation
expense ($1.5 million), and a decrease in the allowance for
funds used during construction ($2.0 million) also
contributed to the decrease in earnings. The increase in
interest expense can be attributed to higher debt balances and a
higher average interest rate on borrowings. The increase in the
average interest rate stems from the borrowing of a portion of
the Companys April 2009 debt issuance. The increase in
depreciation expense can be attributed primarily to a revision
of accumulated depreciation combined with the increased
depreciation associated with placing the Empire Connector in
service in December 2008. The decease in the allowance for funds
used during construction was due to completion of the Empire
Connector project in December 2008. Whereas the allowance for
funds used during construction related to the Empire Connector
project was recorded throughout 2008, it was only recorded for
three months in 2009. These earnings decreases were partially
offset by the earnings impact associated with higher
transportation revenues ($9.7 million), as discussed above.
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 ($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).
EXPLORATION
AND PRODUCTION
Revenues
Exploration
and Production Operating Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended September 30
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
(Thousands)
|
|
|
Gas (after Hedging) from Continuing Operations
|
|
$
|
154,582
|
|
|
$
|
202,153
|
|
|
$
|
143,785
|
|
Oil (after Hedging) from Continuing Operations
|
|
|
219,046
|
|
|
|
250,965
|
|
|
|
167,627
|
|
Gas Processing Plant from Continuing Operations
|
|
|
24,686
|
|
|
|
49,090
|
|
|
|
37,528
|
|
Other from Continuing Operations
|
|
|
432
|
|
|
|
(944
|
)
|
|
|
1,147
|
|
Intrasegment Elimination from Continuing Operations(1)
|
|
|
(15,988
|
)
|
|
|
(34,504
|
)
|
|
|
(26,050
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Revenues from Continuing Operations
|
|
$
|
382,758
|
|
|
$
|
466,760
|
|
|
$
|
324,037
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Revenues from Canada Discontinued
Operations
|
|
$
|
|
|
|
$
|
|
|
|
$
|
50,495
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(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. |
37
Production
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended September 30
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
Gas Production (MMcf)
|
|
|
|
|
|
|
|
|
|
|
|
|
Gulf Coast
|
|
|
9,886
|
|
|
|
11,033
|
|
|
|
10,356
|
|
West Coast
|
|
|
4,063
|
|
|
|
4,039
|
|
|
|
3,929
|
|
Appalachia
|
|
|
8,335
|
|
|
|
7,269
|
|
|
|
5,555
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Production from Continuing Operations
|
|
|
22,284
|
|
|
|
22,341
|
|
|
|
19,840
|
|
Canada Discontinued Operations
|
|
|
|
|
|
|
|
|
|
|
6,426
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Production
|
|
|
22,284
|
|
|
|
22,341
|
|
|
|
26,266
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil Production (Mbbl)
|
|
|
|
|
|
|
|
|
|
|
|
|
Gulf Coast
|
|
|
640
|
|
|
|
505
|
|
|
|
717
|
|
West Coast
|
|
|
2,674
|
|
|
|
2,460
|
|
|
|
2,403
|
|
Appalachia
|
|
|
59
|
|
|
|
105
|
|
|
|
124
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Production from Continuing Operations
|
|
|
3,373
|
|
|
|
3,070
|
|
|
|
3,244
|
|
Canada Discontinued Operations
|
|
|
|
|
|
|
|
|
|
|
206
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Production
|
|
|
3,373
|
|
|
|
3,070
|
|
|
|
3,450
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average
Prices
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended September 30
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
Average Gas Price/Mcf
|
|
|
|
|
|
|
|
|
|
|
|
|
Gulf Coast
|
|
$
|
4.54
|
|
|
$
|
10.03
|
|
|
$
|
6.58
|
|
West Coast
|
|
$
|
3.91
|
|
|
$
|
8.71
|
|
|
$
|
6.54
|
|
Appalachia
|
|
$
|
5.52
|
|
|
$
|
9.73
|
|
|
$
|
7.48
|
|
Weighted Average for Continuing Operations
|
|
$
|
4.79
|
|
|
$
|
9.70
|
|
|
$
|
6.82
|
|
Weighted Average After Hedging for Continuing Operations(1)
|
|
$
|
6.94
|
|
|
$
|
9.05
|
|
|
$
|
7.25
|
|
Canada Discontinued Operations
|
|
$
|
|
|
|
$
|
|
|
|
$
|
6.09
|
|
Average Oil Price/Barrel (bbl)
|
|
|
|
|
|
|
|
|
|
|
|
|
Gulf Coast
|
|
$
|
54.58
|
|
|
$
|
107.27
|
|
|
$
|
63.04
|
|
West Coast(2)
|
|
$
|
50.90
|
|
|
$
|
98.17
|
|
|
$
|
56.86
|
|
Appalachia
|
|
$
|
56.15
|
|
|
$
|
97.40
|
|
|
$
|
62.26
|
|
Weighted Average for Continuing Operations
|
|
$
|
51.69
|
|
|
$
|
99.64
|
|
|
$
|
58.43
|
|
Weighted Average After Hedging for Continuing Operations(1)
|
|
$
|
64.94
|
|
|
$
|
81.75
|
|
|
$
|
51.68
|
|
Canada Discontinued Operations
|
|
$
|
|
|
|
$
|
|
|
|
$
|
50.06
|
|
|
|
|
(1) |
|
Refer to further discussion of hedging activities below under
Market Risk Sensitive Instruments and in
Note G Financial Instruments in Item 8 of
this report. |
|
(2) |
|
Includes low gravity oil which generally sells for a lower price. |
2009
Compared with 2008
Operating revenues from continuing operations for the
Exploration and Production segment decreased $84.0 million
in 2009 as compared with 2008. Gas production revenue after
hedging from continuing operations decreased $47.6 million
primarily due to a $2.11 per Mcf decrease in weighted average
prices after hedging. Gas production from continuing operations
was virtually flat with the prior year as production
38
decreases in the Gulf Coast region were substantially offset by
production increases in the Appalachian region. The decrease in
gas production from continuing operations that occurred in the
Gulf Coast region (1,147 MMcf) was a result of lingering
shut-ins caused by Hurricanes Edouard, Gustav and Ike in
September 2008. While Senecas properties sustained only
superficial damage from the hurricanes, two significant
producing properties were shut-in for a significant portion of
the current fiscal year due to repair work on third party
pipelines and onshore processing facilities. One of the
properties was back on line by March 31, 2009 and the other
property was back on line by the end of April 2009. The increase
in gas production from continuing operations in the Appalachian
region of 1,066 MMcf resulted from additional wells drilled
throughout fiscal 2008 that came on line in 2009. Oil production
revenue after hedging from continuing operations decreased
$31.9 million due to a $16.81 per barrel decrease in
weighted average prices after hedging, which more than offset an
increase in oil production from continuing operations of
303,000 barrels (primarily from the West Coast and Gulf
Coast regions). In addition, there was a $5.9 million
decrease in gross processing plant revenues from continuing
operations (net of eliminations) due to a reduction in the
commodity prices of residual gas and liquids sold at
Senecas processing plants in the West Coast and
Appalachian regions.
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.
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 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 from continuing operations. 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.
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
2009
Compared with 2008
The Exploration and Production segments loss from
continuing operations for 2009 was $10.2 million, compared
with earnings from continuing operations of $146.6 million
for 2008, a decrease of $156.8 million. The decrease in
earnings is primarily the result of an impairment charge of
$108.2 million, as discussed above. In addition, lower
crude oil prices, lower natural gas prices, and lower natural
gas production decreased earnings by $36.9 million,
$30.6 million, and $0.3 million, respectively, while
higher crude oil production increased earnings by
$16.1 million. Lower interest income ($5.5 million)
and higher operating expenses ($1.7 million) further
reduced earnings. In addition, there was a $3.8 million
decrease in earnings caused by a reduction in the commodity
prices of residual gas and liquids sold at Senecas
processing plants in the West Coast and Appalachian regions. The
decrease in interest income is due to lower interest rates and
lower temporary cash investment balances. The increase in
operating expenses is due to an increase in bad debt expense as
a result of a customers bankruptcy filing, and higher
personnel costs in the Appalachian region. These earnings
decreases were partially offset by lower interest expense
($5.4 million), lower lease operating costs
($2.6 million), lower depletion expense
($0.9 million), and lower income tax expense
($4.2 million). The
39
decline in interest expense is primarily due to a lower average
amount of debt outstanding. The reduction in lease operating
expenses is primarily due to a reduction in steam fuel costs in
the West Coast region and lower production taxes in the Gulf
Coast region. The decrease in depletion is primarily due to a
lower full cost pool balance after the impairment charge taken
during the quarter ended December 31, 2008.
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.
ENERGY
MARKETING
Revenues
Energy
Marketing Operating Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended September 30
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
(Thousands)
|
|
|
Natural Gas (after Hedging)
|
|
$
|
398,205
|
|
|
$
|
551,243
|
|
|
$
|
413,405
|
|
Other
|
|
|
116
|
|
|
|
(11
|
)
|
|
|
207
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
398,321
|
|
|
$
|
551,232
|
|
|
$
|
413,612
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy
Marketing Volume
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended September 30
|
|
|
2009
|
|
2008
|
|
2007
|
|
Natural Gas (MMcf)
|
|
|
60,858
|
|
|
|
56,120
|
|
|
|
50,775
|
|
2009
Compared with 2008
Operating revenues for the Energy Marketing segment decreased
$152.9 million in 2009 as compared with 2008. The decrease
is primarily due to lower gas sales revenue, due to a lower
average price of natural gas that was recovered through
revenues. This decline was somewhat offset by an increase in
volume sold. The increase in sales volume is largely
attributable to colder weather as well as an increase in sales
transactions undertaken at the Niagara pipeline delivery point
to offset certain basis risks that the Energy Marketing segment
was exposed to under certain fixed basis commodity purchase
contracts for Appalachian production. Such offsetting
transactions had the effect of increasing revenue and volume
sold with minimal impact to earnings.
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 volume sold. The increase
in volume is
40
primarily attributable to an increase in volume 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 volume also reflects
certain sales transactions undertaken at the Niagara pipeline
delivery point to offset certain basis risks that the Energy
Marketing segment was exposed to under certain fixed basis
commodity purchase contracts for Appalachian production. Such
offsetting transactions had the effect of increasing revenue and
volume sold with minimal impact to earnings.
Earnings
2009
Compared with 2008
The Energy Marketing segments earnings in 2009 were
$7.2 million, an increase of $1.3 million when
compared with earnings of $5.9 million in 2008. Higher
margin of $1.5 million combined with lower operating costs
of $0.4 million (primarily due to a decline in bad debt
expense) are responsible for the increase in earnings. These
increases were partially offset by higher income tax expense of
$0.4 million in 2009 as compared to 2008. The increase in
margin was primarily driven by lower pipeline transportation
fuel costs due to lower natural gas commodity prices, an
unfavorable pipeline imbalance resolution in fiscal 2008 that
did not recur in fiscal 2009, and improved average margins per
Mcf, partially offset by higher pipeline reservation charges
related to additional storage capacity.
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 margin 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 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 volume 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.
ALL OTHER
AND CORPORATE OPERATIONS
All Other and Corporate operations primarily includes the
operations of Highland, Senecas Northeast Division,
Midstream Corporation, Horizon LFG, Horizon Power, former
International segment activity and corporate operations.
Highland and Senecas Northeast Division market timber from
their New York and Pennsylvania land holdings, own two sawmill
operations in northwestern Pennsylvania and process timber
consisting primarily of high quality hardwoods. Midstream
Corporation is a Pennsylvania corporation formed to build, own
and operate natural gas processing and pipeline gathering
facilities in the Appalachian region. 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
2009
Compared with 2008
All Other and Corporate operations had a loss of
$2.2 million in 2009, a decrease of $2.8 million
compared with earnings of $0.6 million for 2008. The
decrease in earnings was largely attributable to lower margins
from lumber, log and timber rights sales ($2.5 million),
lower margins from Horizon LFG ($1.6 million), lower
interest income ($0.6 million), lower income from Horizon
Powers investments in unconsolidated subsidiaries
41
($2.0 million), and higher interest expense
($3.1 million). The decrease in margins from lumber, log
and timber rights sales is a result of a decline in revenues due
to unfavorable market conditions. The decrease in margins from
Horizon LFG is due to the decrease in the price of gas and lower
volumes due to the poor economy. The increase in interest
expense was primarily the result of higher borrowings at a
higher interest rate (mostly due to the $250 million of
8.75% notes that were issued in April 2009). In addition,
during 2009, ESNE, an unconsolidated subsidiary of Horizon
Power, recorded an impairment charge of $3.6 million.
Horizon Powers 50% share of the impairment was
$1.8 million ($1.1 million on an after tax basis). In
2009, Horizon LFG recorded an impairment charge of
$4.6 million on its landfill gas assets ($2.8 million
on an after-tax basis). Also, Horizon Power recognized a gain on
the sale of a turbine ($0.6 million) during 2008 that did
not recur in 2009. These earnings decreases were partially
offset by lower operating costs ($4.9 million). In 2008,
the proxy contest with New Mountain Vantage GP, L.L.C. led to an
increase in operating costs, which did not recur in 2009. In
addition, lower income tax expense ($4.3 million) and a
gain on life insurance policies held by the Company
($2.3 million) further offset the earnings decrease.
The impairment charge of $4.6 million recorded by Horizon
LFG during 2009 (as discussed above) was comprised of a
$2.6 million reduction in intangible assets related to
long-term gas purchase contracts and a $2.0 million
reduction in property, plant and equipment. The impairment was
recorded due to the loss of the primary customer at a landfill
gas site and the anticipated shut-down of the site. This
impairment charge reduced the recorded value of intangible
assets and property, plant and equipment associated with this
site to zero at September 30, 2009.
The impairment charge of $3.6 million recorded by ESNE
during 2009 (as discussed above) was driven by a significant
decrease in run time for the plant given the
economic downturn and the resulting decrease in demand for
electric power.
2008
Compared with 2007
All Other and Corporate operations had earnings of
$0.6 million in 2008, a decrease of $11.3 million
compared with earnings of $11.9 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 ($5.9 million), higher
income tax expense ($0.9 million), lower interest income
($1.5 million) and lower margins from lumber, log and
timber rights sales ($4.2 million). The increase in
operating costs is primarily the result of the proxy contest
with New Mountain Vantage GP, L.L.C. The decrease in margins
from lumber, log and timber rights sales is a result of a
decline in revenues due to unfavorable market conditions and wet
weather conditions that hampered harvesting. In addition, in
2007, Senecas Northeast Division sold 3.1 million
board feet of timber rights and recorded a gain of
$1.6 million in other revenues, which did not recur in 2008.
INTEREST
INCOME
Interest income was $5.0 million lower in 2009 as compared
to 2008. Lower cash investment balances in the Exploration and
Production segment and lower interest rates on such investments
were the primary factors contributing to this decrease.
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.
OTHER
INCOME
Other income was $0.8 million lower in 2009 as compared to
2008. This decrease is attributed to a $1.7 million
decrease in the allowance for funds used during construction in
the Pipeline and Storage segment associated with the Empire
Connector project. Horizon Power recognized a $0.9 million
pre-tax gain on the sale of a turbine during 2008 that did not
recur in 2009. These decreases were partially offset by a death
benefit gain on life insurance policies of $2.3 million
recognized in the Corporate category during 2009.
42
Other income was $2.4 million higher in 2008 as compared to
2007. This increase is primarily attributed to a
$4.2 million increase in the allowance for funds used
during construction in the Pipeline and Storage segment
associated with the Empire Connector project. It also reflects a
$0.9 million pre-tax gain on the sale of a turbine during
2008. These increases were 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.
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 $9.3 million in 2009
as compared to 2008. The increase in 2009 was primarily the
result of a higher average amount of long-term debt outstanding
combined with higher average interest rates. In April 2009, the
Company issued $250 million of 8.75% senior, unsecured
notes due in May 2019. This increase was partially offset by the
repayment of $100 million of 6% medium-term notes that
matured in March 2009.
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.
Other interest charges increased $3.6 million in 2009
compared to 2008. The increase in 2009 was primarily caused by a
$2.3 million increase in interest expense on regulatory
deferrals (primarily deferred gas costs) in the Utility
segments New York jurisdiction combined with a
$0.7 million decrease in the allowance for borrowed funds
used during construction related to the Empire Connector project.
Other interest charges decreased $2.2 million in 2008
compared to 2007. 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.
43
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
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
|
|
|
(Millions)
|
|
|
|
|
|
Provided by Operating Activities
|
|
$
|
609.4
|
|
|
$
|
482.8
|
|
|
$
|
394.2
|
|
Capital Expenditures
|
|
|
(309.9
|
)
|
|
|
(397.7
|
)
|
|
|
(276.7
|
)
|
Investment in Subsidiary, Net of Cash Acquired
|
|
|
(34.9
|
)
|
|
|
|
|
|
|
|
|
Investment in Partnerships
|
|
|
(1.3
|
)
|
|
|
|
|
|
|
(3.3
|
)
|
Net Proceeds from Sale of Foreign Subsidiaries
|
|
|
|
|
|
|
|
|
|
|
232.1
|
|
Cash Held in Escrow
|
|
|
(2.0
|
)
|
|
|
58.4
|
|
|
|
(58.2
|
)
|
Net Proceeds from Sale of Oil and Gas Producing Properties
|
|
|
3.6
|
|
|
|
5.9
|
|
|
|
5.1
|
|
Other Investing Activities
|
|
|
(2.8
|
)
|
|
|
4.4
|
|
|
|
(0.8
|
)
|
Reduction of Long-Term Debt
|
|
|
(100.0
|
)
|
|
|
(200.0
|
)
|
|
|
(119.6
|
)
|
Net Proceeds from Issuance of Long-Term Debt
|
|
|
247.8
|
|
|
|
296.6
|
|
|
|
|
|
Net Proceeds from Issuance of Common Stock
|
|
|
28.2
|
|
|
|
17.4
|
|
|
|
17.5
|
|
Dividends Paid on Common Stock
|
|
|
(104.2
|
)
|
|
|
(103.7
|
)
|
|
|
(100.6
|
)
|
Excess Tax Benefits Associated with Stock- Based Compensation
Awards
|
|
|
5.9
|
|
|
|
16.3
|
|
|
|
13.7
|
|
Shares Repurchased under Repurchase Plan
|
|
|
|
|
|
|
(237.0
|
)
|
|
|
(48.1
|
)
|
Effect of Exchange Rates on Cash
|
|
|
|
|
|
|
|
|
|
|
(0.1
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Increase (Decrease) in Cash and Temporary Cash Investments
|
|
$
|
339.8
|
|
|
$
|
(56.6
|
)
|
|
$
|
55.2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 the straight fixed-variable rate
design used by Supply Corporation and Empire.
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
$609.4 million in 2009, an increase of $126.6 million
compared with the $482.8 million provided by operating
activities in 2008. The increase is primarily due to the timing
of gas cost recovery in the Utility segment. As gas prices
decreased significantly during 2009, the Companys Utility
segment experienced an over-recovery of gas costs that is
reflected in Amounts Payable to Customers on the Companys
Consolidated Balance Sheet at September 30, 2009. At
September 30, 2008, the
44
Companys Utility segment was in an under-recovery
position. It is expected that the over-recovery at
September 30, 2009 will be passed back to customers in 2010.
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. In the Utility segment, lower cash payments
for gas costs offset partially by lower cash receipts for retail
and transportation services resulted in higher cash provided by
operations. In the Exploration and Production segment, cash
provided by operations increased due to higher cash receipts
from the sale of oil and gas production, largely a result of
higher commodity prices. This increase in the Exploration and
Production segment was partially offset by a decrease in cash
provided by operations that resulted from the sale of SECI, a
discontinued operation, in August 2007. Cash provided by
operating activities from SECI was $0.3 million in 2007.
Partially offsetting these increases, the Energy Marketing
segment experienced a decrease in cash provided by operations
due to the timing of gas cost recovery.
INVESTING
CASH FLOW
Expenditures
for Long-Lived Assets
The Companys expenditures from continuing operations for
long-lived assets totaled $339.2 million,
$414.5 million and $250.9 million in 2009, 2008 and
2007, respectively. The table below presents these expenditures:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended September 30
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
|
|
|
(Millions)
|
|
|
|
|
|
Utility:
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital Expenditures
|
|
$
|
56.2
|
|
|
$
|
57.5
|
|
|
$
|
54.2
|
|
Pipeline and Storage:
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital Expenditures
|
|
|
50.1
|
(1)
|
|
|
165.5
|
(1)
|
|
|
43.2
|
|
Exploration and Production:
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital Expenditures
|
|
|
188.3
|
(2)
|
|
|
192.2
|
|
|
|
146.7
|
|
Investment in Subsidiary
|
|
|
34.9
|
(3)
|
|
|
|
|
|
|
|
|
All Other and Corporate:
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital Expenditures
|
|
|
8.7
|
(4)
|
|
|
1.7
|
|
|
|
3.5
|
|
Investment in Partnerships
|
|
|
1.3
|
|
|
|
|
|
|
|
3.3
|
|
Eliminations
|
|
|
(0.3
|
)(5)
|
|
|
(2.4
|
)(6)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Expenditures from Continuing Operations
|
|
$
|
339.2
|
|
|
$
|
414.5
|
|
|
$
|
250.9
|
(7)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Amount for 2009 excludes $16.8 million of accrued capital
expenditures related to the Empire Connector project accrued at
September 30, 2008 and paid during the year ended
September 30, 2009. This amount was included in 2008
capital expenditures shown in the table above, but was excluded
from the Consolidated Statement of Cash Flows at
September 30, 2008 since it represented a non-cash
investing activity at that date. The amount has been included in
the Consolidated Statement of Cash Flows at September 30,
2009. |
|
(2) |
|
Amount for 2009 includes $9.1 million of accrued capital
expenditures, the majority of which was in the Appalachian
region. This amount has been excluded from the Consolidated
Statement of Cash Flows at September 30, 2009 since it
represents a non-cash investing activity at that date. |
|
(3) |
|
Investment amount is net of $4.3 million of cash acquired. |
|
(4) |
|
Amount for 2009 includes $0.7 million of accrued capital
expenditures related to the construction of the Midstream
Covington Gathering System. This amount has been excluded from
the Consolidated Statement of Cash Flows at September 30,
2009 since it represents a non-cash investing activity at that
date. |
45
|
|
|
(5) |
|
Represents $0.3 million of capital expenditures in the
Pipeline and Storage segment for the purchase of pipeline
facilities from the Appalachian region of the Exploration and
Production segment during the quarter ended December 31,
2008. |
|
(6) |
|
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. |
|
(7) |
|
Excludes expenditures for long-lived assets associated with
discontinued operations of $29.1 million. |
Utility
The majority of the Utility capital expenditures for 2009, 2008
and 2007 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 for 2009 and 2008 were related to the Empire
Connector project, which was placed into service on
December 10, 2008, as well as for additions, improvements,
and replacements to this segments transmission and gas
storage systems. The majority of the Pipeline and Storage
segments capital expenditures for 2007 were made for
additions, improvements, and replacements to this segments
transmission and gas storage systems. The Empire Connector
project was completed for a cost of approximately
$192 million. The Company capitalized Empire Connector
project costs of $27.3 million, $149.2 million and
$15.5 million for the years ended September 30, 2009,
2008 and 2007, respectively.
Exploration
and Production
In 2009, the Exploration and Production segments capital
expenditures were primarily well drilling and completion
expenditures and included approximately $18.3 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,
$31.4 million for the West Coast region and
$138.6 million for the Appalachian region. These amounts
included approximately $24.2 million spent to develop
proved undeveloped reserves.
In July 2009, the Companys wholly-owned subsidiary in the
Exploration and Production segment, Seneca, purchased Ivanhoe
Energys United States oil and gas operations for
approximately $39.2 million in cash (including cash
acquired of $4.3 million). The cash acquired at acquisition
includes $2.0 million held in escrow at September 30,
2009. Seneca placed this amount in escrow as part of the
purchase price, and in accordance with the purchase agreement,
this amount will remain in escrow for one year from the closing
of the transaction provided there are no pending disputes or
actions regarding obligations and liabilities required to be
satisfied or discharged by Ivanhoe Energy. This purchase
complements the segments existing oil producing assets in
the Midway Sunset Field in California. This acquisition was
funded with cash on hand.
In 2008, 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.
In 2007, the Exploration and Production segments capital
expenditures were primarily well drilling and completion
expenditures and included approximately $66.2 million for
the Gulf Coast region, substantially all of which was for the
off-shore program in the Gulf of Mexico, $41.4 million for
the West Coast region and $39.1 million for the Appalachian
region. These amounts included approximately $30.3 million
spent to develop proved undeveloped reserves.
46
All
Other and Corporate
In 2009, the majority of the All Other and Corporate
categorys expenditures for long-lived assets were for the
construction of Midstream Corporations Covington Gathering
System, as discussed below. Expenditures for long-lived assets
for 2009 also included a $1.3 million capital contribution
made by NFG Midstream Processing, LLC in the Whitetail
Processing plant, as discussed below.
In 2008, the majority of the All Other and Corporate
categorys expenditures for long-lived assets 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. Additionally, Horizon Power sold a gas-powered
turbine in March 2008 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.
In 2007, the All Other and Corporate category expenditures for
long-lived assets included a $3.3 million capital
contribution to Seneca Energy by Horizon Power. Seneca Energy
generates and sells electricity using methane gas obtained from
landfills owned by outside parties. Horizon Power funded its
capital contributions with short-term borrowings. Additionally,
the All Other and Corporate category expenditures for long-lived
assets also were for the construction of two new kilns that were
placed into service during the quarter ended June 30, 2007,
as well as construction of a lumber sorter for Highlands
sawmill operations.
Estimated
Capital Expenditures
The Companys estimated capital expenditures for the next
three years are:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended September 30
|
|
|
|
2010
|
|
|
2011
|
|
|
2012
|
|
|
|
|
|
|
(Millions)
|
|
|
|
|
|
Utility
|
|
$
|
60.0
|
|
|
$
|
58.0
|
|
|
$
|
58.0
|
|
Pipeline and Storage
|
|
|
51.0
|
|
|
|
227.0
|
|
|
|
240.0
|
|
Exploration and Production(1)
|
|
|
255.0
|
|
|
|
417.0
|
|
|
|
497.0
|
|
All Other
|
|
|
47.0
|
|
|
|
21.0
|
|
|
|
21.0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
413.0
|
|
|
$
|
723.0
|
|
|
$
|
816.0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Includes estimated expenditures for the years ended
September 30, 2010, 2011 and 2012 of approximately
$42 million, $56 million and $28 million,
respectively, to develop proved undeveloped reserves. |
Utility
Estimated capital expenditures for the Utility segment in 2010
will be concentrated in the areas of main and service line
improvements and replacements and, to a lesser extent, the
purchase of new equipment.
Pipeline
and Storage
Estimated capital expenditures for the Pipeline and Storage
segment in 2010 will be concentrated on the replacement of
transmission and storage lines, the reconditioning of storage
wells and improvements of compressor stations.
In light of the 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 and Empire are
actively pursuing several expansion projects. Supply Corporation
is moving forward with two strategic compressor horsepower
expansions, both supported by signed precedent agreements with
Appalachian producers, designed to move anticipated Marcellus
production gas to markets beyond Supply Corporations
pipeline system.
The first strategic horsepower expansion project involves new
compression along Supply Corporations Line N, increasing
that lines capacity into Texas Easterns Holbrook
Station in southwestern Pennsylvania
47
(Line N Expansion Project). This project is designed
and contracted for 150,000 Dth/day of firm transportation, and
will allow anticipated Marcellus production located in the
vicinity of Line N to flow south and access markets off Texas
Easterns system, with a projected in-service date of
November 2011. Supply Corporation is in the process of preparing
an NGA Section 7(c) application to the FERC for approval of
the Line N Expansion Project. The preliminary cost estimate for
the Line N Expansion Project is $23 million. The forecasted
expenditures for this project over the next three years are as
follows: $0.9 million in 2010, $18.5 million in 2011,
and $3.6 million in 2012. These expenditures are included
as Pipeline and Storage estimated capital expenditures in the
table above. As of September 30, 2009, less than
$0.1 million has been spent to study the Line N Expansion
Project, which has been included in preliminary survey and
investigation charges and has been fully reserved for at
September 30, 2009.
The second strategic horsepower expansion project involves the
addition of compression at Supply Corporations existing
interconnect with Tennessee Gas Pipeline at Lamont,
Pennsylvania, with a projected in-service date of May 2010
(Lamont Project). The Lamont Project is designed and
contracted for 40,000 Dth/day of firm transportation and will
afford shippers a transportation path from their anticipated
Marcellus production located in Elk and Cameron Counties,
Pennsylvania to markets attached to Tennessee Gas
Pipelines 300 Line. The Lamont Project will not require an
NGA Section 7(c) application, and will instead be
constructed under Supply Corporations existing blanket
construction certificate authority from the FERC. The
preliminary cost estimate for the Lamont Project is
$6 million, all of which is forecasted to occur in 2010.
These expenditures are included as Pipeline and Storage
estimated capital expenditures in the table above. As of
September 30, 2009, less than $0.1 million has been
spent to study the Lamont Project, which has been included in
preliminary survey and investigation charges and has been fully
reserved for at September 30, 2009.
In addition, Supply Corporation continues to actively pursue its
largest planned expansion, the
West-to-East/Appalachian
Lateral pipeline project. The Appalachian Lateral project is
routed through areas in Pennsylvania where producers are
actively drilling and are seeking market access for their newly
discovered reserves. The Appalachian Lateral will complement
Supply Corporations original West to East
(W2E) project, which was designed to transport
Rockies gas supply from Clarington, Ohio to the
Ellisburg/Leidy/Corning area. The Appalachian Lateral will
transport gas supply from Pennsylvanias producing area to
the Overbeck area of Supply Corporations existing system,
from which some of the facilities associated with the W2E
project will move the gas to eastern market points, including
Leidy, Pennsylvania, and to interconnections with Millennium and
Empire at Corning, New York. Preliminary engineering routing
analysis, project cost estimate and rate design have been
completed, and prospective shippers have been offered precedent
agreements for their consideration. This project will require an
NGA Section 7(c) application, which Supply Corporation has
not filed. The capital cost of all phases of the Appalachian
Lateral/W2E transportation projects is estimated to be in the
range of $750 million to $1 billion. As of
September 30, 2009, approximately $0.6 million has
been spent to study the Appalachian Lateral/W2E transportation
projects, which has been included in preliminary survey and
investigation charges and has been fully reserved for at
September 30, 2009.
Supply Corporation anticipates the development of the
W2E/Appalachian Lateral project will occur in phases, and based
on requests from the Marcellus producing community for
transportation service commencing as early as 2011, Supply
Corporation began a binding Open Season on August 26, 2009.
This Open Season offered transportation capacity on two initial
phases (Phase I and Phase II) of the W2E
pipeline project. The capital cost of these two phases is
estimated to be $257 million. Phase I is designed to
transport approximately 200,000 Dth/day from the Marcellus
producing area through a new
32-mile
pipeline to be constructed through Elk, Cameron, and Clinton
Counties to the Leidy Hub, with an anticipated in-service date
of late 2011. Phase II, with a late 2012 projected in-service
date, consists of an additional 50 miles of new pipeline
and compression extending through Clearfield and Jefferson
Counties to Supply Corporations Line K system and would
provide additional transportation capacity of at least 300,000
Dth/day. The forecasted expenditures for Phase I and
Phase II of this project over the next three years are as
follows: $6.0 million in 2010, $108.0 million in 2011,
and $143.0 million in 2012. These expenditures are included
as Pipeline and Storage estimated capital expenditures in the
table above.
This binding Open Season concluded on October 8, 2009 with
significant participation by Marcellus producers. Supply
Corporation received binding requests for 175,000 Dth/day of
firm transportation capacity
48
and expects to execute the signed precedent agreements submitted
by those Marcellus producers. Supply Corporation is pursuing
post-Open Season capacity requests for the remaining Phase I and
Phase II capacity and expects to continue marketing efforts
for all sections of the W2E and Appalachian Lateral projects.
The timeline associated with the W2E and Appalachian Lateral
projects will depend on market development.
In conjunction with the Appalachian Lateral and W2E
transportation projects, Supply Corporation plans to develop new
storage capacity by expanding certain of its existing storage
facilities. The expansion of these fields could provide
incremental storage capacity of approximately 8.5 MMDth and
incremental withdrawal deliverability of up to 121 MDth of
natural gas per day, with service commencing in early 2013.
Supply Corporation expects that the availability of this
incremental storage capacity will complement the Appalachian
Lateral/W2E pipeline transportation projects and help balance
the increasing flow of Appalachian and Rockies gas supply
through the western Pennsylvania area, and the growing demand
for gas on the east coast. This storage expansion project will
require an NGA Section 7(c) application, which Supply
Corporation has not yet filed. Preliminary cost estimates for
the storage expansion project is $78 million. The
forecasted expenditures for this project over the next three
years are as follows: $0.4 million in 2010,
$0.2 million in 2011, and $67.1 million in 2012. These
expenditures are included as Pipeline and Storage estimated
capital expenditures in the table above. As of
September 30, 2009, approximately $1.0 million has
been spent to study the storage expansion project, which has
been included in preliminary survey and investigation charges
and has been fully reserved for at September 30, 2009. The
timeline associated with the W2E and Appalachian Lateral
projects and any related storage development will depend on
market development.
On October 1, 2009, Empire posted an Open Season for an
expansion project that will provide at least 200,000 Dth/day of
incremental firm transportation capacity from anticipated
Marcellus production at new and existing interconnection(s)
along its recently completed Empire Connector line and along a
proposed
16-mile
24 pipeline extension into Tioga County, Pennsylvania.
Empires preliminary cost estimate for the Tioga County
Extension Project is approximately $43 million. This
project would enable Marcellus producers to deliver their gas at
existing Empire interconnections with Millennium Pipeline at
Corning, New York, with TransCanada Pipeline at Chippawa, and
with utility and power generation markets along its path, as
well as to a planned new interconnection with Tennessee Gas
Pipelines 200 Line (Zone 5) in Ontario County, New
York. Empire completed a non-binding Open Season on
October 23, 2009 for capacity in the Tioga County Extension
Project, and is in the process of negotiating binding precedent
agreements with shippers who participated in the Open Season,
representing more than adequate capacity to support the project
facilities. Following successful negotiations, Empire will file
an NGA Section 7(c) application with the FERC for approval
of this project, and anticipates that these facilities will be
placed in-service on or after September 1, 2011. The
forecasted expenditures for this project over the next two years
are as follows: $2.0 million in 2010 and $41.0 million
in 2011. These expenditures are included as Pipeline and Storage
estimated capital expenditures in the table above. As of
September 30, 2009, no preliminary survey and investigation
charges had been expended on this project, but those activities
began in October of 2009 and will be fully reserved in the
periods they occur. The timeline associated with the Tioga
County Extension Project will depend on the completion of
shipper precedent agreements.
The Company anticipates financing the Line N Expansion Project,
the Lamont Project, Phase I and Phase II of the
W2E/Appalachian Lateral project, the storage expansion project,
and the Tioga County Extension Project, all of which are
discussed above, with a combination of cash from operations,
short-term debt, and long-term debt.
Exploration
and Production
Estimated capital expenditures in 2010 for the Exploration and
Production segment include approximately $14.0 million for
the Gulf Coast region, substantially all of which is for the
off-shore program in the Gulf of Mexico, $17.0 million for
the West Coast region and $224.0 million for the
Appalachian region. The Company anticipates drilling 55 to 75
gross wells in the Marcellus Shale during 2010.
Estimated capital expenditures in 2011 for the Exploration and
Production segment include approximately $5.0 million for
the Gulf Coast region, substantially all of which is for the
off-shore program in the Gulf of
49
Mexico, $27.0 million for the West Coast region and
$385.0 million for the Appalachian region. The Company
anticipates drilling 100 to 130 gross wells in the Marcellus
Shale during 2011.
Estimated capital expenditures in 2012 for the Exploration and
Production segment include approximately $12.0 million for
the Gulf Coast region, substantially all of which is for the
off-shore program in the Gulf of Mexico, $41.0 million for
the West Coast region and $444.0 million for the
Appalachian region. The Company anticipates drilling 120 to 150
gross wells in the Marcellus Shale during 2012.
All
Other and Corporate
Estimated capital expenditures in 2010 for the All Other and
Corporate category will primarily be for the construction of
anticipated gathering systems, including the construction of
Midstream Corporations Covington Gathering System, as
discussed below.
NFG Midstream Covington, LLC, a wholly owned subsidiary of
Midstream Corporation, is constructing a gathering system in
Tioga County, Pennsylvania. The project, called the Covington
Gathering System, is to be constructed in two phases. The first
phase was completed and placed in service in November 2009. The
second phase is anticipated to be placed in service in 2010.
When completed, the system will consist of approximately
15 miles of gathering system at a cost of $15 million
to $18 million. As of September 30, 2009, the Company
has spent approximately $8.1 million in costs related to
this project.
NFG Midstream Processing, LLC, another wholly owned subsidiary
of Midstream Corporation, has a 35% ownership in the Whitetail
Processing Plant. The plant is currently under construction with
completion expected in the fall of 2009. The total project cost
is estimated at $4 million. Once completed, the plant will
extract natural gas liquids from local production. As of
September 30, 2009, the Company invested $1.3 million
related to the construction of the plant.
The Company anticipates funding the Midstream Corporation
projects with cash from operations
and/or
short-term borrowings.
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, 2009.
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, 2009, the
Companys debt to capitalization ratio (as calculated under
the facility) was .44. The constraints specified in the
50
committed credit facility would permit an additional
$1.7 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.
At September 30, 2009, the Companys long-term debt
ratings were: BBB (S&P), Baa1 (Moodys Investor
Service), and A- (Fitch Ratings Service). At September 30,
2009, the Companys commercial paper ratings were:
A-2
(S&P),
P-2
(Moodys Investor Service), and F2 (Fitch Ratings Service).
Under the Companys existing indenture covenants, at
September 30, 2009, the Company would have been permitted
to issue up to a maximum of $435.0 million 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.
However, if the Company were to experience another impairment of
oil and gas properties in the future, it is possible that these
indenture covenants would restrict the Companys ability to
issue additional long-term unsecured indebtedness. This would
not preclude the Company from issuing new indebtedness to
replace maturing debt.
The Companys 1974 indenture, pursuant to which
$99.0 million (or 7.9%) of the Companys long-term
debt (as of September 30, 2009) 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, 2009, the Company had no debt outstanding
under the committed credit facility.
The Companys embedded cost of long-term debt was 6.95% at
September 30, 2009 and 6.5% at September 30, 2008.
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. In February
2009, the Company exchanged the notes for economically identical
notes registered 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 at a price equal to 101% of the principal
amount in the event of both a change in control and a ratings
downgrade to a rating below investment grade. The Company used
$200.0 million of the proceeds of the issuance to refund
$200.0 million of 6.303% medium-term notes that matured on
May 27, 2008.
In April 2009, the Company issued $250.0 million of
8.75% notes due in March 2019. After deducting underwriting
discounts and commissions, the net proceeds to the Company
amounted to $247.8 million. These notes were registered
under the Securities Act of 1933. The holders of the notes may
require the Company to repurchase their notes at a price equal
to 101% of the principal amount in the event of both a change in
control and a ratings downgrade to a rating below investment
grade. The proceeds of this debt issuance were used for general
corporate purposes, including to replenish cash that was used to
pay the $100 million due at the maturity of the
Companys 6.0% medium-term notes on March 1, 2009.
After this debt issuance, the Companys
51
embedded cost of long-term debt increased from 6.5% to 6.95%. If
the Company were to issue long-term debt today, its borrowing
costs might be expected to be in the range of 6.0% to 7.0%
depending on their maturity date.
On December 8, 2005, the Companys Board of Directors
authorized the Company to implement a share repurchase program,
whereby the Company could 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 of the
Companys common stock. Under this new authorization, the
Company repurchased 1,028,981 shares for $46.0 million
through September 17, 2008. The Company, however, stopped
repurchasing shares after September 17, 2008 in light of
the unsettled nature of the credit markets. Such repurchases may
resume in the future. The 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.
OFF-BALANCE
SHEET ARRANGEMENTS
The Company has entered into certain off-balance sheet financing
arrangements. These financing arrangements are primarily
operating 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 $27.8 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.
CONTRACTUAL
OBLIGATIONS
The following table summarizes the Companys expected
future contractual cash obligations as of September 30,
2009, and the twelve-month periods over which they occur:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payments by Expected Maturity Dates
|
|
|
2010
|
|
2011
|
|
2012
|
|
2013
|
|
2014
|
|
Thereafter
|
|
Total
|
|
|
|
|
|
|
|
|
(Millions)
|
|
|
|
|
|
Long-Term Debt, including interest expense(1)
|
|
$
|
86.9
|
|
|
$
|
274.0
|
|
|
$
|
213.2
|
|
|
$
|
304.2
|
|
|
$
|
48.7
|
|
|
$
|
888.5
|
|
|
$
|
1,815.5
|
|
Operating Lease Obligations
|
|
$
|
5.4
|
|
|
$
|
3.9
|
|
|
$
|
3.3
|
|
|
$
|
2.4
|
|
|
$
|
2.3
|
|
|
$
|
10.5
|
|
|
$
|
27.8
|
|
Purchase Obligations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas Purchase Contracts(2)
|
|
$
|
478.0
|
|
|
$
|
63.0
|
|
|
$
|
29.2
|
|
|
$
|
6.7
|
|
|
$
|
6.7
|
|
|
$
|
49.3
|
|
|
$
|
632.9
|
|
Transportation and Storage Contracts
|
|
$
|
42.2
|
|
|
$
|
38.8
|
|
|
$
|
37.4
|
|
|
$
|
33.5
|
|
|
$
|
33.1
|
|
|
$
|
27.0
|
|
|
$
|
212.0
|
|
Other
|
|
$
|
25.1
|
|
|
$
|
9.0
|
|
|
$
|
4.1
|
|
|
$
|
3.4
|
|
|
$
|
3.3
|
|
|
$
|
12.0
|
|
|
$
|
56.9
|
|
|
|
|
(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 other long-term obligations recorded on its
Consolidated Balance Sheets that are not reflected in the table
above. Such long-term obligations include pension and other
post-retirement liabilities, asset retirement obligations,
deferred income tax liabilities, various regulatory liabilities,
derivative financial instrument liabilities and other deferred
credits (the majority of which consist of liabilities for a
non-qualified benefit plan, deferred compensation liabilities,
environmental liabilities, workers compensation liabilities and
liabilities for income tax uncertainties).
52
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 Sheets in
accordance with the authoritative guidance (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 Sheets as a current liability; and
(iii) other obligations which are reflected on the
Consolidated Balance Sheets. 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 I
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 2009, the Company contributed
$16.0 million to the Retirement Plan. The Company
anticipates that the annual contribution to the Retirement Plan
in 2010 will be in the range of $20.0 million to
$30.0 million. It is likely that the Company will have to
fund larger amounts to the Retirement Plan subsequent to 2010 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 2009, the Company contributed
$25.5 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 2010 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.
As of September 30, 2009, the Company recorded a deferred
tax asset relating to a federal net operating loss carryover of
$25.1 million. This carryover, which is available as a
result of an acquisition, expires in varying amounts between
2023 and 2029. Although this loss carryover is subject to
certain annual limitations, no valuation allowance was recorded
because of managements determination that the amount will
be fully utilized during the carryforward period.
MARKET
RISK SENSITIVE INSTRUMENTS
Energy
Commodity Price Risk
The Company, in its Exploration and Production segment, Energy
Marketing segment and Pipeline and Storage segment, uses various
derivative financial instruments (derivatives), including price
swap agreements 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
53
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, 2009
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.
Beginning in fiscal 2009, the Company adopted the authoritative
guidance for fair value measurements. In accordance with the
adoption of this guidance, the Company has identified certain
inputs used to recognize fair value as Level 3
(unobservable inputs). The Level 3 derivative assets relate
to oil swap agreements used to hedge forecasted sales at a
specific location (southern California). The Companys
internal model that is used to calculate fair value applies a
historical basis differential (between the sales locations and
NYMEX) to a forward NYMEX curve because there is not a forward
curve specific to this sales location. Given the high level of
historical correlation between NYMEX prices and prices at this
sales location, the Company does not believe that the fair value
recorded by the Company would be significantly different from
what it expects to receive upon settlement. The fair value of
the Level 3 derivative assets was reduced by
$0.7 million based upon the Companys assessment of
counterparty credit risk. The Company applied default
probabilities to the anticipated cash flows that it was
expecting from its counterparties to calculate the credit
reserve.
The Level 3 assets amount to $27.0 million at
September 30, 2009 and represent 60.2% of the Derivative
Financial Instruments Assets or 5.9% of the Total Assets as
shown in Item 8 at Note F Fair Value
Measurements at September 30, 2009.
During fiscal 2009, the Company transferred $8.1 million of
derivative assets from Level 3 assets to Level 2
assets. The majority of these assets related to natural gas
swaps on southern California natural gas production. The Company
also transferred $0.8 million of derivative liabilities
from Level 3 liabilities to Level 2 liabilities. These
liabilities related to certain natural gas swaps on Gulf of
Mexico natural gas production. These transfers occurred because
the Company was able to obtain and utilize forward-looking,
observable basis differential information for the hedges at
these locations.
The Company uses the crude oil swaps classified as Level 3
to hedge against the risk of declining commodity prices and not
as speculative investments. Gains or losses related to these
Level 3 derivative assets (including any reduction for
credit risk) are deferred until the hedged commodity transaction
occurs in accordance with the provisions of the existing
guidance for derivative instruments and hedging activities.
The increase in the net fair value of the Level 3 positions
from October 1, 2008 to September 30, 2009, as shown
in Item 8 at Note F, was attributable to a significant
decrease in the commodity price of crude oil during that period.
The Company believes that these fair values reasonably represent
the amounts that the Company would realize upon settlement based
on commodity prices that were present at September 30, 2009.
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, 2009. At September 30, 2009, the
Company had not entered into any natural gas or crude oil price
swap agreements extending beyond 2012.
Natural
Gas Price Swap Agreements
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expected Maturity Dates
|
|
|
|
|
|
|
2010
|
|
|
2011
|
|
|
2012
|
|
|
Total
|
|
|
Notional Quantities (Equivalent Bcf)
|
|
|
16.3
|
|
|
|
12.9
|
|
|
|
8.8
|
|
|
|
38.0
|
|
Weighted Average Fixed Rate (per Mcf)
|
|
$
|
6.91
|
|
|
$
|
7.22
|
|
|
$
|
7.48
|
|
|
$
|
7.15
|
|
Weighted Average Variable Rate (per Mcf)
|
|
$
|
6.15
|
|
|
$
|
7.34
|
|
|
$
|
7.56
|
|
|
$
|
6.88
|
|
54
Of the total Bcf above, 0.6 Bcf is accounted for as fair
value hedges at a weighted average fixed rate of $8.08 per Mcf.
The remaining 37.4 Bcf are accounted for as cash flow
hedges at a weighted average fixed rate of $7.13 per Mcf.
Crude
Oil Price Swap Agreements
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expected Maturity Dates
|
|
|
|
|
2010
|
|
2011
|
|
2012
|
|
Total
|
|
Notional Quantities (Equivalent bbls)
|
|
|
1,692,000
|
|
|
|
648,000
|
|
|
|
348,000
|
|
|
|
2,688,000
|
|
Weighted Average Fixed Rate (per bbl)
|
|
$
|
74.59
|
|
|
$
|
66.54
|
|
|
$
|
62.95
|
|
|
$
|
71.14
|
|
Weighted Average Variable Rate (per bbl)
|
|
$
|
59.38
|
|
|
$
|
62.63
|
|
|
$
|
64.30
|
|
|
$
|
60.80
|
|
At September 30, 2009, the Company would have received from
its respective counterparties an aggregate of approximately
$10.4 million to terminate the natural gas price swap
agreements outstanding at that date. The Company would have
received from its respective counterparties an aggregate of
approximately $27.0 million to terminate the crude oil
price swap agreements outstanding at September 30, 2009.
At September 30, 2008, the Company had natural gas price
swap agreements covering 15.1 Bcf at a weighted average
fixed rate of $9.69 per Mcf. The Company also had crude oil
price swap agreements covering 1,920,000 bbls at a weighted
average fixed rate of $90.50 per bbl.
The following table discloses the net contract volume 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, 2009, the Company held no futures contracts
with maturity dates extending beyond 2012.
Futures
Contracts
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expected Maturity Dates
|
|
|
|
2010
|
|
|
2011
|
|
|
2012
|
|
|
Total
|
|
|
Net Contract Volume Purchased (Sold) (Equivalent Bcf)
|
|
|
3.9
|
|
|
|
1.0
|
|
|
|
|
(1)
|
|
|
4.9
|
|
Weighted Average Contract Price (per Mcf)
|
|
$
|
6.72
|
|
|
$
|
7.02
|
|
|
$
|
8.15
|
|
|
$
|
6.74
|
|
Weighted Average Settlement Price (per Mcf)
|
|
$
|
6.42
|
|
|
$
|
6.84
|
|
|
$
|
8.77
|
|
|
$
|
6.45
|
|
|
|
|
(1) |
|
The Energy Marketing segment has purchased 11 futures contracts
(1 contract = 2,500 Dth) for 2012. |
At September 30, 2009, the Company had long (purchased)
futures contracts covering 11.6 Bcf of gas extending
through 2012 at a weighted average contract price of $6.37 per
Mcf and a weighted average settlement price of $6.07 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 to 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 $3.5 million to terminate these
futures contracts at September 30, 2009.
At September 30, 2009, the Company had short (sold) futures
contracts covering 6.7 Bcf of gas extending through 2011 at
a weighted average contract price of $7.37 per Mcf and a
weighted average settlement price of $6.07 per Mcf. Of this
amount, 5.8 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 0.9 Bcf is
accounted for as fair value hedges used to hedge against falling
prices, a risk to which the Energy Marketing segment is exposed
to due to the fixed price gas purchase commitments that it
enters into with its natural gas suppliers. The Company would
have received $8.7 million to terminate these futures
contracts at September 30, 2009.
At September 30, 2008, the Company had futures contracts
covering 2.4 Bcf (net long position) at a weighted average
contract price of $9.99 per Mcf.
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
55
performs a credit check, and then on a quarterly basis monitors
counterparty credit exposure. The majority of the Companys
counterparties are financial institutions and energy traders.
The Company has
over-the-counter
swap positions with ten counterparties. At September 30,
2009, the Company had derivative financial instruments that were
in gain positions with eight of the counterparties. The Company
had derivative financial instruments that were in loss positions
with the other two counterparties. The Company had
$26.6 million of credit exposure with one counterparty
(which is rated A1 (Moodys Investor Service), A
(S&P), and A+ (Fitch Ratings Service) as of
September 30, 2009). On average for those financial
instruments that were in a gain position, the Company had
$1.8 million of credit exposure per counterparty with the
other seven counterparties that were in a gain position. The
Company had not received any collateral from the counterparties
at September 30, 2009 since the Companys gain
position on such derivative financial instruments had not
exceeded the established thresholds at which the counterparties
would be required to post collateral.
As of September 30, 2009, eight of the ten counterparties
to the Companys outstanding derivative instrument
contracts (specifically the
over-the-counter
swaps) had a common credit-risk-related contingency feature. In
the event the Companys credit rating increases or falls
below a certain threshold (the lower of the S&P or
Moodys Debt Rating), the available credit extended to the
Company would either increase or decrease. A decline in the
Companys credit rating, in and of itself, would not cause
the Company to be required to increase the level of its hedging
collateral deposits (in the form of cash deposits, letters of
credit or treasury debt instruments). If the Companys
outstanding derivative instrument contracts were in a liability
position and the Companys credit rating declined, then
additional hedging collateral deposits would be required.
At September 30, 2009, these credit-risk related
contingency features were not triggered since the Company had
assets of $37.9 million related to derivative financial
instruments with the eight counterparties.
For its exchange traded futures contracts, which are in an asset
position, the Company had paid $0.8 million in hedging
collateral as of September 30, 2009. As these are exchange
traded futures contracts, there are no specific credit-risk
related contingency features. The Company posts hedging
collateral based on open positions (i.e. those positions that
have been settled for cash) and margin requirements. (This is
discussed in Note A under Hedging Collateral Deposits.)
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, 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Principal Amounts by Expected Maturity Dates
|
|
|
|
2010
|
|
|
2011
|
|
|
2012
|
|
|
2013
|
|
|
2014
|
|
|
Thereafter
|
|
|
Total
|
|
|
|
(Dollars in millions)
|
|
|
Long-Term Fixed Rate Debt
|
|
$
|
|
|
|
$
|
200.0
|
|
|
$
|
150.0
|
|
|
$
|
250.0
|
|
|
$
|
|
|
|
$
|
649.0
|
|
|
$
|
1,249.0
|
|
Weighted Average Interest Rate Paid
|
|
|
|
|
|
|
7.5
|
%
|
|
|
6.7
|
%
|
|
|
5.3
|
%
|
|
|
|
|
|
|
7.5
|
%
|
|
|
7.0
|
%
|
Fair Value of Long-Term Fixed Rate Debt = $1,347.4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
Customer delivery rates charged by Distribution
Corporations New York division were established in a rate
order issued on December 21, 2007 by the NYPSC. The rate
order approved a revenue increase of $1.8 million
56
annually, together with a surcharge that would collect up to
$10.8 million to recover expenses for implementation of an
efficiency and conservation incentive program. The rate order
further provided for a return on equity of 9.1%. In connection
with the efficiency and conservation program, 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 is 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 and the methodology used for
calculating rate of return, which the appeal contends
understated the Companys cost of equity. Briefs were filed
and oral argument was held on October 14, 2009. The Company
cannot predict the outcome of the appeal at this time.
On April 7, 2009, the Governor of the State of New York
signed into law an amendment to the Public Service Law
increasing the allowed utility assessment from the current rate
of one-third
of one percent to one percent of a utilitys in-state gross
operating revenue, together with a temporary surcharge equal, as
applied, to an additional one percent of the utilitys
gross operating revenue. As a result of this amendment,
Distribution Corporations New York Division paid a total
assessment of $26.2 million during fiscal 2009, of which
$22.9 million was labeled as the temporary surcharge. The
NYPSC, in a generic proceeding initiated for the purpose of
implementing the amended law, has authorized the recovery,
through rates, of the full cost of the increased assessment. The
assessment is currently being applied to customer bills.
Pennsylvania
Jurisdiction
Distribution Corporation currently does not have a rate case on
file with the PaPUC. Distribution Corporations current
tariff in its Pennsylvania jurisdiction was last approved by the
PaPUC on November 30, 2006 as part of a settlement
agreement that 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.
Empires new facilities (the Empire Connector project) were
placed into service on December 10, 2008. As of that date,
Empire became an interstate pipeline subject to FERC regulation,
performing services under a FERC-approved tariff and at
FERC-approved rates. The December 21, 2006 FERC order
issuing Empire its Certificate of Public Convenience and
Necessity requires Empire to file a cost and revenue study at
the FERC, within three years after the in-service date, in
conjunction with which Empire will either justify Empires
existing recourse rates or propose alternative rates.
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, 2009, 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
$18.7 million to $22.9 million. The
57
minimum estimated liability of $18.7 million has been
recorded on the Consolidated Balance Sheet at September 30,
2009. 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. Other than discussed in
Note I (referred to below), the Company is currently not
aware of any material additional exposure to environmental
liabilities. However, changes in environmental regulations, new
information or other factors could adversely impact the Company.
For further discussion refer to Item 8 at
Note I Commitments and Contingencies under the
heading Environmental Matters.
Legislative and regulatory measures to address climate change
and greenhouse gas emissions are in various phases of
discussions. If enacted or adopted, legislation or regulation
that restricts carbon emissions could increase the
Companys cost of environmental compliance by requiring the
Company to install new equipment to reduce emissions from larger
facilities and/or purchase emission allowances. Proposed
measures could also delay or otherwise negatively affect efforts
to obtain permits and other regulatory approvals with regard to
existing and new facilities. But legislation or regulation that
sets a price on or otherwise restricts carbon emissions could
also benefit the Company by increasing demand for natural gas,
because substantially fewer carbon emissions per Btu of heat
generated are associated with the use of natural gas than with
certain alternate fuels such as coal and oil. The effect
(material or not) on the Company of any new legislative or
regulatory measures will depend on the particular provisions
that are ultimately adopted.
NEW
AUTHORITATIVE ACCOUNTING AND FINANCIAL REPORTING
GUIDANCE
In September 2006, the FASB issued authoritative guidance for
using fair value to measure assets and liabilities. This
guidance 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. This guidance is to be applied whenever assets
or liabilities are to be measured at fair value. On
October 1, 2008, the Company adopted this guidance for
financial assets and financial liabilities that are recognized
or disclosed at fair value on a recurring basis. This guidance
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. For further
discussion of the impact of the adoption of the authoritative
guidance for financial assets and financial liabilities, refer
to Item 8 at Note F Fair Value
Measurements. The Company is currently evaluating the impact
that the adoption of the authoritative guidance for nonfinancial
assets and nonfinancial liabilities will have on its
consolidated financial statements. The Company has identified
Goodwill as being the major nonfinancial asset that may be
impacted by the adoption of this guidance. The Company does not
believe there are any nonfinancial liabilities that will be
impacted by the adoption of this guidance.
In September 2006, the FASB issued authoritative guidance which
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. This
guidance 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.
This guidance 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 this authoritative guidance, the
Company has recognized the funded status of its benefit plans
and implemented the related disclosure requirements at
September 30, 2007. The requirement to measure the plan
assets and benefit obligations as of the Companys fiscal
year-end date was fully adopted by the Company as of
September 30, 2009. The Company has historically measured
its plan assets and benefit obligations using a
June 30th measurement date. As a result of the change
to a September 30th measurement date, the Company
recorded fifteen months of pension and other post-retirement
benefit costs during fiscal 2009. Such costs were calculated
using June 30, 2008 measurement date data. Three of those
months pertain to the period of July 1, 2008 to
September 30, 2008. The pension and other post-retirement
benefit costs for that period amounted to
58
$5.1 million and were recorded by the Company during the
quarter ended December 31, 2008 as a $3.8 million
increase to Other Regulatory Assets in the Companys
Utility and Pipeline and Storage segments and a
$1.3 million ($0.8 million after tax) adjustment to
earnings reinvested in the business. Refer to Item 8 at
Note H Retirement Plan and Other
Post-Retirement Benefits for further disclosures regarding the
impact of this authoritative guidance on the Companys
consolidated financial statements.
In December 2007, the FASB revised authoritative guidance that
significantly changes 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 this guidance, 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. This guidance is effective as of the Companys
first quarter of fiscal 2010.
In December 2007, the FASB issued authoritative guidance that
changes 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. This authoritative guidance 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 authoritative guidance that
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
authoritative guidance for derivative instruments and hedging
activities, and how derivative instruments and related hedged
items affect an entitys financial position, financial
performance, and cash flows. The Company adopted the disclosure
provisions of this authoritative guidance during the
Companys second quarter of fiscal 2009. Refer to
Item 8 at Note G Financial Instruments for
these disclosures.
In June 2008, the FASB issued authoritative guidance concerning
whether certain instruments granted in share-based payment
transactions are participating securities. This guidance
specified that unvested share-based payment awards that contain
nonforfeitable rights to dividends are participating securities
and shall be included in the computation of earnings per share
pursuant to the two-class method. The
two-class method allocates undistributed earnings
between common shares and participating securities. This
authoritative guidance is effective as of the Companys
first quarter of fiscal 2010. The Company does not believe this
guidance will have a material impact on its earnings per share
calculation.
On December 31, 2008, the SEC issued a final rule on
Modernization of Oil and Gas Reporting. The final rule modifies
the SECs reporting and disclosure rules for oil and gas
reserves and aligns the full cost accounting rules with the
revised disclosures. The most notable changes of the final rule
include the replacement of the single day period-end pricing to
value oil and gas reserves to a
12-month
average of the first day of the month price for each month
within the reporting period. The final rule also permits
voluntary disclosure of probable and possible reserves, a
disclosure previously prohibited by SEC rules. The revised
reporting and disclosure requirements are effective for the
Companys
Form 10-K
for the period ended September 30, 2010. Early adoption is
not permitted. The Company is currently evaluating the impact
that adoption of these rules will have on its consolidated
financial statements and MD&A disclosures.
In March 2009, the FASB issued authoritative guidance that
expands the disclosures required in an employers financial
statements about pension and other post-retirement benefit plan
assets. The additional disclosures include more details on how
investment allocation decisions are made, the plans
investment policies and strategies, the major categories of plan
assets, the inputs and valuation techniques used to measure the
fair value of plan assets, the effect of fair value measurements
using significant unobservable inputs on changes in plan assets
for the period, and disclosure regarding significant
concentrations of risk within plan assets. The additional
disclosure requirements are required for the Companys
Form 10-K
for the period ended
59
September 30, 2010. The Company is currently evaluating the
impact that adoption of this authoritative guidance will have on
its consolidated financial statement disclosures.
Effective with the June 30, 2009
Form 10-Q,
the Company adopted the FASB authoritative guidance for
subsequent events that establishes general standards of
accounting for and disclosure of events that occur after the
balance sheet date but before financial statements are issued or
are available to be issued. Refer to Item 8 at
Note R Subsequent Events for disclosures made
as a result of the adoption of this guidance.
In June 2009, the FASB issued authoritative guidance that
establishes the FASB Accounting Standards
Codificationtm
(the Codification) as the source of authoritative GAAP
recognized by the FASB to be applied by all nongovernmental
entities in the preparation of financial statements in
conformity with GAAP. Rules and interpretive releases of the SEC
under authority of federal securities law are also sources of
authoritative GAAP for SEC registrants. All other
nongrandfathered, non-SEC accounting literature not included in
the Codification will become nonauthoritative. The Codification
was effective for interim and annual periods ending after
September 15, 2009. Effective with this September 30,
2009
Form 10-K,
the Company has updated its disclosures to conform to the
Codification. There has been no impact on the Companys
consolidated financial statements as the Codification does not
change or alter existing GAAP.
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 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;
|
60
|
|
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.
|
Factors affecting the Companys ability to successfully
identify, drill for and produce economically viable natural gas
and oil reserves, including among others geology, lease
availability, weather conditions, shortages, delays or
unavailability of equipment and services required in drilling
operations, and the need to obtain governmental approvals and
permits and comply with environmental laws and regulations;
|
|
12.
|
Significant differences between the Companys projected and
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 oil having different
quality
and/or
different geographic locations, or changes in the price
differentials between natural gas having different heating
values
and/or
different geographic locations;
|
|
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 differences between the Companys projected and
actual capital expenditures and operating expenses, and
unanticipated project delays or changes in project costs or
plans;
|
61
|
|
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;
|
|
23.
|
Significant changes in tax rates or policies or in rates of
inflation or interest;
|
|
24.
|
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;
|
|
25.
|
Changes in accounting principles or the application of such
principles to the Company;
|
|
26.
|
The cost and effects of legal and administrative claims against
the Company or activist shareholder campaigns to effect changes
at the Company;
|
|
27.
|
Increasing health care costs and the resulting effect on health
insurance premiums and on the obligation to provide other
post-retirement benefits; or
|
|
28.
|
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.
62
|
|
Item 8
|
Financial
Statements and Supplementary Data
|
Index
to Financial Statements
|
|
|
|
|
|
|
Page
|
|
Financial Statements:
|
|
|
|
|
|
|
|
|
|
|
|
|
64
|
|
|
|
|
65
|
|
|
|
|
66
|
|
|
|
|
67
|
|
|
|
|
68
|
|
|
|
|
69
|
|
Financial Statement Schedules:
|
|
|
|
|
For the three years ended September 30, 2009
|
|
|
|
|
|
|
|
124
|
|
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 O
Quarterly Financial Data (unaudited) and Note Q
Supplementary Information for Oil and Gas Producing Activities
(unaudited), appears under this Item, and reference is made
thereto.
63
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, 2009 and 2008, and the
results of their operations and their cash flows for each of the
three years in the period ended September 30, 2009 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, 2009,
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 25, 2009
64
NATIONAL
FUEL GAS COMPANY
REINVESTED
IN THE BUSINESS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended September 30
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
(Thousands of dollars, except per common
|
|
|
|
|
|
|
share amounts)
|
|
|
|
|
|
INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Revenues
|
|
$
|
2,057,852
|
|
|
$
|
2,400,361
|
|
|
$
|
2,039,566
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchased Gas
|
|
|
1,001,782
|
|
|
|
1,235,157
|
|
|
|
1,018,081
|
|
Operation and Maintenance
|
|
|
402,856
|
|
|
|
432,871
|
|
|
|
396,408
|
|
Property, Franchise and Other Taxes
|
|
|
72,163
|
|
|
|
75,585
|
|
|
|
70,660
|
|
Depreciation, Depletion and Amortization
|
|
|
173,410
|
|
|
|
170,623
|
|
|
|
157,919
|
|
Impairment of Oil and Gas Producing Properties
|
|
|
182,811
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,833,022
|
|
|
|
1,914,236
|
|
|
|
1,643,068
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Income
|
|
|
224,830
|
|
|
|
486,125
|
|
|
|
396,498
|
|
Other Income (Expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from Unconsolidated Subsidiaries
|
|
|
3,366
|
|
|
|
6,303
|
|
|
|
4,979
|
|
Impairment of Investment in Partnership
|
|
|
(1,804
|
)
|
|
|
|
|
|
|
|
|
Other Income
|
|
|
6,576
|
|
|
|
7,376
|
|
|
|
4,936
|
|
Interest Income
|
|
|
5,776
|
|
|
|
10,815
|
|
|
|
1,550
|
|
Interest Expense on Long-Term Debt
|
|
|
(79,419
|
)
|
|
|
(70,099
|
)
|
|
|
(68,446
|
)
|
Other Interest Expense
|
|
|
(7,497
|
)
|
|
|
(3,870
|
)
|
|
|
(6,029
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from Continuing Operations Before Income Taxes
|
|
|
151,828
|
|
|
|
436,650
|
|
|
|
333,488
|
|
Income Tax Expense
|
|
|
51,120
|
|
|
|
167,922
|
|
|
|
131,813
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from Continuing Operations
|
|
|
100,708
|
|
|
|
268,728
|
|
|
|
201,675
|
|
Discontinued Operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from Operations, Net of Tax
|
|
|
|
|
|
|
|
|
|
|
15,479
|
|
Gain on Disposal, Net of Tax
|
|
|
|
|
|
|
|
|
|
|
120,301
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from Discontinued Operations, Net of Tax
|
|
|
|
|
|
|
|
|
|
|
135,780
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income Available for Common Stock
|
|
|
100,708
|
|
|
|
268,728
|
|
|
|
337,455
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EARNINGS REINVESTED IN THE BUSINESS
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at Beginning of Year
|
|
|
953,799
|
|
|
|
983,776
|
|
|
|
786,013
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,054,507
|
|
|
|
1,252,504
|
|
|
|
1,123,468
|
|
Share Repurchases
|
|
|
|
|
|
|
(194,776
|
)
|
|
|
(38,196
|
)
|
Cumulative Effect of Adoption of Authoritative Guidance for
Income Taxes
|
|
|
|
|
|
|
(406
|
)
|
|
|
|
|
Adoption of Authoritative Guidance for Defined Benefit Pension
and Other Post-Retirement Plans
|
|
|
(804
|
)
|
|
|
|
|
|
|
|
|
Dividends on Common Stock
|
|
|
(105,410
|
)
|
|
|
(103,523
|
)
|
|
|
(101,496
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at End of Year
|
|
$
|
948,293
|
|
|
$
|
953,799
|
|
|
$
|
983,776
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings Per Common Share:
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic:
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from Continuing Operations
|
|
$
|
1.26
|
|
|
$
|
3.27
|
|
|
$
|
2.43
|
|
Income from Discontinued Operations
|
|
|
|
|
|
|
|
|
|
|
1.63
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income Available for Common Stock
|
|
$
|
1.26
|
|
|
$
|
3.27
|
|
|
$
|
4.06
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted:
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from Continuing Operations
|
|
$
|
1.25
|
|
|
$
|
3.18
|
|
|
$
|
2.37
|
|
Income from Discontinued Operations
|
|
|
|
|
|
|
|
|
|
|
1.59
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income Available for Common Stock
|
|
$
|
1.25
|
|
|
$
|
3.18
|
|
|
$
|
3.96
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted Average Common Shares Outstanding:
|
|
|
|
|
|
|
|
|
|
|
|
|
Used in Basic Calculation
|
|
|
79,649,965
|
|
|
|
82,304,335
|
|
|
|
83,141,640
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Used in Diluted Calculation
|
|
|
80,628,685
|
|
|
|
84,474,839
|
|
|
|
85,301,361
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See Notes to Consolidated Financial Statements
65
NATIONAL
FUEL GAS COMPANY
|
|
|
|
|
|
|
|
|
|
|
At September 30
|
|
|
|
2009
|
|
|
2008
|
|
|
|
(Thousands of dollars)
|
|
|
ASSETS
|
Property, Plant and Equipment
|
|
$
|
5,183,527
|
|
|
$
|
4,873,969
|
|
Less Accumulated Depreciation, Depletion and
Amortization
|
|
|
2,051,482
|
|
|
|
1,719,869
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,132,045
|
|
|
|
3,154,100
|
|
|
|
|
|
|
|
|
|
|
Current Assets
|
|
|
|
|
|
|
|
|
Cash and Temporary Cash Investments
|
|
|
408,053
|
|
|
|
68,239
|
|
Cash Held in Escrow
|
|
|
2,000
|
|
|
|
|
|
Hedging Collateral Deposits
|
|
|
848
|
|
|
|
1
|
|
Receivables Net of Allowance for Uncollectible
Accounts of $38,334 and $33,117, Respectively
|
|
|
144,466
|
|
|
|
185,397
|
|
Unbilled Utility Revenue
|
|
|
18,884
|
|
|
|
24,364
|
|
Gas Stored Underground
|
|
|
55,862
|
|
|
|
87,294
|
|
Materials and Supplies at average cost
|
|
|
24,520
|
|
|
|
31,317
|
|
Unrecovered Purchased Gas Costs
|
|
|
|
|
|
|
37,708
|
|
Other Current Assets
|
|
|
68,474
|
|
|
|
65,158
|
|
Deferred Income Taxes
|
|
|
53,863
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
776,970
|
|
|
|
499,478
|
|
|
|
|
|
|
|
|
|
|
Other Assets
|
|
|
|
|
|
|
|
|
Recoverable Future Taxes
|
|
|
138,435
|
|
|
|
82,506
|
|
Unamortized Debt Expense
|
|
|
14,815
|
|
|
|
13,978
|
|
Other Regulatory Assets
|
|
|
530,913
|
|
|
|
189,587
|
|
Deferred Charges
|
|
|
2,737
|
|
|
|
4,417
|
|
Other Investments
|
|
|
78,503
|
|
|
|
80,640
|
|
Investments in Unconsolidated Subsidiaries
|
|
|
16,257
|
|
|
|
16,279
|
|
Goodwill
|
|
|
5,476
|
|
|
|
5,476
|
|
Intangible Assets
|
|
|
21,536
|
|
|
|
26,174
|
|
Prepaid Post-Retirement Benefit Costs
|
|
|
|
|
|
|
21,034
|
|
Fair Value of Derivative Financial Instruments
|
|
|
44,817
|
|
|
|
28,786
|
|
Other
|
|
|
6,625
|
|
|
|
7,732
|
|
|
|
|
|
|
|
|
|
|
|
|
|
860,114
|
|
|
|
476,609
|
|
|
|
|
|
|
|
|
|
|
Total Assets
|
|
$
|
4,769,129
|
|
|
$
|
4,130,187
|
|
|
|
|
|
|
|
|
|
|
|
CAPITALIZATION AND LIABILITIES
|
Capitalization:
|
|
|
|
|
|
|
|
|
Comprehensive Shareholders Equity
|
|
|
|
|
|
|
|
|
Common Stock, $1 Par Value
|
|
|
|
|
|
|
|
|
Authorized 200,000,000 Shares; Issued and
Outstanding 80,499,915 Shares and
79,120,544 Shares, Respectively
|
|
$
|
80,500
|
|
|
$
|
79,121
|
|
Paid In Capital
|
|
|
602,839
|
|
|
|
567,716
|
|
Earnings Reinvested in the Business
|
|
|
948,293
|
|
|
|
953,799
|
|
|
|
|
|
|
|
|
|
|
Total Common Shareholders Equity Before Items Of
Other Comprehensive Income (Loss)
|
|
|
1,631,632
|
|
|
|
1,600,636
|
|
Accumulated Other Comprehensive Income (Loss)
|
|
|
(42,396
|
)
|
|
|
2,963
|
|
|
|
|
|
|
|
|
|
|
Total Comprehensive Shareholders Equity
|
|
|
1,589,236
|
|
|
|
1,603,599
|
|
Long-Term Debt, Net of Current Portion
|
|
|
1,249,000
|
|
|
|
999,000
|
|
|
|
|
|
|
|
|
|
|
Total Capitalization
|
|
|
2,838,236
|
|
|
|
2,602,599
|
|
|
|
|
|
|
|
|
|
|
Current and Accrued Liabilities
|
|
|
|
|
|
|
|
|
Notes Payable to Banks and Commercial Paper
|
|
|
|
|
|
|
|
|
Current Portion of Long-Term Debt
|
|
|
|
|
|
|
100,000
|
|
Accounts Payable
|
|
|
90,723
|
|
|
|
142,520
|
|
Amounts Payable to Customers
|
|
|
105,778
|
|
|
|
2,753
|
|
Dividends Payable
|
|
|
26,967
|
|
|
|
25,714
|
|
Interest Payable on Long-Term Debt
|
|
|
32,031
|
|
|
|
22,114
|
|
Customer Advances
|
|
|
24,555
|
|
|
|
33,017
|
|
Customer Security Deposits
|
|
|
17,430
|
|
|
|
14,047
|
|
Other Accruals and Current Liabilities
|
|
|
18,875
|
|
|
|
31,173
|
|
Deferred Income Taxes
|
|
|
|
|
|
|
1,871
|
|
Fair Value of Derivative Financial Instruments
|
|
|
2,148
|
|
|
|
1,362
|
|
|
|
|
|
|
|
|
|
|
|
|
|
318,507
|
|
|
|
374,571
|
|
|
|
|
|
|
|
|
|
|
Deferred Credits
|
|
|
|
|
|
|
|
|
Deferred Income Taxes
|
|
|
663,876
|
|
|
|
634,372
|
|
Taxes Refundable to Customers
|
|
|
67,046
|
|
|
|
18,449
|
|
Unamortized Investment Tax Credit
|
|
|
3,989
|
|
|
|
4,691
|
|
Cost of Removal Regulatory Liability
|
|
|
105,546
|
|
|
|
103,100
|
|
Other Regulatory Liabilities
|
|
|
120,229
|
|
|
|
91,933
|
|
Pension and Other Post-Retirement Liabilities
|
|
|
415,888
|
|
|
|
78,909
|
|
Asset Retirement Obligations
|
|
|
91,373
|
|
|
|
93,247
|
|
Other Deferred Credits
|
|
|
144,439
|
|
|
|
128,316
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,612,386
|
|
|
|
1,153,017
|
|
|
|
|
|
|
|
|
|
|
Commitments and Contingencies
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Capitalization and Liabilities
|
|
$
|
4,769,129
|
|
|
$
|
4,130,187
|
|
|
|
|
|
|
|
|
|
|
See Notes to Consolidated Financial Statements
66
NATIONAL
FUEL GAS COMPANY
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended September 30
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
(Thousands of dollars)
|
|
|
Operating Activities
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income Available for Common Stock
|
|
$
|
100,708
|
|
|
$
|
268,728
|
|
|
$
|
337,455
|
|
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
|
|
|
182,811
|
|
|
|
|
|
|
|
|
|
Depreciation, Depletion and Amortization
|
|
|
173,410
|
|
|
|
170,623
|
|
|
|
170,803
|
|
Deferred Income Taxes
|
|
|
(2,521
|
)
|
|
|
72,496
|
|
|
|
52,847
|
|
Income from Unconsolidated Subsidiaries, Net of Cash
Distributions
|
|
|
(466
|
)
|
|
|
1,977
|
|
|
|
(3,366
|
)
|
Impairment of Investment in Partnership
|
|
|
1,804
|
|
|
|
|
|
|
|
|
|
Excess Tax Benefits Associated with Stock-Based Compensation
Awards
|
|
|
(5,927
|
)
|
|
|
(16,275
|
)
|
|
|
(13,689
|
)
|
Other
|
|
|
17,443
|
|
|
|
4,858
|
|
|
|
16,399
|
|
Change in:
|
|
|
|
|
|
|
|
|
|
|
|
|
Hedging Collateral Deposits
|
|
|
(847
|
)
|
|
|
4,065
|
|
|
|
15,610
|
|
Receivables and Unbilled Utility Revenue
|
|
|
47,658
|
|
|
|
(16,815
|
)
|
|
|
5,669
|
|
Gas Stored Underground and Materials and Supplies
|
|
|
43,598
|
|
|
|
(22,116
|
)
|
|
|
(5,714
|
)
|
Unrecovered Purchased Gas Costs
|
|
|
37,708
|
|
|
|
(22,939
|
)
|
|
|
(1,799
|
)
|
Prepayments and Other Current Assets
|
|
|
2,921
|
|
|
|
(36,376
|
)
|
|
|
18,800
|
|
Accounts Payable
|
|
|
(61,149
|
)
|
|
|
32,763
|
|
|
|
(26,002
|
)
|
Amounts Payable to Customers
|
|
|
103,025
|
|
|
|
(7,656
|
)
|
|
|
(13,526
|
)
|
Customer Advances
|
|
|
(8,462
|
)
|
|
|
10,154
|
|
|
|
(6,554
|
)
|
Customer Security Deposits
|
|
|
3,383
|
|
|
|
609
|
|
|
|
1,907
|
|
Other Accruals and Current Liabilities
|
|
|
13,676
|
|
|
|
(4,250
|
)
|
|
|
7,043
|
|
Other Assets
|
|
|
(35,140
|
)
|
|
|
(11,887
|
)
|
|
|
4,109
|
|
Other Liabilities
|
|
|
(4,201
|
)
|
|
|
54,817
|
|
|
|
(5,922
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Cash Provided by Operating Activities
|
|
|
609,432
|
|
|
|
482,776
|
|
|
|
394,197
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investing Activities
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital Expenditures
|
|
|
(309,930
|
)
|
|
|
(397,734
|
)
|
|
|
(276,728
|
)
|
Investment in Subsidiary, Net of Cash Acquired
|
|
|
(34,933
|
)
|
|
|
|
|
|
|
|
|
Investment in Partnerships
|
|
|
(1,317
|
)
|
|
|
|
|
|
|
(3,300
|
)
|
Net Proceeds from Sale of Foreign Subsidiaries
|
|
|
|
|
|
|
|
|
|
|
232,092
|
|
Cash Held in Escrow
|
|
|
(2,000
|
)
|
|
|
58,397
|
|
|
|
(58,248
|
)
|
Net Proceeds from Sale of Oil and Gas Producing Properties
|
|
|
3,643
|
|
|
|
5,969
|
|
|
|
5,137
|
|
Other
|
|
|
(2,806
|
)
|
|
|
4,376
|
|
|
|
(725
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Cash Used in Investing Activities
|
|
|
(347,343
|
)
|
|
|
(328,992
|
)
|
|
|
(101,772
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Financing Activities
|
|
|
|
|
|
|
|
|
|
|
|
|
Excess Tax Benefits Associated with Stock-Based Compensation
Awards
|
|
|
5,927
|
|
|
|
16,275
|
|
|
|
13,689
|
|
Shares Repurchased under Repurchase Plan
|
|
|
|
|
|
|
(237,006
|
)
|
|
|
(48,070
|
)
|
Net Proceeds from Issuance of Long-Term Debt
|
|
|
247,780
|
|
|
|
296,655
|
|
|
|
|
|
Reduction of Long-Term Debt
|
|
|
(100,000
|
)
|
|
|
(200,024
|
)
|
|
|
(119,576
|
)
|
Net Proceeds from Issuance of Common Stock
|
|
|
28,176
|
|
|
|
17,432
|
|
|
|
17,498
|
|
Dividends Paid on Common Stock
|
|
|
(104,158
|
)
|
|
|
(103,683
|
)
|
|
|
(100,632
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Cash Provided By (Used in) Financing Activities
|
|
|
77,725
|
|
|
|
(210,351
|
)
|
|
|
(237,091
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Effect of Exchange Rates on Cash
|
|
|
|
|
|
|
|
|
|
|
(139
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Increase (Decrease) in Cash and Temporary Cash
Investments
|
|
|
339,814
|
|
|
|
(56,567
|
)
|
|
|
55,195
|
|
Cash and Temporary Cash Investments At Beginning of Year
|
|
|
68,239
|
|
|
|
124,806
|
|
|
|
69,611
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and Temporary Cash Investments At End of Year
|
|
$
|
408,053
|
|
|
$
|
68,239
|
|
|
$
|
124,806
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Supplemental Disclosure of Cash Flow Information
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash Paid For:
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
|
|
$
|
75,640
|
|
|
$
|
69,841
|
|
|
$
|
75,987
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income Taxes
|
|
$
|
40,638
|
|
|
$
|
103,154
|
|
|
$
|
97,961
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See Notes to Consolidated Financial Statements
67
NATIONAL
FUEL GAS COMPANY
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended September 30
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
(Thousands of dollars)
|
|
|
Net Income Available for Common Stock
|
|
$
|
100,708
|
|
|
$
|
268,728
|
|
|
$
|
337,455
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Comprehensive Income (Loss), Before Tax:
|
|
|
|
|
|
|
|
|
|
|
|
|
Decrease in the Funded Status of the Pension and Other
Post-Retirement Benefit Plans
|
|
|
(71,771
|
)
|
|
|
(13,584
|
)
|
|
|
|
|
Reclassification Adjustment for Amortization of Prior Year
Funded Status of the Pension and Other Post-Retirement Benefit
Plans
|
|
|
1,008
|
|
|
|
1,924
|
|
|
|
|
|
Foreign Currency Translation Adjustment
|
|
|
(33
|
)
|
|
|
12
|
|
|
|
7,874
|
|
Reclassification Adjustment for Realized Foreign Currency
Translation Gain in Net Income
|
|
|
|
|
|
|
|
|
|
|
(42,658
|
)
|
Unrealized Gain (Loss) on Securities Available for Sale Arising
During the Period
|
|
|
(6,118
|
)
|
|
|
(4,856
|
)
|
|
|
4,747
|
|
Unrealized Gain (Loss) on Derivative Financial Instruments
Arising During the Period
|
|
|
119,210
|
|
|
|
(31,490
|
)
|
|
|
8,495
|
|
Reclassification Adjustment for Realized (Gains) Losses on
Derivative Financial Instruments in Net Income
|
|
|
(114,380
|
)
|
|
|
64,645
|
|
|
|
5,106
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Comprehensive Income (Loss), Before Tax
|
|
|
(72,084
|
)
|
|
|
16,651
|
|
|
|
(16,436
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income Tax Benefit Related to the Decrease in the Funded Status
of the Pension and Other Post-Retirement Benefit Plans
|
|
|
(27,082
|
)
|
|
|
(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
|
|
|
380
|
|
|
|
726
|
|
|
|
|
|
Income Tax Expense (Benefit) Related to Unrealized Gain (Loss)
on Securities Available for Sale Arising During the Period
|
|
|
(2,311
|
)
|
|
|
(1,434
|
)
|
|
|
1,724
|
|
Income Tax Expense (Benefit) Related to Unrealized Gain (Loss)
on Derivative Financial Instruments Arising During the Period
|
|
|
48,293
|
|
|
|
(13,228
|
)
|
|
|
3,153
|
|
Reclassification Adjustment for Income Tax (Expense) Benefit on
Realized (Gains) Losses on Derivative Financial Instruments In
Net Income
|
|
|
(46,005
|
)
|
|
|
26,548
|
|
|
|
2,824
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income Taxes Net
|
|
|
(26,725
|
)
|
|
|
7,485
|
|
|
|
7,701
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Comprehensive Income (Loss)
|
|
|
(45,359
|
)
|
|
|
9,166
|
|
|
|
(24,137
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive Income
|
|
$
|
55,349
|
|
|
$
|
277,894
|
|
|
$
|
313,318
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See Notes to Consolidated Financial Statements
68
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 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.
69
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.
The impact of weather normalized usage per customer account in
the Utility segments New York rate jurisdiction is
tempered by a revenue decoupling mechanism. The effect of the
revenue decoupling mechanism is to render the Company
financially indifferent to throughput decreases resulting from
conservation. Weather normalized usage per account that exceeds
the average weather normalized usage per customer account
results in a refund being credited to customers bills.
Weather normalized usage per account that is below the average
weather normalized usage per account results in a surcharge
being added to customers bills. The surcharge or credit is
calculated over a twelve-month period ending December 31st,
and applied to customer bills annually, beginning March 1st.
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, including return on equity and income taxes, through
fixed monthly reservation charges. Because of this rate design,
changes in throughput due to weather variations do not have a
significant impact on the revenues of Supply Corporation.
Prior to December 10, 2008, the allowed rates that Empire
billed its customers were based on a modified fixed-variable
rate design, which recovered return on equity and income taxes
through variable charges. Because of this rate design, changes
in throughput due to weather variations could have had a
significant impact on Empires revenues. On
December 10, 2008, Empire became FERC regulated. As a
result, Empire now bills its customers based on a straight
fixed-variable rate design. Changes in throughput due to weather
variations no longer have a significant impact on Empires
revenue.
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
70
NATIONAL
FUEL GAS COMPANY
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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 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, 2009, 2008, and 2007, estimated
future net cash flows were increased by $143.3 million,
$34.5 million and $2.2 million, respectively. The
Companys capitalized costs exceeded the full cost ceiling
for the Companys oil and gas properties at
December 31, 2008. As such, the Company recognized a
pre-tax impairment of $182.8 million at December 31,
2008. Deferred income taxes of $74.6 million were recorded
associated with this impairment.
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. In the All Other category, 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
|
|
|
|
2009
|
|
|
2008
|
|
|
|
(Thousands)
|
|
|
Utility
|
|
$
|
1,616,908
|
|
|
$
|
1,580,366
|
|
Pipeline and Storage
|
|
|
1,196,937
|
|
|
|
996,743
|
|
Exploration and Production
|
|
|
1,972,353
|
|
|
|
1,800,422
|
|
Energy Marketing
|
|
|
1,241
|
|
|
|
1,232
|
|
All Other and Corporate
|
|
|
154,512
|
|
|
|
146,005
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
4,941,951
|
|
|
$
|
4,524,768
|
|
|
|
|
|
|
|
|
|
|
71
NATIONAL
FUEL GAS COMPANY
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Average depreciation, depletion and amortization rates are as
follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended September 30
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
Utility
|
|
|
2.6
|
%
|
|
|
2.6
|
%
|
|
|
2.8
|
%
|
Pipeline and Storage
|
|
|
3.0
|
%
|
|
|
3.2
|
%
|
|
|
3.5
|
%
|
Exploration and Production, per Mcfe(1)
|
|
$
|
2.14
|
|
|
$
|
2.26
|
|
|
$
|
1.94
|
|
Energy Marketing
|
|
|
3.4
|
%
|
|
|
3.5
|
%
|
|
|
2.8
|
%
|
All Other and Corporate
|
|
|
5.2
|
%
|
|
|
4.3
|
%
|
|
|
4.1
|
%
|
|
|
|
(1) |
|
Amounts include depletion of oil and gas producing properties as
well as depreciation of fixed assets. As disclosed in
Note Q Supplementary Information for Oil and
Gas Producing Properties, depletion of oil and gas producing
properties amounted to $2.10, $2.23 and $1.92 per Mcfe of
production in 2009, 2008 and 2007, respectively. Depletion of
oil and gas producing properties in the United States amounted
to $2.10, $2.23 and $1.97 per Mcfe of production in 2009, 2008
and 2007, respectively. Depletion of oil and gas producing
properties in Canada amounted to $1.67 per Mcfe of production in
2007. |
Goodwill
The Company has recognized goodwill of $5.5 million as of
September 30, 2009 and 2008 on its Consolidated Balance
Sheets related to the Companys acquisition of Empire in
2003. The Company accounts for goodwill in accordance with the
current authoritative guidance, which requires the Company to
test goodwill for impairment annually. At September 30,
2009 and 2008, 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 G 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. Reference is made to
Note F Fair Value Measurements for further
discussion concerning the fair value of derivative financial
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 2009 or 2008.
72
NATIONAL
FUEL GAS COMPANY
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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 2009, 2008 or 2007.
Accumulated
Other Comprehensive Income (Loss)
The components of Accumulated Other Comprehensive Income (Loss)
are as follows:
|
|
|
|
|
|
|
|
|
|
|
Year Ended September 30
|
|
|
|
2009
|
|
|
2008
|
|
|
|
(Thousands)
|
|
|
Funded Status of the Pension and Other Post-Retirement Benefit
Plans
|
|
$
|
(63,802
|
)
|
|
$
|
(19,741
|
)
|
Cumulative Foreign Currency Translation Adjustment
|
|
|
(104
|
)
|
|
|
(71
|
)
|
Net Unrealized Gain on Derivative Financial Instruments
|
|
|
18,491
|
|
|
|
15,949
|
|
Net Unrealized Gain on Securities Available for Sale
|
|
|
3,019
|
|
|
|
6,826
|
|
|
|
|
|
|
|
|
|
|
Accumulated Other Comprehensive Income (Loss)
|
|
$
|
(42,396
|
)
|
|
$
|
2,963
|
|
|
|
|
|
|
|
|
|
|
At September 30, 2009, it is estimated that of the
$18.5 million net unrealized gain on derivative financial
instruments shown in the table above, $18.6 million of
unrealized gains will be reclassified into the Consolidated
Statement of Income during 2010. The remaining unrealized loss
on derivative financial instruments of $0.1 million will be
reclassified into the Consolidated Statement of Income in
subsequent years. 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 prior
service costs and accumulated losses. The total amount for prior
service costs was $0.3 million and $0.4 million at
September 30, 2009 and September 30, 2008,
respectively. The total amount for accumulated losses was
$63.5 million and $19.3 million at September 30,
2009 and September 30, 2008, respectively.
Gas
Stored Underground Current
In the Utility segment, gas stored underground
current in the amount of $30.4 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 2009, 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
$51.6 million at September 30, 2009. All other gas
stored underground current, which is in the Energy
Marketing segment, is carried at lower of cost or market on an
average cost method.
Purchased
Timber Rights
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
73
NATIONAL
FUEL GAS COMPANY
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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
|
|
|
|
2009
|
|
|
2008
|
|
|
|
(Thousands)
|
|
|
Materials and Supplies
|
|
$
|
6,349
|
|
|
$
|
9,911
|
|
Other Assets
|
|
|
6,343
|
|
|
|
7,383
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
12,692
|
|
|
$
|
17,294
|
|
|
|
|
|
|
|
|
|
|
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, 2009, the Company accrued
$9.1 million of capital expenditures in the Exploration and
Production segment, the majority of which was in the Appalachian
region. The Company also accrued $0.7 million of capital
expenditures in the All Other category related to the
construction of the Midstream Covington Gathering System at
September 30, 2009. These amounts were excluded from the
Consolidated Statement of Cash Flows at September 30, 2009
since they represent non-cash investing activities at that date.
At September 30, 2008, the Company accrued
$16.8 million of capital expenditures related to the
construction of the Empire Connector project. This amount was
excluded from the Consolidated Statement of Cash Flows at
September 30, 2008 since it represented a non-cash
investing activity at that date. These capital expenditures were
paid during the quarter ended December 31, 2008 and have
been included in the Consolidated Statement of Cash Flows for
the year ended September 30, 2009.
74
NATIONAL
FUEL GAS COMPANY
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Hedging
Collateral Account
This is an account title for cash held in margin accounts funded
by the Company to serve as collateral for open hedging
positions. At September 30, 2009, the Company had hedging
collateral deposits of $0.8 million related to its
exchange-traded futures contracts. It is the Companys
policy to not offset hedging collateral deposits paid or
received against the derivative financial instruments liability
or asset balances.
Cash
Held in Escrow
On July 20, 2009, the Companys wholly-owned
subsidiary in the Exploration and Production segment, Seneca,
acquired Ivanhoe Energys United States oil and gas
operations for approximately $39.2 million in cash
(including cash acquired of $4.3 million). The cash
acquired at acquisition includes $2 million held in escrow
at September 30, 2009. Seneca placed this amount in escrow
as part of the purchase price, and in accordance with the
purchase agreement, this amount will remain in escrow for one
year from the closing of the transaction provided there are no
pending disputes or actions regarding obligations and
liabilities required to be satisfied or discharged by Ivanhoe
Energy.
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
$12.2 million and $10.6 million at September 30,
2009 and 2008, respectively, prepaid property and other taxes of
$12.0 million and $11.2 million at September 30,
2009 and 2008, respectively, federal income taxes receivable in
the amounts of $23.3 million and $27.5 million at
September 30, 2009 and 2008, respectively, state income
taxes receivable in the amounts of $13.5 million and
$5.0 million at September 30, 2009 and 2008,
respectively, and fair values of firm commitments in the amounts
of $7.5 million and $10.9 million at
September 30, 2009 and 2008, respectively.
Customer
Advances
The Companys Utility and Energy Marketing segments have
balanced billing programs whereby customers pay their estimated
annual usage in equal installments over a twelve-month period.
Monthly payments under the balanced billing programs are
typically higher than current month usage during the summer
months. During the winter months, monthly payments under the
balanced billing programs are typically lower than current month
usage. At September 30, 2009 and 2008, customers in the
balanced billing programs had advanced excess funds of
$24.6 million and $33.0 million, respectively.
Customer
Security Deposits
The Company, in its Utility, Pipeline and Storage, and Energy
Marketing segments, often times requires security deposits from
marketers, producers, pipeline companies, and commercial and
industrial customers before providing services to such
customers. At September 30, 2009 and 2008, the Company had
received customer security deposits amounting to
$17.4 million and $14.0 million, respectively.
75
NATIONAL
FUEL GAS COMPANY
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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 2009, there were 365,000
stock-settled SARs and 765,000 stock options excluded as being
antidilutive. 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.
Share
Repurchases
The Company considers all shares repurchased as cancelled shares
restored to the status of authorized but unissued shares, in
accordance with New Jersey law. The repurchases are accounted
for on the date the share repurchase is settled as an adjustment
to common stock (at par value) with the excess repurchase price
allocated between paid in capital and retained earnings. Refer
to Note E Capitalization and Short-Term
Borrowings for further discussion of the share repurchase
program.
Stock-Based
Compensation
The Company has various stock option and stock award plans which
provide or provided for the issuance of one or more of the
following to key employees: incentive stock options,
nonqualified stock options, stock-settled SARs, restricted
stock, performance units or performance shares. Stock options
and stock-settled SARs under all plans have exercise prices
equal to the average market price of Company common stock on the
date of grant, and generally no stock option or stock-settled
SAR is exercisable less than one year or more than ten years
after the date of each grant. Restricted stock is subject to
restrictions on vesting and transferability. Restricted stock
awards entitle the participants to full dividend and voting
rights. Certificates for shares of restricted stock awarded
under the Companys stock option and stock award plans are
held by the Company during the periods in which the restrictions
on vesting are effective. Restrictions on restricted stock
awards generally lapse ratably over a period of not more than
ten years after the date of each grant.
The Company follows authoritative guidance 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 the
Black-Scholes-Merton closed form model to calculate the
compensation expense associated with such share-based payments
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.
The Company did not grant any stock options during the years
ended September 30, 2009 and 2008. There were 448,000 stock
options granted during the year ended September 30, 2007.
The Company granted 610,000 and 321,000 performance based
stock-settled SARs during the year ended September 30, 2009
and 2008, respectively, but did not grant any performance based
stock-settled SARs 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, but did not grant any non-performance based stock-settled
SARs during the years ended September 30, 2009 and 2008.
The accounting treatment for such performance based and
non-performance based stock-settled SARs is the same as the
accounting for stock options under the current authoritative
guidance for stock-based compensation. The performance based
stock-settled SARs granted for the year ended
76
NATIONAL
FUEL GAS COMPANY
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
September 30, 2009 vest and become exercisable annually in
one-third increments, provided that a performance condition is
met. The performance condition for each fiscal year, generally
stated, is an increase over the prior fiscal year of at least
five percent in certain oil and natural gas production of the
Exploration and Production segment. 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 2009 and 2008 was estimated on
the date of grant using the same accounting treatment that is
applied for stock options, and assumes that the performance
conditions specified will be achieved. If such conditions are
not met or it is not considered probable that such conditions
will be met, no compensation expense is recognized and any
previously recognized compensation expense is reversed. During
2009, the Company reversed $0.5 million of previously
recognized compensation expense associated with performance
based stock-settled SARs. The Company also granted 63,000,
25,000, and 25,000 restricted share awards (non-vested stock as
defined by the current accounting literature) during the years
ended September 30, 2009, 2008 and 2007, respectively.
Stock-based compensation expense for the years ended
September 30, 2009, 2008 and 2007 was approximately
$2.1 million (net of the $0.5 million reversal of
compensation expense discussed above), $2.3 million, and
$3.7 million, 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, 2009, 2008 and 2007 was approximately
$0.8 million, $0.9 million and $1.5 million,
respectively. There were no capitalized stock-based compensation
costs during the years ended September 30, 2009 and 2008.
Stock
Options
The total intrinsic value of stock options exercised during the
years ended September 30, 2009, 2008 and 2007 totaled
approximately $18.7 million, $24.6 million, and
$38.7 million, respectively. For 2009, 2008 and 2007, the
amount of cash received by the Company from the exercise of such
stock options was approximately $29.2 million,
$18.5 million, and $26.0 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, 2008, 2007, and 2006, the
Company realized a tax benefit of $1.6 million,
$4.4 million, and $3.2 million, respectively. For
stock options exercised during the period of January 1,
2009 through September 30, 2009, the Company will realize a
tax benefit of approximately $5.7 million in the quarter
ended December 31, 2009. For stock options exercised during
the period of January 1, 2008 through September 30,
2008, the Company realized 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. The weighted average grant date fair
value of options granted in 2007 is $7.27 per share. As stated
above, there were no stock options granted during the years
ended September 30, 2009 and 2008. For the years ended
September 30, 2009, 2008 and 2007, 27,000, 358,000 and
327,501 stock options became fully vested, respectively. The
total fair value of the stock options that became vested during
the years ended September 30, 2009, 2008 and 2007 was
approximately $0.2 million, $2.6 million and
$2.1 million, respectively. As of September 30, 2009,
unrecognized compensation expense related to stock options
totaled approximately $47,000, which will be recognized over a
weighted average period of 3.0 months. For a summary of
transactions during 2009 involving option shares for all plans,
refer to Note E Capitalization and Short-Term
Borrowings.
77
NATIONAL
FUEL GAS COMPANY
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The fair value of options 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
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
Risk Free Interest Rate
|
|
|
N/A
|
|
|
|
N/A
|
|
|
|
4.46
|
%
|
Expected Life (Years)
|
|
|
N/A
|
|
|
|
N/A
|
|
|
|
7.0
|
|
Expected Volatility
|
|
|
N/A
|
|
|
|
N/A
|
|
|
|
17.73
|
%
|
Expected Dividend Yield (Quarterly)
|
|
|
N/A
|
|
|
|
N/A
|
|
|
|
0.76
|
%
|
The risk-free interest rate is based on the yield of a Treasury
Note with a remaining term commensurate with the expected term
of the option. The expected life and expected volatility are
based on historical experience.
For grants during the year ended September 30, 2007, it was
assumed that there would be no forfeitures, based on the vesting
term and the number of grantees.
Non-Performance
Based Stock-settled SARs
Participants in the stock option and award plans did not
exercise any non-performance based stock-settled SARs during the
years ended September 30, 2009, 2008 and 2007 since none of
the non-performance based stock-settled SARs granted have
vested. As stated above, 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. The Company did not
grant any non-performance based stock-settled SARs during 2009
or 2008. As of September 30, 2009, unrecognized
compensation expense related to non-performance based
stock-settled SARs totaled approximately $0.1 million,
which will be recognized over a weighted average period of
4.3 months. For a summary of transactions during 2009
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
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
Risk Free Interest Rate
|
|
|
N/A
|
|
|
|
N/A
|
|
|
|
4.53
|
%
|
Expected Life (Years)
|
|
|
N/A
|
|
|
|
N/A
|
|
|
|
7.0
|
|
Expected Volatility
|
|
|
N/A
|
|
|
|
N/A
|
|
|
|
17.55
|
%
|
Expected Dividend Yield (Quarterly)
|
|
|
N/A
|
|
|
|
N/A
|
|
|
|
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
Participants in the stock option and award plans did not
exercise any performance based stock-settled SARs during the
years ended September 30, 2009, 2008 and 2007. As stated
above, there were 610,000 and 321,000 performance based
stock-settled SARs granted during the years ended
September 30, 2009 and 2008,
78
NATIONAL
FUEL GAS COMPANY
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
respectively. The weighted average grant date fair value of
performance based stock-settled SARs granted in 2009 and 2008 is
$4.09 per share and $9.06 per share, respectively. The Company
did not grant any performance based stock-settled SARs during
2007. For the year ended September 30, 2009, 96,984
performance based stock-settled SARs became fully vested. Fiscal
2009 was the first year in which performance based stock-settled
SARs became vested. The total fair value of the performance
based stock-settled SARs that became vested during the year
ended September 30, 2009 was approximately
$0.8 million. As of September 30, 2009, unrecognized
compensation expense related to performance based stock-settled
SARs totaled approximately $1.3 million, which will be
recognized over a weighted average period of 10.9 months.
For a summary of transactions during 2009 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
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
Risk Free Interest Rate
|
|
|
2.56
|
%
|
|
|
3.78
|
%
|
|
|
N/A
|
|
Expected Life (Years)
|
|
|
7.50
|
|
|
|
7.25
|
|
|
|
N/A
|
|
Expected Volatility
|
|
|
22.16
|
%
|
|
|
17.69
|
%
|
|
|
N/A
|
|
Expected Dividend Yield (Quarterly)
|
|
|
1.09
|
%
|
|
|
0.64
|
%
|
|
|
N/A
|
|
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 years ended September 30, 2009 and
2008, it was assumed that there would be no forfeitures, based
on the vesting term and the number of grantees.
Restricted
Share Awards
The weighted average fair value of restricted share awards
granted in 2009, 2008 and 2007 is $47.46 per share, $48.41 per
share and $40.18 per share, respectively. As of
September 30, 2009, unrecognized compensation expense
related to restricted share awards totaled approximately
$3.9 million, which will be recognized over a weighted
average period of 4.4 years. For a summary of transactions
during 2009 involving restricted share awards, refer to
Note E Capitalization and Short-Term Borrowings.
New
Authoritative Accounting and Financial Reporting
Guidance
In September 2006, the FASB issued authoritative guidance for
using fair value to measure assets and liabilities. This
guidance 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. This guidance is to be applied whenever assets
or liabilities are to be measured at fair value. On
October 1, 2008, the Company adopted this guidance for
financial assets and financial liabilities that are recognized
or disclosed at fair value on a recurring basis. This guidance
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. For further
discussion of the impact of the adoption of the authoritative
guidance for financial assets and financial liabilities, refer
to Note F Fair Value Measurements. The Company
is currently evaluating the impact that the adoption of the
authoritative guidance for nonfinancial assets and nonfinancial
liabilities will have on its consolidated financial statements.
The Company has identified Goodwill as being the major
nonfinancial asset that may be impacted by the adoption of this
guidance. The Company does not believe there are any
nonfinancial liabilities that will be impacted by the adoption
of this guidance.
79
NATIONAL
FUEL GAS COMPANY
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
In September 2006, the FASB issued authoritative guidance which
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. This
guidance 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.
This guidance 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 this authoritative guidance, the
Company has recognized the funded status of its benefit plans
and implemented the related disclosure requirements at
September 30, 2007. The requirement to measure the plan
assets and benefit obligations as of the Companys fiscal
year-end date was fully adopted by the Company as of
September 30, 2009. The Company has historically measured
its plan assets and benefit obligations using a
June 30th measurement date. As a result of the change
to a September 30th measurement date, the Company
recorded fifteen months of pension and other post-retirement
benefit costs during fiscal 2009. Such costs were calculated
using June 30, 2008 measurement date data. Three of those
months pertain to the period of July 1, 2008 to
September 30, 2008. The pension and other post-retirement
benefit costs for that period amounted to $5.1 million and
were recorded by the Company during the quarter ended
December 31, 2008 as a $3.8 million increase to Other
Regulatory Assets in the Companys Utility and Pipeline and
Storage segments and a $1.3 million ($0.8 million
after tax) adjustment to earnings reinvested in the business.
Refer to Note H Retirement Plan and Other
Post-Retirement Benefits for further disclosures regarding the
impact of this authoritative guidance on the Companys
consolidated financial statements.
In December 2007, the FASB revised authoritative guidance that
significantly changes 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 this guidance, 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. This guidance is effective as of the Companys
first quarter of fiscal 2010.
In December 2007, the FASB issued authoritative guidance that
changes 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. This authoritative guidance 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 authoritative guidance that
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
authoritative guidance for derivative instruments and hedging
activities, and how derivative instruments and related hedged
items affect an entitys financial position, financial
performance, and cash flows. The Company adopted the disclosure
provisions of this authoritative guidance during the
Companys second quarter of fiscal 2009. Refer to
Note G Financial Instruments for these
disclosures.
In June 2008, the FASB issued authoritative guidance concerning
whether certain instruments granted in share-based payment
transactions are participating securities. This guidance
specified that unvested share-based payment awards that contain
nonforfeitable rights to dividends are participating securities
and shall be included in the computation of earnings per share
pursuant to the two-class method. The
two-class
method allocates undistributed earnings between common shares
and participating securities. This authoritative
80
NATIONAL
FUEL GAS COMPANY
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
guidance is effective as of the Companys first quarter of
fiscal 2010. The Company does not believe this guidance will
have a material impact on its earnings per share calculation.
On December 31, 2008, the SEC issued a final rule on
Modernization of Oil and Gas Reporting. The final rule modifies
the SECs reporting and disclosure rules for oil and gas
reserves and aligns the full cost accounting rules with the
revised disclosures. The most notable changes of the final rule
include the replacement of the single day period-end pricing to
value oil and gas reserves to a
12-month
average of the first day of the month price for each month
within the reporting period. The final rule also permits
voluntary disclosure of probable and possible reserves, a
disclosure previously prohibited by SEC rules. The revised
reporting and disclosure requirements are effective for the
Companys
Form 10-K
for the period ended September 30, 2010. Early adoption is
not permitted. The Company is currently evaluating the impact
that adoption of these rules will have on its consolidated
financial statements and MD&A disclosures.
In March 2009, the FASB issued authoritative guidance that
expands the disclosures required in an employers financial
statements about pension and other post-retirement benefit plan
assets. The additional disclosures include more details on how
investment allocation decisions are made, the plans
investment policies and strategies, the major categories of plan
assets, the inputs and valuation techniques used to measure the
fair value of plan assets, the effect of fair value measurements
using significant unobservable inputs on changes in plan assets
for the period, and disclosure regarding significant
concentrations of risk within plan assets. The additional
disclosure requirements are required for the Companys
Form 10-K
for the period ended September 30, 2010. The Company is
currently evaluating the impact that adoption of this
authoritative guidance will have on its consolidated financial
statement disclosures.
Effective with the June 30, 2009
Form 10-Q,
the Company adopted the FASB authoritative guidance for
subsequent events that establishes general standards of
accounting for and disclosure of events that occur after the
balance sheet date but before financial statements are issued or
are available to be issued. Refer to Note R
Subsequent Events for disclosures made as a result of the
adoption of this guidance.
In June 2009, the FASB issued authoritative guidance that
establishes the FASB Accounting Standards
Codificationtm
(the Codification) as the source of authoritative GAAP
recognized by the FASB to be applied by all nongovernmental
entities in the preparation of financial statements in
conformity with GAAP. Rules and interpretive releases of the SEC
under authority of federal securities law are also sources of
authoritative GAAP for SEC registrants. All other
nongrandfathered, non-SEC accounting literature not included in
the Codification will become nonauthoritative. The Codification
was effective for interim and annual periods ending after
September 15, 2009. Effective with this September 30,
2009
Form 10-K,
the Company has updated its disclosures to conform to the
Codification. There has been no impact on the Companys
consolidated financial statements as the Codification does not
change or alter existing GAAP.
Note B
Asset Retirement Obligations
The Company accounts for asset retirement obligations in
accordance with the authoritative guidance that requires
entities to record the fair value of a liability for an asset
retirement obligation in the period in which it is incurred. An
asset retirement obligation is defined as a legal obligation
associated with the retirement of a tangible long-lived asset in
which the timing
and/or
method of settlement may or may not be conditional on a future
event that may or may not be within the control of the Company.
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.
In accordance with the current authoritative guidance for asset
retirement obligations, the Company has recorded an asset
retirement obligation representing plugging and abandonment
costs associated
81
NATIONAL
FUEL GAS COMPANY
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
with the Exploration and Production segments crude oil and
natural gas wells and has capitalized such costs in property,
plant and equipment (i.e. the full cost pool). Under the current
authoritative guidance for asset retirement obligations, since
plugging and abandonment costs are already included in the full
cost pool, the
units-of-production
depletion calculation excludes 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. In
accordance with current authoritative guidance, since the full
cost pool includes an amount associated with plugging and
abandoning the wells, as discussed in the preceding paragraph,
the calculation of the full cost ceiling no longer reduces the
future net cash flows from proved oil and gas reserves by an
estimate of plugging and abandonment costs.
In addition to the asset retirement obligation recorded in the
Exploration and Production segment, the Company has 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 has also
recorded asset retirement obligations for certain costs
connected with the retirement of distribution mains and services
pipeline systems in the Utility segment and with the
transmission mains and other components in the pipeline systems
in the Pipeline and Storage segment. These retirement costs
within the distribution and transmission systems are primarily
for the capping and purging of pipe, which are generally
abandoned in place when retired, as well as for the
clean-up of
PCB contamination associated with the removal of certain pipe.
A reconciliation of the Companys asset retirement
obligation is shown below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended September 30
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
|
|
|
(Thousands)
|
|
|
|
|
|
Balance at Beginning of Year
|
|
$
|
93,247
|
|
|
$
|
75,939
|
|
|
$
|
77,392
|
|
Liabilities Incurred and Revisions of Estimates
|
|
|
4,492
|
|
|
|
18,739
|
|
|
|
(932
|
)
|
Liabilities Settled
|
|
|
(13,155
|
)
|
|
|
(6,871
|
)
|
|
|
(6,108
|
)
|
Accretion Expense
|
|
|
6,789
|
|
|
|
5,440
|
|
|
|
5,394
|
|
Exchange Rate Impact
|
|
|
|
|
|
|
|
|
|
|
193
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at End of Year
|
|
$
|
91,373
|
|
|
$
|
93,247
|
|
|
$
|
75,939
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
82
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
|
|
|
|
2009
|
|
|
2008
|
|
|
|
(Thousands)
|
|
|
Regulatory Assets(1):
|
|
|
|
|
|
|
|
|
Pension and Other Post-Retirement Benefit Costs(2) (Note H)
|
|
$
|
461,352
|
|
|
$
|
147,909
|
|
Recoverable Future Taxes (Note D)
|
|
|
138,435
|
|
|
|
82,506
|
|
NYPSC Assessment(2)
|
|
|
24,445
|
|
|
|
|
|
Environmental Site Remediation Costs(2) (Note I)
|
|
|
21,456
|
|
|
|
22,530
|
|
Asset Retirement Obligations(2) (Note B)
|
|
|
7,884
|
|
|
|
8,155
|
|
Unamortized Debt Expense (Note A)
|
|
|
6,610
|
|
|
|
7,524
|
|
Unrecovered Purchased Gas Costs (See Regulatory Mechanisms in
Note A)
|
|
|
|
|
|
|
37,708
|
|
Other(2)
|
|
|
15,776
|
|
|
|
10,993
|
|
|
|
|
|
|
|
|
|
|
Total Regulatory Assets
|
|
|
675,958
|
|
|
|
317,325
|
|
|
|
|
|
|
|
|
|
|
Regulatory Liabilities:
|
|
|
|
|
|
|
|
|
Amounts Payable to Customers (See Regulatory Mechanisms in
Note A)
|
|
|
105,778
|
|
|
|
2,753
|
|
Cost of Removal Regulatory Liability
|
|
|
105,546
|
|
|
|
103,100
|
|
Taxes Refundable to Customers (Note D)
|
|
|
67,046
|
|
|
|
18,449
|
|
Pension and Other Post-Retirement Benefit Costs(3) (Note H)
|
|
|
61,003
|
|
|
|
42,994
|
|
Tax Benefit on Medicare Part D Subsidy(3)
|
|
|
28,817
|
|
|
|
23,502
|
|
Off-System Sales and Capacity Release Credits(3)
|
|
|
8,340
|
|
|
|
8,977
|
|
Deferred Insurance Proceeds(3)
|
|
|
3,804
|
|
|
|
3,933
|
|
Other(3)
|
|
|
18,265
|
|
|
|
12,527
|
|
|
|
|
|
|
|
|
|
|
Total Regulatory Liabilities
|
|
|
398,599
|
|
|
|
216,235
|
|
|
|
|
|
|
|
|
|
|
Net Regulatory Position
|
|
$
|
277,359
|
|
|
$
|
101,090
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
The Company recovers the cost of its regulatory assets but
generally does not earn a return on them. There are a few
exceptions to this rule. For example, the Company does earn a
return on Unrecovered Purchased Gas Costs and, in the New York
jurisdiction of its Utility segment, earns a return, within
certain parameters, on the excess of cumulative funding to the
pension plan over the cumulative amount collected in rates. |
|
(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 Consolidated Balance Sheets 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.
83
NATIONAL
FUEL GAS COMPANY
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Cost
of Removal Regulatory Liability
In the Companys Utility and Pipeline and Storage segments,
costs of removing assets (i.e. asset retirement costs) are
collected from customers through depreciation expense. These
amounts are not a legal retirement obligation as discussed in
Note B Asset Retirement Obligations. Rather,
they are classified as a regulatory liability in recognition of
the fact that the Company has collected dollars from the
customer that will be used in the future to fund asset
retirement costs.
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
customer funds the Companys post-retirement benefit plans.
As such, any tax benefit received under the Act must be
flowed-through to the customer. Refer to Note H
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 Pipeline and Storage segment, has deferred
environmental insurance settlement proceeds amounting to
$3.8 million and $3.9 million at September 30,
2009 and 2008, 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 customers funded the premiums on the former insurance
policies.
NYPSC
Assessment
On April 7, 2009, the Governor of the State of New York
signed into law an amendment to the Public Service Law
increasing the allowed utility assessment from the current rate
of one-third
of one percent to one percent of a utilitys in-state gross
operating revenue, together with a temporary surcharge equal, as
applied, to an additional one percent of the utilitys
gross operating revenue. The NYPSC, in a generic proceeding
initiated for the purpose of implementing the amended law, has
authorized the recovery, through rates, of the full cost of the
increased assessment. The assessment is currently being applied
to customer bills in the Utility segments New York
jurisdiction.
Off-System
Sales and Capacity Release Credits
The Company, in its Utility segment, has entered into off-system
sales and capacity release transactions. Most of the margins on
such transactions are returned to the customer with only a small
percentage being retained by the Company. The amount owed to the
customer has been deferred as a regulatory liability.
84
NATIONAL
FUEL GAS COMPANY
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Note D
Income Taxes
The components of federal, state and foreign income taxes
included in the Consolidated Statements of Income are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended September 30
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
|
|
|
(Thousands)
|
|
|
|
|
|
Current Income Taxes
|
|
|
|
|
|
|
|
|
|
|
|
|
Federal
|
|
$
|
43,300
|
|
|
$
|
75,079
|
|
|
$
|
99,608
|
|
State
|
|
|
10,341
|
|
|
|
20,257
|
|
|
|
21,700
|
|
Foreign
|
|
|
|
|
|
|
90
|
|
|
|
22
|
|
Deferred Income Taxes
|
|
|
|
|
|
|
|
|
|
|
|
|
Federal
|
|
|
(4,940
|
)
|
|
|
56,668
|
|
|
|
39,340
|
|
State
|
|
|
2,419
|
|
|
|
15,828
|
|
|
|
10,751
|
|
Foreign
|
|
|
|
|
|
|
|
|
|
|
2,756
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
51,120
|
|
|
|
167,922
|
|
|
|
174,177
|
|
Deferred Investment Tax Credit
|
|
|
(697
|
)
|
|
|
(697
|
)
|
|
|
(697
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Income Taxes
|
|
$
|
50,423
|
|
|
$
|
167,225
|
|
|
$
|
173,480
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Presented as Follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Income
|
|
$
|
(697
|
)
|
|
$
|
(697
|
)
|
|
$
|
(697
|
)
|
Income Tax Expense Continuing Operations
|
|
|
51,120
|
|
|
|
167,922
|
|
|
|
131,813
|
|
Discontinued Operations
|
|
|
|
|
|
|
|
|
|
|
|
|
Income From Operations
|
|
|
|
|
|
|
|
|
|
|
2,792
|
|
Gain on Disposal
|
|
|
|
|
|
|
|
|
|
|
39,572
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Income Taxes
|
|
$
|
50,423
|
|
|
$
|
167,225
|
|
|
$
|
173,480
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The U.S. and foreign components of income (loss) before
income taxes are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended September 30
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
(Thousands)
|
|
|
U.S.
|
|
$
|
151,160
|
|
|
$
|
435,982
|
|
|
$
|
496,074
|
|
Foreign
|
|
|
(29
|
)
|
|
|
(29
|
)
|
|
|
14,861
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
151,131
|
|
|
$
|
435,953
|
|
|
$
|
510,935
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
85
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
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
(Thousands)
|
|
|
Income Tax Expense, Computed at U.S. Federal Statutory Rate of
35%
|
|
$
|
52,896
|
|
|
$
|
152,584
|
|
|
$
|
178,827
|
|
Increase (Reduction) in Taxes Resulting from:
|
|
|
|
|
|
|
|
|
|
|
|
|
State Income Taxes
|
|
|
8,294
|
|
|
|
23,455
|
|
|
|
21,093
|
|
Foreign Tax Differential
|
|
|
10
|
|
|
|
69
|
|
|
|
(20,980
|
)
|
Miscellaneous
|
|
|
(10,777
|
)
|
|
|
(8,883
|
)
|
|
|
(5,460
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Income Taxes
|
|
$
|
50,423
|
|
|
$
|
167,225
|
|
|
$
|
173,480
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The foreign tax differential amount shown above for 2007
includes tax effects relating to the gain on disposition of a
foreign subsidiary.
Significant components of the Companys deferred tax
liabilities and assets are as follows:
|
|
|
|
|
|
|
|
|
|
|
At September 30
|
|
|
|
2009
|
|
|
2008
|
|
|
|
(Thousands)
|
|
|
Deferred Tax Liabilities:
|
|
|
|
|
|
|
|
|
Property, Plant and Equipment
|
|
$
|
733,581
|
|
|
$
|
673,313
|
|
Pension and Other Post-Retirement Benefit Costs
|
|
|
164,120
|
|
|
|
43,340
|
|
Other
|
|
|
69,297
|
|
|
|
55,391
|
|
|
|
|
|
|
|
|
|
|
Total Deferred Tax Liabilities
|
|
|
966,998
|
|
|
|
772,044
|
|
|
|
|
|
|
|
|
|
|
Deferred Tax Assets:
|
|
|
|
|
|
|
|
|
Pension and Other Post-Retirement Benefit Costs
|
|
|
(202,627
|
)
|
|
|
(55,309
|
)
|
Other
|
|
|
(154,358
|
)
|
|
|
(80,492
|
)
|
|
|
|
|
|
|
|
|
|
Total Deferred Tax Assets
|
|
|
(356,985
|
)
|
|
|
(135,801
|
)
|
|
|
|
|
|
|
|
|
|
Total Net Deferred Income Taxes
|
|
$
|
610,013
|
|
|
$
|
636,243
|
|
|
|
|
|
|
|
|
|
|
Presented as Follows:
|
|
|
|
|
|
|
|
|
Net Deferred Tax Liability/(Asset) Current
|
|
$
|
(53,863
|
)
|
|
$
|
1,871
|
|
Net Deferred Tax Liability Non-Current
|
|
|
663,876
|
|
|
|
634,372
|
|
|
|
|
|
|
|
|
|
|
Total Net Deferred Income Taxes
|
|
$
|
610,013
|
|
|
$
|
636,243
|
|
|
|
|
|
|
|
|
|
|
As of September 30, 2009, the Company recorded a deferred
tax asset relating to a federal net operating loss carryover of
$25.1 million. This carryover, which is available as a
result of an acquisition, expires in varying amounts between
2023 and 2029. Although this loss carryover is subject to
certain annual limitations, no valuation allowance was recorded
because of managements determination that the amount will
be fully utilized during the carryforward period.
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 $67.0 million and $18.4 million at
September 30, 2009 and 2008, respectively. Also, regulatory
assets representing future amounts collectible from customers,
corresponding to additional deferred income taxes not previously
recorded because
86
NATIONAL
FUEL GAS COMPANY
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
of prior ratemaking practices, amounted to $138.4 million
and $82.5 million at September 30, 2009 and 2008,
respectively.
During fiscal 2009, consent was received from the Internal
Revenue Service (IRS) National Office approving the
Companys application to change its tax method of
accounting for certain capitalized costs relating to its utility
property. Included in the regulatory liabilities and assets as
of September 30, 2009 noted above are liabilities of
$47.3 million and assets of $51.1 million associated
with this tax accounting method change.
The Company adopted the FASB authoritative guidance for income
tax uncertainties 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.
A reconciliation of the change in unrecognized tax benefits for
the year ended September 30, 2009 and 2008 is as follows:
|
|
|
|
|
|
|
|
|
|
|
Year Ended September 30
|
|
|
|
2009
|
|
|
2008
|
|
|
|
(Thousands)
|
|
|
Balance at Beginning of Year
|
|
$
|
1,700
|
|
|
$
|
1,700
|
|
Additions for Tax Positions Related to Current Year
|
|
|
8,721
|
|
|
|
|
|
Additions for Tax Positions of Prior Years
|
|
|
|
|
|
|
|
|
Reductions for Tax Positions of Prior Years
|
|
|
|
|
|
|
|
|
Settlements with Taxing Authorities
|
|
|
(1,700
|
)
|
|
|
|
|
Lapse of Statute of Limitations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at End of Year
|
|
$
|
8,721
|
|
|
$
|
1,700
|
|
|
|
|
|
|
|
|
|
|
The balance of $8.7 million as of September 30, 2009
relates to tax positions for which the ultimate deductibility is
highly certain but for which there is uncertainty about the
timing of such deductibility. Due to the impact of deferred tax
accounting, other than interest and penalties, the disallowance
of the shorter deductibility period would not materially affect
the annual effective tax rate but would accelerate the payment
of cash to the taxing authority to an earlier period. The
Company anticipates that the unrecognized tax benefits will not
significantly change within the next twelve months.
The Company recognizes interest relating to income taxes in
Other Interest Expense and penalties relating to income taxes in
Other Income. The Company did not recognize any interest expense
related to income taxes during fiscal 2009. The Company
recognized interest expense related to income taxes of
$0.5 million during fiscal 2008. The Company has not
accrued any penalties during fiscal 2009 and 2008.
The Company files U.S. federal and various state income tax
returns. The IRS is currently conducting an examination of the
Company for fiscal 2009 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 2006 and later years, IRS
examinations for fiscal 2008 and prior years have been completed
and the Company believes such years are effectively settled.
The Company is also subject to various routine state income tax
examinations. The Companys operating subsidiaries mainly
operate in four states which have statutes of limitations that
generally expire between three to four years from the date of
filing of the income tax return.
87
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, 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 Authoritative Guidance for
Income Taxes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(406
|
)
|
|
|
|
|
Other Comprehensive Income, 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
|
|
|
|
2,963
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income Available for Common Stock
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
100,708
|
|
|
|
|
|
Dividends Declared on Common Stock ($1.32 Per Share)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(105,410
|
)
|
|
|
|
|
Adoption of Authoritative Guidance for Defined Benefit Pension
and Other Post-Retirement Plans
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(804
|
)
|
|
|
|
|
Other Comprehensive Loss, Net of Tax
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(45,359
|
)
|
Share-Based Payment Expense(2)
|
|
|
|
|
|
|
|
|
|
|
2,055
|
|
|
|
|
|
|
|
|
|
Common Stock Issued Under Stock and Benefit Plans(1)
|
|
|
1,379
|
|
|
|
1,379
|
|
|
|
33,068
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at September 30, 2009
|
|
|
80,500
|
|
|
$
|
80,500
|
|
|
$
|
602,839
|
|
|
$
|
948,293
|
(3)
|
|
$
|
(42,396
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
88
NATIONAL
FUEL GAS COMPANY
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
(1) |
|
Paid in Capital includes tax benefits of $5.9 million,
$16.3 million and $13.7 million for September 30,
2009, 2008 and 2007, respectively, associated with the exercise
of stock options. |
|
(2) |
|
Paid in Capital includes compensation costs associated with
stock option, stock-settled SARs and/or restricted stock awards.
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,
2009, $804.1 million of accumulated earnings was free of
such limitations. |
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 2009, the Company issued 1,609,597 original issue shares
of common stock as a result of stock option exercises and 63,000
original issue shares for restricted stock awards (non-vested
stock as defined in existing guidance). 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 2009, 303,091 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 eight non-employee
directors of the Company who receive compensation under the
Companys Retainer Policy for Non-Employee Directors, as
partial consideration for the directors services. Under
this program, the Company issued 9,865 original issue shares of
common stock during 2009.
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, however, stopped repurchasing shares after
September 17, 2008 in light of the unsettled nature of the
credit markets. Such repurchases may be made in the future. The
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
several times since it was adopted and is now embodied in an
Amended and Restated Rights
89
NATIONAL
FUEL GAS COMPANY
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Agreement effective December 4, 2008, a copy of which was
included as an exhibit to the
Form 8-K
filed by the Company on December 4, 2008.
Pursuant to the Plan, 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 Distribution Date, each holder
of a Right may exercise its right to receive, upon payment of an
amount calculated under the Rights Agreement, common stock of
the Company (or, under certain circumstances, other securities
or assets of the Company) having a value equal to two times the
amount paid to exercise the Right. 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,
upon exercise of the right, common stock of the acquiring
company having a value equal to two times the amount paid to
exercise the right. 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
90
NATIONAL
FUEL GAS COMPANY
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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.
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, 2008
|
|
|
6,464,697
|
|
|
$
|
26.17
|
|
|
|
|
|
|
|
|
|
Granted in 2009
|
|
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
Exercised in 2009
|
|
|
(1,609,597
|
)
|
|
$
|
23.15
|
|
|
|
|
|
|
|
|
|
Forfeited in 2009
|
|
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at September 30, 2009
|
|
|
4,855,100
|
|
|
$
|
27.18
|
|
|
|
2.80
|
|
|
$
|
90,463
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Option shares exercisable at September 30, 2009
|
|
|
4,755,100
|
|
|
$
|
26.92
|
|
|
|
2.71
|
|
|
$
|
89,832
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Option shares available for future grant at September 30,
2009(1)
|
|
|
72,797
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(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, 2008
|
|
|
50,000
|
|
|
$
|
41.20
|
|
|
|
|
|
|
|
|
|
Granted in 2009
|
|
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
Exercised in 2009
|
|
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
Forfeited in 2009
|
|
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at September 30, 2009
|
|
|
50,000
|
|
|
$
|
41.20
|
|
|
|
7.45
|
|
|
$
|
231
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock-settled SARs exercisable at September 30, 2009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
91
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, 2008
|
|
|
315,000
|
|
|
$
|
48.26
|
|
|
|
|
|
|
|
|
|
Granted in 2009
|
|
|
610,000
|
|
|
$
|
29.88
|
|
|
|
|
|
|
|
|
|
Exercised in 2009
|
|
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
Forfeited in 2009
|
|
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at September 30, 2009
|
|
|
925,000
|
|
|
$
|
36.14
|
|
|
|
8.96
|
|
|
$
|
8,947
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock-settled SARs exercisable at September 30, 2009
|
|
|
96,984
|
|
|
$
|
47.37
|
|
|
|
8.40
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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, 2008
|
|
|
58,828
|
|
|
$
|
42.65
|
|
Granted in 2009
|
|
|
63,000
|
|
|
$
|
47.46
|
|
Vested in 2009
|
|
|
(3,828
|
)
|
|
$
|
31.30
|
|
Forfeited in 2009
|
|
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
Restricted Share Awards Outstanding at September 30, 2009
|
|
|
118,000
|
|
|
$
|
46.59
|
|
|
|
|
|
|
|
|
|
|
Vesting restrictions for the outstanding shares of non-vested
restricted stock at September 30, 2009 will lapse as
follows: 2010 27,500 shares; 2011
2,500 shares; 2012 5,000 shares;
2013 5,000 shares; 2014
5,000 shares; 2015 13,000 shares;
2016 5,000 shares; 2018
35,000 shares; and 2021 20,000 shares.
Redeemable
Preferred Stock
As of September 30, 2009, there were 10,000,000 shares
of $1 par value Preferred Stock authorized but unissued.
92
NATIONAL
FUEL GAS COMPANY
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Long-Term
Debt
The outstanding long-term debt is as follows:
|
|
|
|
|
|
|
|
|
|
|
At September 30
|
|
|
|
2009
|
|
|
2008
|
|
|
|
(Thousands)
|
|
|
Medium-Term Notes(1):
|
|
|
|
|
|
|
|
|
6.7% to 7.50% due November 2010 to June 2025
|
|
$
|
449,000
|
|
|
$
|
549,000
|
|
Notes(1):
|
|
|
|
|
|
|
|
|
5.25% to 8.75% due March 2013 to May 2019
|
|
|
800,000
|
|
|
|
550,000
|
|
|
|
|
|
|
|
|
|
|
Total Long-Term Debt
|
|
|
1,249,000
|
|
|
|
1,099,000
|
|
Less Current Portion
|
|
|
|
|
|
|
100,000
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
1,249,000
|
|
|
$
|
999,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
The Medium-Term Notes and Notes are unsecured. |
In April 2009, the Company issued $250.0 million of
8.75% notes due in May 2019. After deducting underwriting
discounts and commissions, the net proceeds to the Company
amounted to $247.8 million. These notes were registered
under the Securities Act of 1933. The holders of the notes may
require the Company to repurchase their notes at a price equal
to 101% of the principal amount in the event of both a change in
control and a ratings downgrade to a rating below investment
grade. The proceeds of this debt issuance were used for general
corporate purposes, including to replenish cash that was used to
pay the $100 million due at the maturity of the
Companys 6.0% medium-term notes on March 1, 2009.
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. In February
2009, the Company exchanged the notes for economically identical
notes registered 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 at a price equal to 101% of the principal
amount in the event of both a change in control and a ratings
downgrade to a rating below investment grade. The Company used
$200.0 million of the proceeds of the issuance to refund
$200.0 million of 6.303% medium-term notes that matured on
May 27, 2008.
As of September 30, 2009, the aggregate principal amounts
of long-term debt maturing during the next five years and
thereafter are as follows: zero in 2010, $200.0 million in
2011, $150.0 million in 2012, $250.0 million in 2013,
zero in 2014, and $649.0 million thereafter.
Short-Term
Borrowings
The Company historically has obtained short-term funds either
through bank loans or the issuance of commercial paper. As for
the former, the Company maintains a number of individual
uncommitted or discretionary lines of credit with certain
financial institutions for general corporate purposes.
Borrowings under these lines of credit are made at competitive
market rates. These credit lines, which aggregate to
$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, 2009 and 2008, the Company had no
outstanding short-term notes payable to banks or commercial
paper.
93
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, 2009, the
Companys debt to capitalization ratio (as calculated under
the facility) was .44. The constraints specified in the
committed credit facility would permit an additional
$1.7 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, 2009, the Company would have been permitted
to issue up to a maximum of $435.0 million 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. If the Company were to experience another
impairment of oil and gas properties in the future, it is
possible that these indenture covenants would restrict the
Companys ability to issue additional long-term unsecured
indebtedness. This would not preclude the Company from issuing
new indebtedness to replace maturing debt.
The Companys 1974 indenture pursuant to which
$99.0 million (or 7.9%) of the Companys long-term
debt (as of September 30, 2009) 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, 2009, the Company had no debt outstanding
under the committed credit facility.
Note F
Fair Value Measurements
Beginning in fiscal 2009, the Company adopted the FASB
authoritative guidance regarding fair value measurements which
establishes a fair-value hierarchy and prioritizes the inputs
used in valuation techniques that measure fair value. Those
inputs are prioritized into three levels. Level 1 inputs
are unadjusted quoted prices in active markets for assets or
liabilities that the Company has the ability to access at the
measurement date. Level 2 inputs are inputs other than
quoted prices included within Level 1 that are observable
for the asset or liability, either directly or indirectly at the
measurement date. Level 3 inputs are unobservable inputs
for the asset or liability at the measurement date. The
Companys assessment of the significance of a particular
input to the fair value measurement requires judgment, and may
affect the valuation of fair value assets and liabilities and
their placement within the fair value hierarchy levels. The
adoption of this authoritative guidance regarding fair value
measurements has not had a significant impact on the
consolidated financial statements.
94
NATIONAL
FUEL GAS COMPANY
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The following table sets forth, by level within the fair value
hierarchy, the Companys financial assets and liabilities
that were accounted for at fair value on a recurring basis as of
September 30, 2009. Financial assets and liabilities are
classified in their entirety based on the lowest level of input
that is significant to the fair value measurement.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
At fair Value as of September 30, 2009
|
|
Recurring Fair Value Measures
|
|
Level 1
|
|
|
Level 2
|
|
|
Level 3
|
|
|
Total
|
|
|
|
(Dollars in thousands)
|
|
|
Assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash Equivalents
|
|
$
|
390,462
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
390,462
|
|
Derivative Financial Instruments
|
|
|
5,312
|
|
|
|
12,536
|
|
|
|
26,969
|
|
|
|
44,817
|
|
Other Investments
|
|
|
24,276
|
|
|
|
|
|
|
|
|
|
|
|
24,276
|
|
Hedging Collateral Deposits
|
|
|
848
|
|
|
|
|
|
|
|
|
|
|
|
848
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
420,898
|
|
|
$
|
12,536
|
|
|
$
|
26,969
|
|
|
$
|
460,403
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative Financial Instruments
|
|
$
|
|
|
|
$
|
2,148
|
|
|
$
|
|
|
|
$
|
2,148
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
|
|
|
$
|
2,148
|
|
|
$
|
|
|
|
$
|
2,148
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
Equivalents
The cash equivalents reported in Level 1 consist of SEC
registered money market mutual funds.
Derivative
Financial Instruments
The derivative financial instruments reported in Level 1
consist of NYMEX futures contracts. The hedging collateral
deposits associated with these futures contracts have been
reported in Level 1 as well. The derivative financial
instruments reported in Level 2 consist of natural gas swap
agreements used in the Companys Exploration and Production
segment and natural gas swap agreements used in the Energy
Marketing segment. The fair value of these natural gas swap
agreements is based on an internal model that uses observable
inputs. The fair market value of the price swap agreements
reported in Level 2 as assets has been reduced by
$0.2 million based on an assessment of counterparty credit
risk. The derivative financial instruments reported in
Level 3 consist of all of the Exploration and Production
segments crude oil swap agreements. The fair value of the
crude oil swap agreements is based on an internal model that
uses both observable and unobservable inputs. The fair market
value of the price swap agreements reported in Level 3 as
assets has been reduced by $0.7 million based on an
assessment of counterparty credit risk. The fair market value of
the price swap agreements reported in Level 2 as
liabilities has been reduced by less than $0.1 million
based on an assessment of the Companys credit risk. This
credit reserve, as well as the credit reserve established for
the Level 2 and Level 3 swap agreement assets, was
determined by applying default probabilities to the anticipated
cash flows that the Company is either expecting from its
counterparties or expecting to pay to its counterparties.
Other
Investments
The other investments reported in Level 1 consist of
publicly traded equity securities and a publicly traded balanced
equity mutual fund.
The table listed below provides a reconciliation of the
beginning and ending net balances for assets and liabilities
measured at fair value and classified as Level 3.
95
NATIONAL
FUEL GAS COMPANY
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Fair
Value Measurements Using Unobservable Inputs
(Level 3)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Gains/Losses
|
|
|
|
|
|
|
|
|
|
|
|
|
Realized and Unrealized
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Included in Other
|
|
|
Transfer
|
|
|
|
|
|
|
October 1,
|
|
|
Included in
|
|
|
Comprehensive Income
|
|
|
In/(Out) of
|
|
|
September 30,
|
|
|
|
2008
|
|
|
Earnings
|
|
|
(Loss)
|
|
|
Level 3
|
|
|
2009
|
|
|
|
(Dollars in thousands)
|
|
|
Assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative Financial Instruments
|
|
$
|
7,110
|
|
|
$
|
(47,076
|
)(1)
|
|
$
|
75,077
|
|
|
$
|
(8,142
|
)(2)
|
|
$
|
26,969
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
7,110
|
|
|
$
|
(47,076
|
)
|
|
$
|
75,077
|
|
|
$
|
(8,142
|
)
|
|
$
|
26,969
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative Financial Instruments
|
|
$
|
(777
|
)
|
|
$
|
(12,104
|
)(1)
|
|
$
|
12,070
|
|
|
$
|
811
|
(2)
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
(777
|
)
|
|
$
|
(12,104
|
)
|
|
$
|
12,070
|
|
|
$
|
811
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Amounts are reported in Operating Revenues in the Consolidated
Statement of Income for the year ended September 30, 2009. |
|
(2) |
|
These transfers occurred because the Company was able to obtain
and utilize forward-looking, observable basis differential
information for its hedges on southern California natural gas
production. |
Note G
Financial Instruments
Long-Term
Debt
At September 30, 2009, the fair market value of the
Companys debt, as presented in the table below, was
determined using a discounted cash flow model, which
incorporates the Companys credit risk in determining the
yield, and subsequently, the fair market value of the debt. At
September 30, 2008, the fair market value of the
Companys long-term debt was determined 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
|
|
|
|
2009 Carrying
|
|
|
2009 Fair
|
|
|
2008 Carrying
|
|
|
2008 Fair
|
|
|
|
Amount
|
|
|
Value
|
|
|
Amount
|
|
|
Value
|
|
|
|
(Thousands)
|
|
|
Long-Term Debt
|
|
$
|
1,249,000
|
|
|
$
|
1,347,368
|
|
|
$
|
1,099,000
|
|
|
$
|
1,027,098
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The fair value amounts are not intended to reflect principal
amounts that the Company will ultimately be required to pay.
Carrying amounts for other financial instruments recorded on the
Companys Consolidated Balance Sheets approximate fair
value.
Other
Investments
Investments in life 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 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
$54.2 million and $53.6 million at September 30,
2009 and 2008, respectively. The fair value of the equity mutual
fund was $15.8 million and $12.4 million at
September 30, 2009 and 2008,
96
NATIONAL
FUEL GAS COMPANY
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
respectively. The gross unrealized loss on this equity mutual
fund was $1.0 million at September 30, 2009 and
September 30, 2008. Although this investment has been in an
unrealized loss position for over twelve months, management has
the intent and ability to hold the investment for a sufficient
period of time for the asset to recover in value. As such,
management does not consider this investment to be other than
temporarily impaired. The fair value of the stock of an
insurance company was $8.3 million and $14.5 million
at September 30, 2009 and 2008, respectively. The gross
unrealized gain on this stock was $5.9 million and
$12.1 million at September 30, 2009 and 2008,
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 is exposed to certain risks relating to its ongoing
business operations. The primary risk managed by using
derivative instruments is commodity price risk in the
Exploration and Production and Energy Marketing segments. The
Company enters into futures contracts and
over-the-counter
swap agreements for natural gas and crude oil to manage the
price risk associated with forecasted sales of gas and oil. The
Company also enters into futures contracts and swaps to manage
the risk associated with forecasted gas purchases, storage of
gas, and withdrawal of gas from storage to meet customer demand.
The duration of the Companys hedges do not typically
exceed 3 years and the majority of the positions settle
within one year.
The Company has presented its net derivative assets and
liabilities on its Consolidated Balance Sheet at
September 30, 2009 as shown in the table below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Values of Derivative Instruments
|
|
|
(Dollar Amounts in Thousands)
|
|
|
Asset Derivatives
|
|
Liability Derivatives
|
Derivatives
|
|
September 30, 2009
|
|
September 30, 2009
|
Designated as
|
|
Consolidated
|
|
|
|
Consolidated
|
|
|
Hedging
|
|
Balance Sheet
|
|
|
|
Balance Sheet
|
|
|
Instruments
|
|
Location
|
|
Fair Value
|
|
Location
|
|
Fair Value
|
|
Commodity
Contracts
|
|
Fair Value of
Derivative
Financial
Instruments
|
|
$
|
44,817
|
|
|
Fair Value of
Derivative
Financial
Instruments
|
|
$
|
2,148
|
|
The following table discloses the fair value of derivative
contracts on a gross-contract basis as opposed to the
net-contract basis presentation on the Consolidated Balance
Sheet at September 30, 2009.
|
|
|
|
|
Derivatives
|
|
Fair Values of Derivative Instruments
|
Designated as
|
|
(Dollar Amounts in Thousands)
|
Hedging
|
|
Gross Asset Derivatives
|
|
Gross Liability Derivatives
|
Instruments
|
|
September 30, 2009
|
|
September 30, 2009
|
|
|
|
Fair Value
|
|
Fair Value
|
Commodity
Contracts
|
|
$63,601
|
|
$20,932
|
Cash
Flow Hedges
For derivative instruments that are designated and qualify as a
cash flow hedge, the effective portion of the gain or loss on
the derivative is reported as a component of other comprehensive
income and reclassified into earnings in the same period or
periods during which the hedged transaction affects earnings.
Gains and losses on the derivative representing either hedge
ineffectiveness or hedge components excluded from the assessment
of effectiveness are recognized in current earnings.
As of September 30, 2009, the Companys Exploration
and Production segment had the following commodity derivative
contracts (swaps) outstanding to hedge forecasted sales (where
the Company uses short
97
NATIONAL
FUEL GAS COMPANY
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
positions (i.e. positions that pay-off in the event of commodity
price decline) to mitigate the risk of decreasing revenues and
earnings):
|
|
|
Commodity
|
|
Units
|
|
Natural Gas
|
|
36.9 Bcf (all short positions)
|
Crude Oil
|
|
2,688,000 Bbls (all short positions)
|
As of September 30, 2009, the Companys Energy
Marketing segment had the following commodity derivative
contracts (futures contracts and swaps) outstanding to hedge
forecasted sales (where the Company uses short positions to
mitigate the risk associated with natural gas price decreases
and its impact on decreasing revenues and earnings) and
purchases (where the Company uses long positions (i.e. positions
that pay-off in the event of commodity price increases) to
mitigate the risk of increasing natural gas prices, which would
lead to increased purchased gas expense and decreased earnings):
|
|
|
Commodity
|
|
Units
|
|
Natural Gas
|
|
6.4 Bcf (6.2 Bcf short positions (forecasted storage
withdrawals) and 0.2 Bcf long positions (forecasted storage
injections))
|
As of September 30, 2009, the Companys Exploration
and Production segment had $36.2 million
($21.3 million after tax) of gains included in the
accumulated other comprehensive income balance. It is expected
that $36.4 million ($21.4 million after tax) of these
gains will be reclassified into income within the next
12 months as the sales of the underlying commodities are
expected to occur. See Note A, under Accumulated Other
Comprehensive Income (Loss), for the after-tax gain pertaining
to derivative financial instruments (Net Unrealized Gain on
Derivative Financial Instruments in Note A includes both
the Exploration and Production and Energy Marketing segments).
As of September 30, 2009, the Companys Energy
Marketing segment had $4.7 million ($2.8 million after
tax) of losses included in the accumulated other comprehensive
income (loss) balance. It is expected that $4.7 million
($2.8 million after tax) of these losses will be
reclassified into income within the next 12 months as the
sales and purchases of the underlying commodities occur. See
Note A, under Accumulated Other Comprehensive Income
(Loss), for the after-tax gain pertaining to derivative
financial instruments (Net Unrealized Gain on Derivative
Financial Instruments in Note A includes both the
Exploration and Production and Energy Marketing segments).
98
NATIONAL
FUEL GAS COMPANY
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The Effect of Derivative Financial Instruments on the
Statement of Financial Performance for the
|
|
|
Year Ended September 30, 2009 (Dollar Amounts in
Thousands)
|
|
|
Amount of
|
|
|
|
Amount of
|
|
|
|
|
|
|
Derivative Gain or
|
|
|
|
Derivative Gain or
|
|
|
|
|
|
|
(Loss) Recognized
|
|
Location of
|
|
(Loss) Reclassified
|
|
|
|
|
|
|
in Other
|
|
Derivative Gain or
|
|
from Accumulated
|
|
|
|
Derivative Gain or
|
|
|
Comprehensive
|
|
(Loss) Reclassified
|
|
Other Comprehensive
|
|
Location of
|
|
(Loss) Recognized
|
|
|
Income (Loss) on
|
|
from Accumulated
|
|
Income (Loss) on
|
|
Derivative Gain or
|
|
in the Consolidated
|
|
|
the Consolidated
|
|
Other Comprehensive
|
|
the Consolidated
|
|
(Loss) Recognized
|
|
Statement of Income
|
|
|
Statement of
|
|
Income (Loss) on
|
|
Balance Sheet into
|
|
in the Consolidated
|
|
(Ineffective
|
|
|
Comprehensive
|
|
the Consolidated
|
|
the Consolidated
|
|
Statement of Income
|
|
Portion and Amount
|
|
|
Income (Effective
|
|
Balance Sheet into
|
|
Statement of Income
|
|
(Ineffective
|
|
Excluded from
|
Derivatives in Cash
|
|
Portion) for the
|
|
the Consolidated
|
|
(Effective Portion)
|
|
Portion and Amount
|
|
Effectiveness Testing)
|
Flow Hedging
|
|
Year Ended
|
|
Statement of Income
|
|
for the Year Ended
|
|
Excluded from
|
|
for the Year Ended
|
Relationships
|
|
September 30, 2009
|
|
(Effective Portion)
|
|
September 30, 2009
|
|
Effectiveness Testing)
|
|
September 30, 2009
|
|
Commodity Contracts Exploration &
Production segment
|
|
$
|
110,883
|
|
|
Operating Revenue
|
|
$
|
91,808
|
|
|
Operating Revenue
|
|
$
|
|
|
Commodity Contracts Energy Marketing segment
|
|
$
|
7,492
|
|
|
Purchased Gas
|
|
$
|
21,301
|
|
|
Operating Revenue
|
|
$
|
|
|
Commodity Contracts Pipeline & Storage
segment(1)
|
|
$
|
652
|
|
|
Operating Revenue
|
|
$
|
1,952
|
|
|
Operating Revenue
|
|
$
|
|
|
Commodity Contracts All Other(1)
|
|
$
|
183
|
|
|
Purchased Gas
|
|
$
|
(681
|
)
|
|
Purchased Gas
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
119,210
|
|
|
|
|
$
|
114,380
|
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
There were no open hedging positions at September 30, 2009.
As such there is no mention of these positions in the preceding
sections of this footnote. |
Fair
value hedges
The Companys Energy Marketing segment utilizes fair value
hedges to mitigate risk associated with fixed price sales
commitments, fixed price purchase commitments, and commitments
related to the injection and withdrawal of storage gas. In order
to hedge fixed price sales commitments, the Company enters into
long positions to mitigate the risk that after the Company
enters into fixed price sales agreements with its customers, the
price of natural gas increases (thereby passing up the
opportunity for higher operating revenue). With fixed price
purchase commitments, the Company enters into short positions to
mitigate the risk that after the Company locks into fixed price
purchase deals with its suppliers, the price of natural gas
decreases (thereby passing up the opportunity for lower
purchased gas expense). Fair value hedges related to the
injection and withdrawal of storage gas impact purchased gas
expense. As of September 30, 2009, the Companys
Energy Marketing segment had fair value hedges covering
approximately 13.0 Bcf (11.7 Bcf of fixed price sales
commitments (all long positions), 0.9 Bcf of fixed price
purchase commitments (all short positions), and 0.4 Bcf of
commitments related to the withdrawal of storage gas (all short
positions)). For derivative instruments that are designated and
qualify as a fair value hedge, the gain or loss on the
derivative as well as the offsetting gain or loss on the hedged
item attributable to the hedged risk completely offset each
other in current earnings, as shown below.
|
|
|
|
|
|
|
|
|
Consolidated Statement of Income
|
|
Gain/(Loss) on Derivative
|
|
Gain/(Loss) on Commitment
|
|
Operating Revenues
|
|
$
|
5,242,000
|
|
|
$
|
(5,242,000
|
)
|
Purchased Gas
|
|
$
|
(8,252,000
|
)
|
|
$
|
8,252,000
|
|
99
NATIONAL
FUEL GAS COMPANY
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
Amount of
|
|
|
|
|
Derivative Gain or
|
|
|
Location of
|
|
(Loss) Recognized
|
|
|
Derivative Gain or
|
|
in the Consolidated
|
|
|
(Loss) Recognized
|
|
Statement of Income
|
|
|
in the Consolidated
|
|
for the Year Ended
|
Derivatives in Fair Value Hedging Relationships
|
|
Statement of Income
|
|
September 30, 2009
|
|
|
|
|
(In thousands)
|
|
Commodity Contracts Energy Marketing segment(1)
|
|
|
Operating Revenues
|
|
|
$
|
5,242
|
|
Commodity Contracts Energy Marketing segment(2)
|
|
|
Purchased Gas
|
|
|
$
|
11
|
|
Commodity Contracts Energy Marketing segment(3)
|
|
|
Purchased Gas
|
|
|
$
|
(8,263
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
(3,010
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Represents hedging of fixed price sales commitments of natural
gas. |
|
(2) |
|
Represents hedging of fixed price purchase commitments of
natural gas. |
|
(3) |
|
Represents hedging of storage withdrawal commitments of natural
gas. |
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 a
quarterly basis monitors counterparty credit exposure. The
majority of the Companys counterparties are financial
institutions and energy traders. The Company has
over-the-counter
swap positions with ten counterparties. At September 30,
2009, the Company had derivative financial instruments that were
in gain positions with eight of the counterparties. The Company
had derivative financial instruments that were in loss positions
with the other two counterparties. The Company had
$26.6 million of credit exposure with one counterparty
(which is rated A1 (Moodys Investor Service), A
(S&P), and A+ (Fitch Ratings Service) as of
September 30, 2009). On average for those financial
instruments that were in a gain position, the Company had
$1.8 million of credit exposure per counterparty with the
other seven counterparties that were in a gain position. The
Company had not received any collateral from the counterparties
at September 30, 2009 since the Companys gain
position on such derivative financial instruments had not
exceeded the established thresholds at which the counterparties
would be required to post collateral.
As of September 30, 2009, eight of the ten counterparties
to the Companys outstanding derivative instrument
contracts (specifically the
over-the-counter
swaps) had a common credit-risk-related contingency feature. In
the event the Companys credit rating increases or falls
below a certain threshold (the lower of the S&P or
Moodys Debt Rating), the available credit extended to the
Company would either increase or decrease. A decline in the
Companys credit rating, in and of itself, would not cause
the Company to be required to increase the level of its hedging
collateral deposits (in the form of cash deposits, letters of
credit or treasury debt instruments). If the Companys
outstanding derivative instrument contracts were in a liability
position and the Companys credit rating declined, then
additional hedging collateral deposits would be required. At
September 30, 2009, these credit-risk related contingency
features were not triggered since the Company had assets of
$37.9 million related to derivative financial instruments
with the eight counterparties.
For its exchange traded futures contracts, which are in an asset
position, the Company had paid $0.8 million in hedging
collateral as of September 30, 2009. As these are exchange
traded futures contracts, there are no specific credit-risk
related contingency features. The Company posts hedging
collateral based on open positions (i.e. those positions that
have been settled for cash) and margin requirements. (This is
discussed in Note A under Hedging Collateral Deposits.)
100
NATIONAL
FUEL GAS COMPANY
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Note H
Retirement Plan and Other Post-Retirement Benefits
The Company has a tax-qualified, noncontributory,
defined-benefit retirement plan (Retirement Plan) that covers a
majority of the full-time 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 were
$0.4 million, $0.2 million and $0.2 million for
the years ended September 30, 2009, 2008 and 2007,
respectively. Costs associated with the Companys
contributions to the Tax-Deferred Savings Plans were
$4.1 million, $4.0 million, and $4.1 million for
the years ended September 30, 2009, 2008 and 2007,
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 trust used to pay retiree medical benefits for
the associated participants in the Retirement Plan. Although
these accounts are in the Retirement Plan trust, 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.
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 September 30, 2009,
June 30, 2008 and June 30, 2007, for fiscal year 2009,
2008 and 2007, respectively.
101
NATIONAL
FUEL GAS COMPANY
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Retirement Plan
|
|
|
Other Post-Retirement Benefits
|
|
|
|
Year Ended September 30
|
|
|
Year Ended September 30
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
(Thousands)
|
|
|
Change in Benefit Obligation
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Benefit Obligation at Beginning of Period
|
|
$
|
719,059
|
|
|
$
|
742,519
|
|
|
$
|
732,207
|
|
|
$
|
411,545
|
|
|
$
|
444,545
|
|
|
$
|
445,931
|
|
Service Cost
|
|
|
10,913
|
|
|
|
12,597
|
|
|
|
12,898
|
|
|
|
3,801
|
|
|
|
5,104
|
|
|
|
5,614
|
|
Interest Cost
|
|
|
46,836
|
|
|
|
44,949
|
|
|
|
44,350
|
|
|
|
27,499
|
|
|
|
27,081
|
|
|
|
27,198
|
|
Plan Participants Contributions
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,185
|
|
|
|
1,990
|
|
|
|
1,566
|
|
Retiree Drug Subsidy Receipts
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,427
|
|
|
|
1,532
|
|
|
|
1,325
|
|
Amendments(1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(10,765
|
)
|
|
|
(31,874
|
)
|
|
|
|
|
Actuarial (Gain) Loss
|
|
|
102,430
|
|
|
|
(34,189
|
)
|
|
|
(2,986
|
)
|
|
|
55,776
|
|
|
|
(14,390
|
)
|
|
|
(14,450
|
)
|
Adjustment for Change in Measurement Date
|
|
|
14,438
|
|
|
|
|
|
|
|
|
|
|
|
7,825
|
|
|
|
|
|
|
|
|
|
Benefits Paid
|
|
|
(62,180
|
)
|
|
|
(46,817
|
)
|
|
|
(43,950
|
)
|
|
|
(31,998
|
)
|
|
|
(22,443
|
)
|
|
|
(22,639
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Benefit Obligation at End of Period
|
|
$
|
831,496
|
|
|
$
|
719,059
|
|
|
$
|
742,519
|
|
|
$
|
467,295
|
|
|
$
|
411,545
|
|
|
$
|
444,545
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Change in Plan Assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value of Assets at Beginning of Period
|
|
$
|
695,089
|
|
|
$
|
765,144
|
|
|
$
|
664,521
|
|
|
$
|
377,640
|
|
|
$
|
412,371
|
|
|
$
|
325,624
|
|
Actual Return on Plan Assets
|
|
|
(99,511
|
)
|
|
|
(39,206
|
)
|
|
|
119,662
|
|
|
|
(62,368
|
)
|
|
|
(43,478
|
)
|
|
|
65,552
|
|
Employer Contributions
|
|
|
15,993
|
|
|
|
3,817
|
|
|
|
16,488
|
|
|
|
25,659
|
|
|
|
29,200
|
|
|
|
42,268
|
|
Employer Contributions During Period from Measurement Date to
Fiscal Year End
|
|
|
N/A
|
|
|
|
12,151
|
|
|
|
8,423
|
|
|
|
N/A
|
|
|
|
|
|
|
|
|
|
Plan Participants Contributions
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,185
|
|
|
|
1,990
|
|
|
|
1,566
|
|
Adjustment for Change in Measurement Date
|
|
|
14,490
|
|
|
|
|
|
|
|
|
|
|
|
7,904
|
|
|
|
|
|
|
|
|
|
Benefits Paid
|
|
|
(62,180
|
)
|
|
|
(46,817
|
)
|
|
|
(43,950
|
)
|
|
|
(31,998
|
)
|
|
|
(22,443
|
)
|
|
|
(22,639
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value of Assets at End of Period
|
|
$
|
563,881
|
|
|
$
|
695,089
|
|
|
$
|
765,144
|
|
|
$
|
319,022
|
|
|
$
|
377,640
|
|
|
$
|
412,371
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Amount Recognized at End of Period (Funded Status)
|
|
$
|
(267,615
|
)
|
|
$
|
(23,970
|
)
|
|
$
|
22,625
|
|
|
$
|
(148,273
|
)
|
|
$
|
(33,905
|
)
|
|
$
|
(32,174
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amounts Recognized in the Balance Sheets Consist of:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accrued Benefit Liability
|
|
$
|
(267,615
|
)
|
|
$
|
(23,970
|
)
|
|
$
|
|
|
|
$
|
(148,273
|
)
|
|
$
|
(54,939
|
)
|
|
$
|
(70,555
|
)
|
Prepaid Benefit Cost
|
|
|
|
|
|
|
|
|
|
|
22,625
|
|
|
|
|
|
|
|
21,034
|
|
|
|
38,381
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Amount Recognized at End of Period
|
|
$
|
(267,615
|
)
|
|
$
|
(23,970
|
)
|
|
$
|
22,625
|
|
|
$
|
(148,273
|
)
|
|
$
|
(33,905
|
)
|
|
$
|
(32,174
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated Benefit Obligation
|
|
$
|
758,658
|
|
|
$
|
659,004
|
|
|
$
|
672,340
|
|
|
|
N/A
|
|
|
|
N/A
|
|
|
|
N/A
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
102
NATIONAL
FUEL GAS COMPANY
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Retirement Plan
|
|
|
Other Post-Retirement Benefits
|
|
|
|
Year Ended September 30
|
|
|
Year Ended September 30
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
(Thousands)
|
|
|
Weighted Average Assumptions Used to Determine Benefit
Obligation at September 30
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Discount Rate
|
|
|
5.50
|
%
|
|
|
6.75
|
%
|
|
|
6.25
|
%
|
|
|
5.50
|
%
|
|
|
6.75
|
%
|
|
|
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
|
|
$
|
10,913
|
|
|
$
|
12,597
|
|
|
$
|
12,898
|
|
|
$
|
3,801
|
|
|
$
|
5,104
|
|
|
$
|
5,614
|
|
Interest Cost
|
|
|
46,836
|
|
|
|
44,949
|
|
|
|
44,350
|
|
|
|
27,499
|
|
|
|
27,081
|
|
|
|
27,198
|
|
Expected Return on Plan Assets
|
|
|
(57,958
|
)
|
|
|
(55,000
|
)
|
|
|
(51,235
|
)
|
|
|
(31,615
|
)
|
|
|
(33,715
|
)
|
|
|
(26,960
|
)
|
Amortization of Prior Service Cost
|
|
|
732
|
|
|
|
808
|
|
|
|
882
|
|
|
|
(1,074
|
)
|
|
|
4
|
|
|
|
4
|
|
Amortization of Transition Amount
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,265
|
|
|
|
7,127
|
|
|
|
7,127
|
|
Recognition of Actuarial Loss(2)
|
|
|
5,676
|
|
|
|
11,064
|
|
|
|
13,528
|
|
|
|
9,271
|
|
|
|
2,927
|
|
|
|
8,214
|
|
Net Amortization and Deferral for Regulatory Purposes
|
|
|
12,817
|
|
|
|
6,008
|
|
|
|
1,211
|
|
|
|
18,037
|
|
|
|
22,264
|
|
|
|
16,220
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Periodic Benefit Cost
|
|
$
|
19,016
|
|
|
$
|
20,426
|
|
|
$
|
21,634
|
|
|
$
|
28,184
|
|
|
$
|
30,792
|
|
|
$
|
37,417
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated Other Comprehensive Loss (Pre-Tax) Attributable to
Recognition of Funded Status of Benefit Plans
|
|
|
N/A
|
|
|
|
N/A
|
|
|
$
|
11,256
|
|
|
|
N/A
|
|
|
|
N/A
|
|
|
$
|
778
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted Average Assumptions Used to Determine Net Periodic
Benefit Cost 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
|
%
|
|
|
|
(1) |
|
In fiscal 2008 and 2009, the Company passed amendments, 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 the existing
authoritative guidance 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 and liabilities) is reflected
in the Net Amortization and Deferral for Regulatory Purposes
line item above.
103
NATIONAL
FUEL GAS COMPANY
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
As note above, through 2008, the Company used June
30th as
the measurement date for financial reporting purposes. In 2009,
in accordance with the current authoritative guidance for
defined benefit pension and other postretirement plans, the
Company began measuring the Plans assets and liabilities
for its pension and other post-retirement benefit plans as of
September 30th, its fiscal year end. In making this change and
as permitted by the current authoritative guidance, the Company
recorded fifteen months of pension and post-retirement benefits
expense (for the period from July 1, 2008 through
September 30, 2009) during the fiscal year ended
September 30, 2009. The pension and other post-retirement
benefit costs for the period of July 1, 2008 to
September 30, 2008 amounted to $3.8 million and were
recorded by the Company during the year ended September 30,
2009 as a $3.4 million increase to Other Regulatory Assets
in the Companys Utility and Pipeline and Storage segments
and a $0.4 million ($0.2 million after tax) adjustment
to earnings reinvested in the business. In addition, for the
Companys non-qualified benefit plan, benefit costs of
$1.3 million were recorded by the Company during the year
ended September 30, 2009 as a $0.4 million increase to
Other Regulatory Assets in the Companys Utility segment
and a $0.9 million ($0.6 million after tax) adjustment
to earnings reinvested in the business.
The cumulative amounts recognized in accumulated other
comprehensive income (loss), regulatory assets, and regulatory
liabilities through fiscal 2009, the changes in such amounts
during 2009, as well as the amounts expected to be recognized in
net periodic benefit cost in fiscal 2010 are presented in the
table below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
|
|
|
|
|
|
|
Retirement
|
|
|
Post-Retirement
|
|
|
Non-Qualified
|
|
|
|
Plan
|
|
|
Benefits
|
|
|
Benefit Plan
|
|
|
|
(Thousands)
|
|
|
Amounts Recognized in Accumulated Other Comprehensive Income
(Loss), Regulatory Assets and Regulatory Liabilities(1)
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Actuarial Loss
|
|
$
|
(324,615
|
)
|
|
$
|
(191,360
|
)
|
|
$
|
(24,690
|
)
|
Transition Obligation
|
|
|
|
|
|
|
(2,027
|
)
|
|
|
|
|
Prior Service (Cost) Credit
|
|
|
(4,581
|
)
|
|
|
10,517
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Amount Recognized
|
|
$
|
(329,196
|
)
|
|
$
|
(182,870
|
)
|
|
$
|
(24,690
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Changes to Accumulated Other Comprehensive Income (Loss),
Regulatory Assets and Regulatory Liabilities Recognized During
Fiscal 2009(1)
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase in Net Actuarial Loss
|
|
$
|
(252,978
|
)
|
|
$
|
(138,252
|
)
|
|
$
|
(11,160
|
)
|
Reduction in Transition Obligation
|
|
|
|
|
|
|
9,299
|
|
|
|
|
|
Prior Service (Cost) Credit
|
|
|
914
|
|
|
|
2,956
|
|
|
|
11
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Change
|
|
$
|
(252,064
|
)
|
|
$
|
(125,997
|
)
|
|
$
|
(11,149
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amounts Expected to be Recognized in Net Periodic Benefit
Cost in the Next Fiscal Year(1)
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Actuarial Loss
|
|
$
|
(21,641
|
)
|
|
$
|
(25,882
|
)
|
|
$
|
(2,623
|
)
|
Transition Obligation
|
|
|
|
|
|
|
(541
|
)
|
|
|
|
|
Prior Service (Cost) Credit
|
|
|
(655
|
)
|
|
|
1,710
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Amount Expected to be Recognized
|
|
$
|
(22,296
|
)
|
|
$
|
(24,713
|
)
|
|
$
|
(2,623
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Amounts presented are shown before recognizing deferred taxes. |
In order to adjust the funded status of its pension and other
post-retirement benefit plans at September 30, 2009, the
Company recorded a $318.4 million increase to Other
Regulatory Assets in the Companys Utility and
104
NATIONAL
FUEL GAS COMPANY
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Pipeline and Storage segments and a $70.8 million (pre-tax)
increase to Accumulated Other Comprehensive Loss.
The effect of the discount rate change for the Retirement Plan
in 2009 was to increase the projected benefit obligation of the
Retirement Plan by $102.6 million. 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 2007, there was no change to the
discount rate used to estimate the projected benefit obligation
for the Retirement Plan.
The Company made cash contributions totaling $16.0 million
to the Retirement Plan during the year ended September 30,
2009. The Company expects that the annual contribution to the
Retirement Plan in 2010 will be in the range of
$20.0 million to $30.0 million. It is likely that the
Company will have to fund larger amounts to the Retirement Plan
subsequent to 2010 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: $51.8 million in 2010;
$52.2 million in 2011; $52.6 million in 2012;
$53.3 million in 2013; $54.4 million in 2014; and
$294.3 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 $5.2 million,
$5.0 million and $5.5 million in 2009, 2008 and 2007,
respectively. At September 30, 2007, an $8.0 million
(pre-tax) loss was recognized in accumulated other comprehensive
income (loss) on the Consolidated Balance Sheet upon adoption of
the FASB revised authoritative guidance for defined benefit
pension and other postretirement plans. The accumulated benefit
obligation for this plan was $35.8 million and
$31.8 million at September 30, 2009 and 2008,
respectively. The projected benefit obligation for the plan was
$60.3 million and $47.5 million at September 30,
2009 and 2008, respectively. The actuarial valuations for this
plan were determined based on a discount rate of 5.25%, 6.75%
and 6.25% as of September 30, 2009, 2008 and 2007,
respectively; a rate of compensation increase of 10.0% as of
September 30, 2009, 2008 and 2007; and an expected
long-term rate of return on plan assets of 8.25% at
September 30, 2009, 2008 and 2007.
The effect of the discount rate change in 2009 was to increase
the other post-retirement benefit obligation by
$60.9 million. Effective October 1, 2009, 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 $27.0 million. Other actuarial
experience decreased the other post-retirement benefit
obligation in 2009 by $32.1 million.
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.
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
105
NATIONAL
FUEL GAS COMPANY
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
actuarially equivalent to Medicare Part D. Since the
Company is assumed to continue to provide a prescription drug
benefit to retirees in the point of service and indemnity plans
that is at least actuarially equivalent to Medicare Part D,
the impact of the Act was reflected as of December 8, 2003.
The estimated gross other post-retirement benefit payments and
gross amount of Medicare Part D prescription drug subsidy
receipts are as follows:
|
|
|
|
|
|
|
|
|
|
|
Benefit Payments
|
|
Subsidy Receipts
|
|
2010
|
|
$
|
26,827,000
|
|
|
$
|
(1,933,000
|
)
|
2011
|
|
$
|
28,592,000
|
|
|
$
|
(2,156,000
|
)
|
2012
|
|
$
|
29,970,000
|
|
|
$
|
(2,444,000
|
)
|
2013
|
|
$
|
31,299,000
|
|
|
$
|
(2,758,000
|
)
|
2014
|
|
$
|
32,743,000
|
|
|
$
|
(3,066,000
|
)
|
2015 through 2019
|
|
$
|
185,348,000
|
|
|
$
|
(20,026,000
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009
|
|
2008
|
|
2007
|
|
Rate of Increase for Pre Age 65 Participants
|
|
|
8.0
|
%(1)
|
|
|
9.0
|
%(2)
|
|
|
8.0
|
%(3)
|
Rate of Increase for Post Age 65 Participants
|
|
|
7.0
|
%(1)
|
|
|
7.0
|
%(2)
|
|
|
6.67
|
%(3)
|
Annual Rate of Increase in the Per Capita Cost of Covered
Prescription Drug Benefits
|
|
|
9.0
|
%(1)
|
|
|
10.0
|
%(2)
|
|
|
10.0
|
%(3)
|
Annual Rate of Increase in the Per Capita Medicare Part B
Reimbursement
|
|
|
7.0
|
%(1)
|
|
|
7.0
|
%(2)
|
|
|
7.0
|
%(4)
|
Annual Rate of Increase in the Per Capita Medicare Part D
Subsidy
|
|
|
7.9
|
%(1)
|
|
|
10.0
|
%(2)
|
|
|
10.0
|
%(3)
|
|
|
|
(1) |
|
It was assumed that this rate would gradually decline to 4.5% by
2028. |
|
(2) |
|
It was assumed that this rate would gradually decline to 5.0% by
2018. |
|
(3) |
|
It was assumed that this rate would gradually decline to 5.0% by
2014. |
|
(4) |
|
It was assumed that this rate would gradually decline to 5.0% by
2016. |
The health care cost trend rate assumptions used to calculate
the per capita cost of covered medical care benefits have a
significant effect on the amounts reported. If the health care
cost trend rates were increased by 1% in each year, the other
post-retirement benefit obligation as of October 1, 2009
would increase by $54.5 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 2009
by $3.9 million. If the health care cost trend rates were
decreased by 1% in each year, the other post-retirement benefit
obligation as of October 1, 2009 would decrease by
$46.2 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 2009 by
$3.3 million.
The Company made cash contributions totaling $25.5 million
to the VEBA trusts and 401(h) accounts during the year ended
September 30, 2009. In addition, the Company made direct
payments of $0.2 million to retirees not covered by the
VEBA trusts and 401(h) accounts during the year ended
September 30, 2009. The Company expects that the annual
contribution to the VEBA trusts and 401(h) accounts in 2010 will
be in the range of $25.0 million to $30.0 million.
106
NATIONAL
FUEL GAS COMPANY
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The Companys Retirement Plan weighted average asset
allocations (excluding the 401(h) accounts) at
September 30, 2009, 2008 and 2007 by asset category are as
follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Percentage of Plan
|
|
|
|
Target Allocation
|
|
|
Assets at September 30
|
|
Asset Category
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
Equity Securities
|
|
|
60-75
|
%
|
|
|
66
|
%
|
|
|
67
|
%
|
|
|
70
|
%
|
Fixed Income Securities
|
|
|
20-35
|
%
|
|
|
21
|
%
|
|
|
23
|
%
|
|
|
18
|
%
|
Other
|
|
|
0-15
|
%
|
|
|
13
|
%
|
|
|
10
|
%
|
|
|
12
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
|
|
|
100
|
%
|
|
|
100
|
%
|
|
|
100
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The Companys weighted average asset allocations for its
VEBA trusts and 401(h) accounts at September 30, 2009, 2008
and 2007 by asset category are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Percentage of Plan
|
|
|
|
Target Allocation
|
|
|
Assets at September 30
|
|
Asset Category
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
Equity Securities
|
|
|
85-100
|
%
|
|
|
93
|
%
|
|
|
93
|
%
|
|
|
95
|
%
|
Fixed Income Securities
|
|
|
0-15
|
%
|
|
|
2
|
%
|
|
|
1
|
%
|
|
|
1
|
%
|
Other
|
|
|
0-15
|
%
|
|
|
5
|
%
|
|
|
6
|
%
|
|
|
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 and the
Companys other post-retirement benefits is 5.50% as of
September 30, 2009. The discount rate which is used to
present value the future benefit payment obligations of the
Non-Qualified benefit plan is 5.25% as of September 30,
2009. 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 I
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.
107
NATIONAL
FUEL GAS COMPANY
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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, 2009, 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
$18.7 million to $22.9 million. The minimum estimated
liability of $18.7 million has been recorded on the
Consolidated Balance Sheet at September 30, 2009. 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.
|
|
(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.
The Company has agreed with the NYDEC to remediate another
former manufactured gas plant site located in New York. The
Company has received approval from the NYDEC of a Remedial
Design work plan for this site and has recorded an estimated
minimum liability for remediation of this site of
$15.7 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: $520.2 million in
2010, $101.8 million in 2011, $66.6 million in 2012,
$40.2 million in 2013, $39.8 million in 2014, and
$76.3 million thereafter. Gas prices within the gas
purchase contracts are variable based on NYMEX prices adjusted
for basis. 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: $5.4 million in 2010,
$3.9 million in 2011, $3.3 million in 2012,
$2.4 million in 2013, $2.3 million in 2014, and
$10.5 million thereafter.
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
108
NATIONAL
FUEL GAS COMPANY
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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 J
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 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 the United States, primarily in
Appalachia 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
|
|
|
|
(Thousands)
|
|
|
Operating Revenues
|
|
$
|
50,495
|
|
Operating Expenses
|
|
|
33,306
|
|
|
|
|
|
|
Operating Income
|
|
|
17,189
|
|
Interest Income
|
|
|
1,082
|
|
|
|
|
|
|
Income before Income Taxes
|
|
|
18,271
|
|
Income Tax Expense
|
|
|
2,792
|
|
|
|
|
|
|
Income from Discontinued Operations
|
|
|
15,479
|
|
Gain on Disposal, Net of Taxes of $39,572
|
|
|
120,301
|
|
|
|
|
|
|
Income from Discontinued Operations
|
|
$
|
135,780
|
|
|
|
|
|
|
Note K
Business Segment Information
The Company has four reportable segments: Utility, Pipeline and
Storage, Exploration and Production, and Energy Marketing. The
division 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.
109
NATIONAL
FUEL GAS COMPANY
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The Pipeline and Storage segment operations are regulated by the
FERC for both Supply Corporation and 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. Empires new
facilities (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, were placed into service on
December 10, 2008. 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 and Louisiana. Senecas production is, for the most
part, sold to purchasers located in the vicinity of its wells.
As disclosed in Note J 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. As disclosed in
Note M Acquisition, on July 20, 2009,
Seneca acquired Ivanhoe Energys United States oil and gas
operations for approximately $39.2 million (including cash
acquired). Ivanhoe Energys United States oil and gas
operations were incorporated into the Companys
consolidated financial statements for the period subsequent to
the completion of the acquisition on July 20, 2009.
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 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.
110
NATIONAL
FUEL GAS COMPANY
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended September 30, 2009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Corporate
|
|
|
|
|
|
|
Pipeline
|
|
Exploration
|
|
|
|
Total
|
|
|
|
and
|
|
|
|
|
|
|
and
|
|
and
|
|
Energy
|
|
Reportable
|
|
All
|
|
Intersegment
|
|
Total
|
|
|
Utility
|
|
Storage
|
|
Production
|
|
Marketing
|
|
Segments
|
|
Other
|
|
Eliminations
|
|
Consolidated
|
|
|
(Thousands)
|
|
Revenue from External Customers
|
|
$
|
1,097,550
|
|
|
$
|
137,478
|
|
|
$
|
382,758
|
|
|
$
|
397,763
|
|
|
$
|
2,015,549
|
|
|
$
|
41,409
|
|
|
$
|
894
|
|
|
$
|
2,057,852
|
|
Intersegment Revenues
|
|
$
|
15,474
|
|
|
$
|
81,795
|
|
|
$
|
|
|
|
$
|
558
|
|
|
$
|
97,827
|
|
|
$
|
3,890
|
|
|
$
|
(101,717
|
)
|
|
$
|
|
|
Interest Income
|
|
$
|
2,486
|
|
|
$
|
995
|
|
|
$
|
2,430
|
|
|
$
|
79
|
|
|
$
|
5,990
|
|
|
$
|
583
|
|
|
$
|
(797
|
)
|
|
$
|
5,776
|
|
Interest Expense
|
|
$
|
32,417
|
|
|
$
|
21,580
|
|
|
$
|
33,368
|
|
|
$
|
215
|
|
|
$
|
87,580
|
|
|
$
|
2,471
|
|
|
$
|
(3,135
|
)
|
|
$
|
86,916
|
|
Depreciation, Depletion and Amortization
|
|
$
|
39,675
|
|
|
$
|
35,115
|
|
|
$
|
90,816
|
|
|
$
|
42
|
|
|
$
|
165,648
|
|
|
$
|
7,066
|
|
|
$
|
696
|
|
|
$
|
173,410
|
|
Income Tax Expense (Benefit)
|
|
$
|
37,097
|
|
|
$
|
30,579
|
|
|
$
|
(14,616
|
)
|
|
$
|
4,470
|
|
|
$
|
57,530
|
|
|
$
|
(5,221
|
)
|
|
$
|
(1,189
|
)
|
|
$
|
51,120
|
|
Income from Unconsolidated Subsidiaries
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
3,366
|
|
|
$
|
|
|
|
$
|
3,366
|
|
Significant Non-Cash Item: Impairment of Oil and Gas Producing
Properties
|
|
$
|
|
|
|
$
|
|
|
|
$
|
182,811
|
|
|
$
|
|
|
|
$
|
182,811
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
182,811
|
|
Significant Non-Cash Item: Impairment of Investment in
Partnership
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
1,804
|
(1)
|
|
$
|
|
|
|
$
|
1,804
|
|
Significant Non-Cash Item: Impairment of Landfill Gas Assets
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
4,568
|
(2)
|
|
$
|
|
|
|
$
|
4,568
|
|
Segment Profit: Net Income (Loss)
|
|
$
|
58,664
|
|
|
$
|
47,358
|
|
|
$
|
(10,238
|
)
|
|
$
|
7,166
|
|
|
$
|
102,950
|
|
|
$
|
(2,071
|
)
|
|
$
|
(171
|
)
|
|
$
|
100,708
|
|
Expenditures for Additions to Long-Lived Assets
|
|
$
|
56,178
|
|
|
$
|
50,118
|
|
|
$
|
223,223
|
(3)
|
|
$
|
25
|
|
|
$
|
329,544
|
|
|
$
|
9,723
|
(4)
|
|
$
|
(47
|
)
|
|
$
|
339,220
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
At September 30, 2009
|
|
|
(Thousands)
|
|
Segment Assets
|
|
$
|
2,132,610
|
|
|
$
|
1,046,372
|
|
|
$
|
1,265,678
|
|
|
$
|
52,469
|
|
|
$
|
4,497,129
|
|
|
$
|
210,809
|
|
|
$
|
61,191
|
|
|
$
|
4,769,129
|
|
|
|
|
(1) |
|
Amount represents the impairment in the value of the
Companys 50% investment in ESNE, a partnership that owns
an 80-megawatt, combined cycle, natural gas-fired power plant in
the town of North East, Pennsylvania. |
|
(2) |
|
Amount represents the impairment in the value of certain
long-lived landfill gas site assets due to the loss of a primary
customer at the site and the anticipated shut-down of the site.
The impairment includes a $2.6 million reduction in
intangible assets related to long-term gas purchase contracts
and a $2.0 million reduction in property, plant and
equipment. |
|
(3) |
|
Amount includes the acquisition of Ivanhoe Energys United
States oil and gas operation for $34.9 million, net of cash
acquired, and is discussed in Note M
Acquisition. |
|
(4) |
|
Amount includes a $1.3 million capital contribution made by
NFG Midstream Processing, LLC in the Whitetail Processing Plant. |
111
NATIONAL
FUEL GAS COMPANY
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended September 30, 2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Corporate
|
|
|
|
|
|
|
Pipeline
|
|
Exploration
|
|
|
|
Total
|
|
|
|
and
|
|
|
|
|
|
|
and
|
|
and
|
|
Energy
|
|
Reportable
|
|
All
|
|
Intersegment
|
|
Total
|
|
|
Utility
|
|
Storage
|
|
Production
|
|
Marketing
|
|
Segments
|
|
Other
|
|
Eliminations
|
|
Consolidated
|
|
|
(Thousands)
|
|
Revenue from External Customers
|
|
$
|
1,194,657
|
|
|
$
|
135,052
|
|
|
$
|
466,760
|
|
|
$
|
549,932
|
|
|
$
|
2,346,401
|
|
|
$
|
53,265
|
|
|
$
|
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
|
|
|
$
|
13,923
|
|
|
$
|
1,232
|
|
|
$
|
(4,340
|
)
|
|
$
|
10,815
|
|
Interest Expense
|
|
$
|
27,683
|
|
|
$
|
13,783
|
|
|
$
|
41,645
|
|
|
$
|
175
|
|
|
$
|
83,286
|
|
|
$
|
3,782
|
|
|
$
|
(13,099
|
)
|
|
$
|
73,969
|
|
Depreciation, Depletion and Amortization
|
|
$
|
39,113
|
|
|
$
|
32,871
|
|
|
$
|
92,221
|
|
|
$
|
42
|
|
|
$
|
164,247
|
|
|
$
|
5,687
|
|
|
$
|
689
|
|
|
$
|
170,623
|
|
Income Tax Expense (Benefit)
|
|
$
|
36,303
|
|
|
$
|
34,008
|
|
|
$
|
92,686
|
|
|
$
|
3,180
|
|
|
$
|
166,177
|
|
|
$
|
2,186
|
|
|
$
|
(441
|
)
|
|
$
|
167,922
|
|
Income from Unconsolidated Subsidiaries
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
6,303
|
|
|
$
|
|
|
|
$
|
6,303
|
|
Segment Profit: Net Income (Loss)
|
|
$
|
61,472
|
|
|
$
|
54,148
|
|
|
$
|
146,612
|
|
|
$
|
5,889
|
|
|
$
|
268,121
|
|
|
$
|
5,779
|
|
|
$
|
(5,172
|
)
|
|
$
|
268,728
|
|
Expenditures for Additions to Long-Lived Assets
|
|
$
|
57,457
|
|
|
$
|
165,520
|
|
|
$
|
192,187
|
|
|
$
|
39
|
|
|
$
|
415,203
|
|
|
$
|
1,485
|
|
|
$
|
(2,186
|
)
|
|
$
|
414,502
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
At September 30, 2008
|
|
|
(Thousands)
|
|
Segment Assets
|
|
$
|
1,643,665
|
|
|
$
|
948,984
|
|
|
$
|
1,416,120
|
|
|
$
|
89,527
|
|
|
$
|
4,098,296
|
|
|
$
|
217,874
|
|
|
$
|
(185,983
|
)
|
|
$
|
4,130,187
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended September 30, 2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Corporate
|
|
|
|
|
|
|
Pipeline
|
|
Exploration
|
|
|
|
Total
|
|
|
|
and
|
|
|
|
|
|
|
and
|
|
and
|
|
Energy
|
|
Reportable
|
|
All
|
|
Intersegment
|
|
Total
|
|
|
Utility
|
|
Storage
|
|
Production
|
|
Marketing
|
|
Segments
|
|
Other
|
|
Eliminations
|
|
Consolidated
|
|
|
(Thousands)
|
|
Revenue from External Customers
|
|
$
|
1,106,453
|
|
|
$
|
130,410
|
|
|
$
|
324,037
|
|
|
$
|
413,612
|
|
|
$
|
1,974,512
|
|
|
$
|
64,282
|
|
|
$
|
772
|
|
|
$
|
2,039,566
|
|
Intersegment Revenues
|
|
$
|
14,271
|
|
|
$
|
81,556
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
95,827
|
|
|
$
|
8,726
|
|
|
$
|
(104,553
|
)
|
|
$
|
|
|
Interest Income
|
|
$
|
(2,345
|
)
|
|
$
|
357
|
|
|
$
|
9,905
|
|
|
$
|
682
|
|
|
$
|
8,599
|
|
|
$
|
1,265
|
|
|
$
|
(8,314
|
)
|
|
$
|
1,550
|
|
Interest Expense
|
|
$
|
28,190
|
|
|
$
|
9,623
|
|
|
$
|
51,743
|
|
|
$
|
263
|
|
|
$
|
89,819
|
|
|
$
|
5,952
|
|
|
$
|
(21,296
|
)
|
|
$
|
74,475
|
|
Depreciation, Depletion and Amortization
|
|
$
|
40,541
|
|
|
$
|
32,985
|
|
|
$
|
78,174
|
|
|
$
|
33
|
|
|
$
|
151,733
|
|
|
$
|
5,494
|
|
|
$
|
692
|
|
|
$
|
157,919
|
|
Income Tax Expense
|
|
$
|
31,642
|
|
|
$
|
35,740
|
|
|
$
|
52,421
|
|
|
$
|
5,654
|
|
|
$
|
125,457
|
|
|
$
|
4,465
|
|
|
$
|
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
|
|
|
$
|
189,824
|
|
|
$
|
6,292
|
|
|
$
|
5,559
|
|
|
$
|
201,675
|
|
Expenditures for Additions to Long-Lived Assets from Continuing
Operations
|
|
$
|
54,185
|
|
|
$
|
43,226
|
|
|
$
|
146,687
|
|
|
$
|
76
|
|
|
$
|
244,174
|
|
|
$
|
7,044
|
(1)
|
|
$
|
(319
|
)
|
|
$
|
250,899
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
At September 30, 2007
|
|
|
(Thousands)
|
|
Segment Assets
|
|
$
|
1,565,593
|
|
|
$
|
810,957
|
|
|
$
|
1,326,073
|
|
|
$
|
59,802
|
|
|
$
|
3,762,425
|
|
|
$
|
231,755
|
|
|
$
|
(105,768
|
)
|
|
$
|
3,888,412
|
|
|
|
|
(1) |
|
Amount includes a $3.3 million capital contribution to
Seneca Energy by Horizon Power. |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For The Year Ended September 30
|
|
Geographic Information
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
(Thousands)
|
|
|
Revenues from External Customers(1):
|
|
|
|
|
|
|
|
|
|
|
|
|
United States
|
|
$
|
2,057,852
|
|
|
$
|
2,400,361
|
|
|
$
|
2,039,566
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
112
NATIONAL
FUEL GAS COMPANY
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
At September 30
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
(Thousands)
|
|
|
Long-Lived Assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
United States
|
|
$
|
3,992,159
|
|
|
$
|
3,630,709
|
|
|
$
|
3,334,274
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Revenue is based upon the country in which the sale originates.
This table excludes revenues from Canadian discontinued
operations of $50,495 for September 30, 2007. |
Note L
Investments in Unconsolidated Subsidiaries
The Companys unconsolidated subsidiaries consist of equity
method investments in Seneca Energy, Model City, ESNE and
Whitetail Processing Plant. The Company has 50% interests in
each of the first three entities and a 35% ownership interest in
the Whitetail Processing Plant. 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. Whitetail Processing Plant is
currently under construction with completion expected in the
fall of 2009. Once completed, the plant will extract natural gas
liquids from local production in Pennsylvania.
During the quarter ended December 31, 2008, the Company
recorded a pre-tax impairment of $1.8 million
($1.1 million on an after-tax basis) of its equity
investment in ESNE due to a decline in the fair market value of
ESNE. The impairment was driven by a significant decrease in
run time for the plant given the economic downturn
and the resulting decrease in demand for electric power.
A summary of the Companys investments in unconsolidated
subsidiaries at September 30, 2009 and 2008 is as follows:
|
|
|
|
|
|
|
|
|
|
|
At September 30
|
|
|
|
2009
|
|
|
2008
|
|
|
|
(Thousands)
|
|
|
Seneca Energy
|
|
$
|
10,924
|
|
|
$
|
10,589
|
|
Model City
|
|
|
2,136
|
|
|
|
1,732
|
|
ESNE
|
|
|
1,880
|
|
|
|
3,958
|
|
Whitetail Processing Plant
|
|
|
1,317
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
16,257
|
|
|
$
|
16,279
|
|
|
|
|
|
|
|
|
|
|
Note M
Acquisition
On July 20, 2009, the Companys wholly-owned
subsidiary in the Exploration and Production segment, Seneca,
acquired all of the shares of Ivanhoe Energys United
States oil and gas operations for approximately
$39.2 million in cash (including cash acquired), of which
$2.0 million was held in escrow at September 30, 2009.
In accordance with the purchase agreement, this amount will
remain in escrow for one year from the closing of the
transaction provided there are no pending disputes or actions
regarding obligations and liabilities required to be satisfied
or discharged by Ivanhoe Energy. Ivanhoe Energys United
States oil and gas operations were incorporated into the
Companys consolidated financial statements for the period
subsequent to the completion of the acquisition on July 20,
2009. As of the acquisition date, these assets produced
approximately 645 (595 net) barrels per day of oil in California
and Texas. The purchase also included certain exploration
acreage in California. This acquisition adds to the
Companys existing oil producing assets in the Midway
Sunset Field in California. The acquisition consisted of
approximately $37.1 million in property, plant and
equipment,
113
NATIONAL
FUEL GAS COMPANY
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
$6.2 million of current assets (including $2.0 million
of cash held in escrow), $0.3 million of current
liabilities and $3.8 million of deferred credits. Details
of the acquisition are as follows (all figures in thousands):
|
|
|
|
|
Assets Acquired
|
|
$
|
43,282
|
|
Liabilities Assumed
|
|
|
(4,082
|
)
|
Cash Acquired at Acquisition
|
|
|
(4,267
|
)
|
|
|
|
|
|
Cash Paid, Net of Cash Acquired
|
|
$
|
34,933
|
|
|
|
|
|
|
Note N
Intangible Assets
As a result of the Empire and Toro acquisitions in 2003, the
Company acquired certain intangible assets. 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, 2009
|
|
|
2008
|
|
|
|
Gross Carrying
|
|
|
Accumulated
|
|
|
Net Carrying
|
|
|
Net Carrying
|
|
|
|
Amount
|
|
|
Amortization
|
|
|
Amount
|
|
|
Amount
|
|
|
Intangible Assets Subject to Amortization:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-Term Transportation Contracts
|
|
$
|
4,701
|
|
|
$
|
(2,630
|
)
|
|
$
|
2,071
|
|
|
$
|
2,522
|
|
Long-Term Gas Purchase Contracts
|
|
|
31,864
|
|
|
|
(12,399
|
)
|
|
|
19,465
|
|
|
|
23,652
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
36,565
|
|
|
$
|
(15,029
|
)
|
|
$
|
21,536
|
|
|
$
|
26,174
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Aggregate Amortization Expense:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Year Ended September 30, 2009
|
|
$
|
4,638
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Year Ended September 30, 2008
|
|
$
|
2,662
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Year Ended September 30, 2007
|
|
$
|
2,662
|
|
|
|
|
|
|
|
|
|
|
|
|
|
In September 2009, the Company recorded a pre-tax impairment of
$4.6 million in the value of certain long-lived assets in
the All Other category due to the loss of the primary customer
at one of Toros landfill gas sites and the anticipated
shut-down of the site. The impairment was comprised of a
$2.6 million reduction in intangible assets related to
long-term gas purchase contracts and a $2.0 million
reduction in property, plant and equipment. The
$2.6 million intangible assets impairment was recorded to
Purchased Gas expense and the $2.0 million property, plant
and equipment impairment was recorded to Depreciation, Depletion
and Amortization expense on the Consolidated Statement of
Income. The $2.6 million impairment of the intangible asset
is included in amortization expense for the year ended
September 30, 2009 in the table shown above.
In October 2008, the Company completed the amortization of
intangible assets related to two long-term transportation
contracts. As such, the gross carrying amount of intangible
assets subject to amortization was reduced from
$8.6 million at September 30, 2008 to
$4.7 million at September 30, 2009. Accumulated
amortization was reduced by the same amount. Aside from this
change, the only activity with regard to intangible assets
subject to amortization was amortization expense as shown in the
table above. Amortization expense for the long-term
transportation contracts is estimated to be $0.4 million
annually for 2010, 2011,
114
NATIONAL
FUEL GAS COMPANY
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
2012, 2013 and 2014. Amortization expense for the long-term gas
purchase contracts is estimated to be $1.4 million annually
for 2010, 2011, 2012, 2013 and 2014.
Note O
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.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
|
|
|
|
|
|
|
|
|
|
|
Income
|
|
Earnings per
|
Quarter
|
|
Operating
|
|
Operating
|
|
(Loss) Available for
|
|
Common Share
|
Ended
|
|
Revenues
|
|
Income (Loss)
|
|
Common Stock
|
|
Basic
|
|
Diluted
|
|
|
(Thousands, except per common share amounts)
|
|
2009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
9/30/2009
|
|
$
|
278,933
|
|
|
$
|
64,922
|
|
|
$
|
26,998
|
(1)
|
|
$
|
0.34
|
|
|
$
|
0.33
|
|
6/30/2009
|
|
$
|
367,111
|
|
|
$
|
88,086
|
|
|
$
|
42,904
|
|
|
$
|
0.54
|
|
|
$
|
0.53
|
|
3/31/2009
|
|
$
|
804,645
|
|
|
$
|
138,642
|
|
|
$
|
73,484
|
|
|
$
|
0.92
|
|
|
$
|
0.92
|
|
12/31/2008
|
|
$
|
607,163
|
|
|
$
|
(66,820
|
)
|
|
$
|
(42,678
|
)(2)
|
|
$
|
(0.54
|
)
|
|
$
|
(0.53
|
)
|
2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
9/30/2008
|
|
$
|
397,858
|
|
|
$
|
79,149
|
|
|
$
|
43,266
|
|
|
$
|
0.54
|
|
|
$
|
0.52
|
|
6/30/2008
|
|
$
|
548,382
|
|
|
$
|
110,947
|
|
|
$
|
59,855
|
|
|
$
|
0.74
|
|
|
$
|
0.72
|
|
3/31/2008
|
|
$
|
885,853
|
|
|
$
|
170,020
|
|
|
$
|
95,003
|
(3)
|
|
$
|
1.14
|
|
|
$
|
1.11
|
|
12/31/2007
|
|
$
|
568,268
|
|
|
$
|
126,009
|
|
|
$
|
70,604
|
|
|
$
|
0.84
|
|
|
$
|
0.82
|
|
|
|
|
(1) |
|
Includes a non-cash $4.6 million impairment charge
($2.8 million after tax) associated with landfill gas
assets in the All Other category. |
|
(2) |
|
Includes a non-cash $182.8 million impairment charge
($108.2 million after tax) associated with the Exploration
and Production segments oil and gas producing properties;
a non-cash $1.8 million impairment charge
($1.1 million after tax) associated with an equity
investment in the All Other category and a $2.3 million
gain realized on life insurance policies in the Corporate
category. |
|
(3) |
|
Includes a $0.6 million gain on the sale of a turbine. |
Note P
Market for Common Stock and Related Shareholder Matters
(unaudited)
At September 30, 2009, there were 16,098 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
115
NATIONAL
FUEL GAS COMPANY
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
ranges (based on
intra-day
prices) and quarterly dividends declared for the fiscal years
ended September 30, 2009 and 2008, are shown below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Price Range
|
|
|
Quarter Ended
|
|
High
|
|
Low
|
|
Dividends Declared
|
|
2009
|
|
|
|
|
|
|
|
|
|
|
|
|
9/30/2009
|
|
$
|
48.30
|
|
|
$
|
33.77
|
|
|
$
|
.335
|
|
6/30/2009
|
|
$
|
37.61
|
|
|
$
|
29.83
|
|
|
$
|
.335
|
|
3/31/2009
|
|
$
|
34.34
|
|
|
$
|
26.67
|
|
|
$
|
.325
|
|
12/31/2008
|
|
$
|
41.99
|
|
|
$
|
26.83
|
|
|
$
|
.325
|
|
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
|
|
Note Q
Supplementary Information for Oil and Gas Producing Activities
(unaudited)
The following supplementary information is presented in
accordance with the authoritative guidance regarding 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
|
|
|
|
2009
|
|
|
2008
|
|
|
|
(Thousands)
|
|
|
Proved Properties(1)
|
|
$
|
1,953,720
|
|
|
$
|
1,783,276
|
|
Unproved Properties
|
|
|
70,061
|
|
|
|
23,285
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,023,781
|
|
|
|
1,806,561
|
|
Less Accumulated Depreciation, Depletion and
Amortization
|
|
|
990,284
|
|
|
|
718,166
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
1,033,497
|
|
|
$
|
1,088,395
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Includes asset retirement costs of $65.9 million and
$60.9 million at September 30, 2009 and 2008,
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
116
NATIONAL
FUEL GAS COMPANY
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
capitalized costs being amortized. Following is a summary of
costs excluded from amortization at September 30, 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
as of
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
September 30,
|
|
|
Year Costs Incurred
|
|
|
|
2009
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
Prior
|
|
|
|
(Thousands)
|
|
|
Acquisition Costs
|
|
$
|
63,708
|
|
|
$
|
44,728
|
|
|
$
|
6,342
|
|
|
$
|
2,361
|
|
|
$
|
10,277
|
|
Development Costs
|
|
|
6,353
|
|
|
|
6,353
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
70,061
|
(1)
|
|
$
|
51,081
|
|
|
$
|
6,342
|
|
|
$
|
2,361
|
|
|
$
|
10,277
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Costs related to unproved properties excluded from amortization
includes $52.3 million related to onshore properties and
$17.8 million related to offshore properties at
September 30, 2009. |
Costs
Incurred in Oil and Gas Property Acquisition, Exploration and
Development Activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended September 30
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
(Thousands)
|
|
|
United States
|
|
|
|
|
|
|
|
|
|
|
|
|
Property Acquisition Costs:
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved
|
|
$
|
35,803
|
|
|
$
|
16,474
|
|
|
$
|
2,621
|
|
Unproved
|
|
|
44,528
|
|
|
|
8,449
|
|
|
|
3,210
|
|
Exploration Costs
|
|
|
11,724
|
|
|
|
56,274
|
|
|
|
26,891
|
|
Development Costs
|
|
|
125,109
|
|
|
|
106,975
|
|
|
|
113,206
|
|
Asset Retirement Costs
|
|
|
2,877
|
|
|
|
20,048
|
|
|
|
2,139
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
220,041
|
|
|
|
208,220
|
|
|
|
148,067
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canada Discontinued Operations
|
|
|
|
|
|
|
|
|
|
|
|
|
Property Acquisition Costs:
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved
|
|
|
|
|
|
|
|
|
|
|
(1,404
|
)
|
Unproved
|
|
|
|
|
|
|
|
|
|
|
(1,142
|
)
|
Exploration Costs
|
|
|
|
|
|
|
|
|
|
|
20,134
|
|
Development Costs
|
|
|
|
|
|
|
|
|
|
|
11,414
|
|
Asset Retirement Costs
|
|
|
|
|
|
|
|
|
|
|
167
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
29,169
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
|
|
Property Acquisition Costs:
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved
|
|
|
35,803
|
|
|
|
16,474
|
|
|
|
1,217
|
|
Unproved
|
|
|
44,528
|
|
|
|
8,449
|
|
|
|
2,068
|
|
Exploration Costs
|
|
|
11,724
|
|
|
|
56,274
|
|
|
|
47,025
|
|
Development Costs
|
|
|
125,109
|
|
|
|
106,975
|
|
|
|
124,620
|
|
Asset Retirement Costs
|
|
|
2,877
|
|
|
|
20,048
|
|
|
|
2,306
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
220,041
|
|
|
$
|
208,220
|
|
|
$
|
177,236
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
117
NATIONAL
FUEL GAS COMPANY
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
For the years ended September 30, 2009, 2008 and 2007, the
Company spent $24.2 million, $25.4 million and
$30.3 million, respectively, developing proved undeveloped
reserves.
Results
of Operations for Producing Activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended September 30
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
(Thousands, except per Mcfe amounts)
|
|
|
United States
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas (includes revenues from sales to affiliates of $239,
$443 and $325, respectively)
|
|
$
|
106,815
|
|
|
$
|
216,623
|
|
|
$
|
135,399
|
|
Oil, Condensate and Other Liquids
|
|
|
174,356
|
|
|
|
305,887
|
|
|
|
189,539
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Operating Revenues(1)
|
|
|
281,171
|
|
|
|
522,510
|
|
|
|
324,938
|
|
Production/Lifting Costs
|
|
|
62,614
|
|
|
|
66,685
|
|
|
|
48,410
|
|
Accretion Expense
|
|
|
5,437
|
|
|
|
4,056
|
|
|
|
3,704
|
|
Depreciation, Depletion and Amortization ($2.10, $2.23 and $1.97
per Mcfe of production)
|
|
|
89,307
|
|
|
|
91,093
|
|
|
|
77,452
|
|
Impairment of Oil and Gas Producing Properties(2)
|
|
|
182,811
|
|
|
|
|
|
|
|
|
|
Income Tax Expense (Benefit)
|
|
|
(27,055
|
)
|
|
|
144,922
|
|
|
|
78,928
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Results of Operations for Producing Activities (excluding
corporate overheads and interest charges)
|
|
|
(31,943
|
)
|
|
|
215,754
|
|
|
|
116,444
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canada Discontinued Operations
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas
|
|
|
|
|
|
|
|
|
|
|
39,114
|
|
Oil, Condensate and Other Liquids
|
|
|
|
|
|
|
|
|
|
|
10,313
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Operating Revenues(1)
|
|
|
|
|
|
|
|
|
|
|
49,427
|
|
Production/Lifting Costs
|
|
|
|
|
|
|
|
|
|
|
14,846
|
|
Accretion Expense
|
|
|
|
|
|
|
|
|
|
|
249
|
|
Depreciation, Depletion and Amortization ($1.67 per Mcfe of
production for 2007)
|
|
|
|
|
|
|
|
|
|
|
12,787
|
|
Income Tax Expense
|
|
|
|
|
|
|
|
|
|
|
3,703
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Results of Operations for Producing Activities (excluding
corporate overheads and interest charges)
|
|
|
|
|
|
|
|
|
|
|
17,842
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
118
NATIONAL
FUEL GAS COMPANY
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended September 30
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
(Thousands, except per Mcfe amounts)
|
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas (includes revenues from sales to affiliates of $239,
$443 and $325, respectively)
|
|
|
106,815
|
|
|
|
216,623
|
|
|
|
174,513
|
|
Oil, Condensate and Other Liquids
|
|
|
174,356
|
|
|
|
305,887
|
|
|
|
199,852
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Operating Revenues(1)
|
|
|
281,171
|
|
|
|
522,510
|
|
|
|
374,365
|
|
Production/Lifting Costs
|
|
|
62,614
|
|
|
|
66,685
|
|
|
|
63,256
|
|
Accretion Expense
|
|
|
5,437
|
|
|
|
4,056
|
|
|
|
3,953
|
|
Depreciation, Depletion and Amortization ($2.10, $2.23 and $1.92
per Mcfe of production)
|
|
|
89,307
|
|
|
|
91,093
|
|
|
|
90,239
|
|
Impairment of Oil and Gas Producing Properties(2)
|
|
|
182,811
|
|
|
|
|
|
|
|
|
|
Income Tax Expense
|
|
|
(27,055
|
)
|
|
|
144,922
|
|
|
|
82,631
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Results of Operations for Producing Activities (excluding
corporate overheads and interest charges)
|
|
$
|
(31,943
|
)
|
|
$
|
215,754
|
|
|
$
|
134,286
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Exclusive of hedging gains and losses. See further discussion in
Note G Financial Instruments. |
|
(2) |
|
See discussion of impairment in Note A Summary
of Significant Accounting Policies. |
119
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, 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
|
|
Extensions and Discoveries
|
|
|
6,698
|
|
|
|
3,282
|
|
|
|
49,249
|
|
|
|
59,229
|
|
|
|
|
|
|
|
59,229
|
|
Revisions of Previous Estimates
|
|
|
9,407
|
|
|
|
488
|
|
|
|
(19,484
|
)
|
|
|
(9,589
|
)
|
|
|
|
|
|
|
(9,589
|
)(1)
|
Production
|
|
|
(9,886
|
)
|
|
|
(4,063
|
)
|
|
|
(8,335
|
)
|
|
|
(22,284
|
)
|
|
|
|
|
|
|
(22,284
|
)
|
Purchases of Minerals in Place
|
|
|
|
|
|
|
392
|
|
|
|
|
|
|
|
392
|
|
|
|
|
|
|
|
392
|
|
Sales of Minerals in Place
|
|
|
(4,693
|
)
|
|
|
|
|
|
|
|
|
|
|
(4,693
|
)
|
|
|
|
|
|
|
(4,693
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
September 30, 2009
|
|
|
26,167
|
|
|
|
72,959
|
|
|
|
149,828
|
|
|
|
248,954
|
|
|
|
|
|
|
|
248,954
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved Developed Reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
|
|
September 30, 2009
|
|
|
18,051
|
|
|
|
67,603
|
|
|
|
120,579
|
|
|
|
206,233
|
|
|
|
|
|
|
|
206,233
|
|
|
|
|
(1) |
|
During 2009, the Company made a downward revision of its proved
developed and undeveloped reserves amounting to 9,589 MMcf. This
was primarily attributable to a 19,484 MMcf reduction in the
Appalachian |
120
NATIONAL
FUEL GAS COMPANY
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
region offset by a 9,407 MMcf increase in the Gulf Coast region.
The reduction in the Appalachian region was mainly due to
declining natural gas prices, which made certain reserves
uneconomical. The improvement in the Gulf Coast region was due
to improved performance of Gulf Coast properties. |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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, 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
|
|
Extensions and Discoveries
|
|
|
302
|
|
|
|
896
|
|
|
|
15
|
|
|
|
1,213
|
|
|
|
|
|
|
|
1,213
|
|
Revisions of Previous Estimates
|
|
|
447
|
|
|
|
43
|
|
|
|
(41
|
)
|
|
|
449
|
|
|
|
|
|
|
|
449
|
|
Production
|
|
|
(640
|
)
|
|
|
(2,674
|
)
|
|
|
(59
|
)
|
|
|
(3,373
|
)
|
|
|
|
|
|
|
(3,373
|
)
|
Purchases of Minerals in Place
|
|
|
|
|
|
|
2,115
|
|
|
|
|
|
|
|
2,115
|
|
|
|
|
|
|
|
2,115
|
|
Sales of Minerals in Place
|
|
|
(15
|
)
|
|
|
|
|
|
|
|
|
|
|
(15
|
)
|
|
|
|
|
|
|
(15
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
September 30, 2009
|
|
|
1,452
|
|
|
|
44,824
|
|
|
|
311
|
|
|
|
46,587
|
|
|
|
|
|
|
|
46,587
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved Developed Reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
|
|
September 30, 2009
|
|
|
1,194
|
|
|
|
37,711
|
|
|
|
285
|
|
|
|
39,190
|
|
|
|
|
|
|
|
39,190
|
|
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.
121
NATIONAL
FUEL GAS COMPANY
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The standardized measure is intended instead to provide a means
for comparing the value of the Companys proved reserves at
a given time with those of other oil- and gas-producing
companies than is provided by a simple comparison of raw proved
reserve quantities.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended September 30
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
(Thousands)
|
|
|
United States
|
|
|
|
|
|
|
|
|
|
|
|
|
Future Cash Inflows
|
|
$
|
3,972,026
|
|
|
$
|
5,845,214
|
|
|
$
|
4,879,496
|
|
Less:
|
|
|
|
|
|
|
|
|
|
|
|
|
Future Production Costs
|
|
|
1,010,851
|
|
|
|
1,231,705
|
|
|
|
872,536
|
|
Future Development Costs
|
|
|
312,717
|
|
|
|
265,515
|
|
|
|
229,987
|
|
Future Income Tax Expense at Applicable Statutory Rate
|
|
|
916,466
|
|
|
|
1,645,351
|
|
|
|
1,423,707
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Future Net Cash Flows
|
|
|
1,731,992
|
|
|
|
2,702,643
|
|
|
|
2,353,266
|
|
Less:
|
|
|
|
|
|
|
|
|
|
|
|
|
10% Annual Discount for Estimated Timing of Cash Flows
|
|
|
856,015
|
|
|
|
1,434,799
|
|
|
|
1,292,804
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Standardized Measure of Discounted Future Net Cash Flows
|
|
$
|
875,977
|
|
|
$
|
1,267,844
|
|
|
$
|
1,060,462
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The principal sources of change in the standardized measure of
discounted future net cash flows were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended September 30
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
(Thousands)
|
|
|
United States
|
|
|
|
|
|
|
|
|
|
|
|
|
Standardized Measure of Discounted Future
Net Cash Flows at Beginning of Year
|
|
$
|
1,267,844
|
|
|
$
|
1,060,462
|
|
|
$
|
861,659
|
|
Sales, Net of Production Costs
|
|
|
(218,557
|
)
|
|
|
(455,825
|
)
|
|
|
(276,529
|
)
|
Net Changes in Prices, Net of Production Costs
|
|
|
(699,217
|
)
|
|
|
509,705
|
|
|
|
539,895
|
|
Purchases of Minerals in Place
|
|
|
38,902
|
|
|
|
67,768
|
|
|
|
|
|
Sales of Minerals in Place
|
|
|
(20,141
|
)
|
|
|
(31,642
|
)
|
|
|
484
|
|
Extensions and Discoveries
|
|
|
66,002
|
|
|
|
143,394
|
|
|
|
98,751
|
|
Changes in Estimated Future Development Costs
|
|
|
(22,392
|
)
|
|
|
(100,684
|
)
|
|
|
(83,199
|
)
|
Previously Estimated Development Costs Incurred
|
|
|
53,285
|
|
|
|
65,156
|
|
|
|
58,710
|
|
Net Change in Income Taxes at Applicable Statutory Rate
|
|
|
331,251
|
|
|
|
(119,585
|
)
|
|
|
(174,920
|
)
|
Revisions of Previous Quantity Estimates
|
|
|
(27,864
|
)
|
|
|
(3,936
|
)
|
|
|
(140,203
|
)
|
Accretion of Discount and Other
|
|
|
106,864
|
|
|
|
133,031
|
|
|
|
175,814
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Standardized Measure of Discounted Future Net Cash Flows at End
of Year
|
|
|
875,977
|
|
|
|
1,267,844
|
|
|
|
1,060,462
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
122
NATIONAL
FUEL GAS COMPANY
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended September 30
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
(Thousands)
|
|
|
Canada Discontinued Operations
|
|
|
|
|
|
|
|
|
|
|
|
|
Standardized Measure of Discounted Future Net Cash Flows at
Beginning of Year
|
|
|
|
|
|
|
|
|
|
|
74,249
|
|
Sales, Net of Production Costs
|
|
|
|
|
|
|
|
|
|
|
(34,581
|
)
|
Net Changes in Prices, Net of Production Costs
|
|
|
|
|
|
|
|
|
|
|
35,628
|
|
Sales of Minerals in Place
|
|
|
|
|
|
|
|
|
|
|
(151,236
|
)
|
Extensions and Discoveries
|
|
|
|
|
|
|
|
|
|
|
6,908
|
|
Changes in Estimated Future Development Costs
|
|
|
|
|
|
|
|
|
|
|
5,722
|
|
Previously Estimated Development Costs Incurred
|
|
|
|
|
|
|
|
|
|
|
5,798
|
|
Net Change in Income Taxes at Applicable Statutory Rate
|
|
|
|
|
|
|
|
|
|
|
(10,075
|
)
|
Revisions of Previous Quantity Estimates
|
|
|
|
|
|
|
|
|
|
|
34,998
|
|
Accretion of Discount and Other
|
|
|
|
|
|
|
|
|
|
|
32,589
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Standardized Measure of Discounted Future Net Cash Flows at End
of Year
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
|
|
Standardized Measure of Discounted Future Net Cash Flows at
Beginning of Year
|
|
|
1,267,844
|
|
|
|
1,060,462
|
|
|
|
935,908
|
|
Sales, Net of Production Costs
|
|
|
(218,557
|
)
|
|
|
(455,825
|
)
|
|
|
(311,110
|
)
|
Net Changes in Prices, Net of Production Costs
|
|
|
(699,217
|
)
|
|
|
509,705
|
|
|
|
575,523
|
|
Purchases of Minerals in Place
|
|
|
38,902
|
|
|
|
67,768
|
|
|
|
|
|
Sales of Minerals in Place
|
|
|
(20,141
|
)
|
|
|
(31,642
|
)
|
|
|
(150,752
|
)
|
Extensions and Discoveries
|
|
|
66,002
|
|
|
|
143,394
|
|
|
|
105,659
|
|
Changes in Estimated Future Development Costs
|
|
|
(22,392
|
)
|
|
|
(100,684
|
)
|
|
|
(77,477
|
)
|
Previously Estimated Development Costs Incurred
|
|
|
53,285
|
|
|
|
65,156
|
|
|
|
64,508
|
|
Net Change in Income Taxes at Applicable Statutory Rate
|
|
|
331,251
|
|
|
|
(119,585
|
)
|
|
|
(184,995
|
)
|
Revisions of Previous Quantity Estimates
|
|
|
(27,864
|
)
|
|
|
(3,936
|
)
|
|
|
(105,205
|
)
|
Accretion of Discount and Other
|
|
|
106,864
|
|
|
|
133,031
|
|
|
|
208,403
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Standardized Measure of Discounted Future Net Cash Flows at End
of Year
|
|
$
|
875,977
|
|
|
$
|
1,267,844
|
|
|
$
|
1,060,462
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Note R
Subsequent Events
In accordance with the authoritative guidance for subsequent
events, the Company has evaluated subsequent events through
November 25, 2009, which represents the filing date of this
Form 10-K
with the SEC, in order to ensure that this
Form 10-K
includes appropriate disclosure of events both recognized in the
financial statements as of September 30, 2009, and events
which occurred subsequent to September 30, 2009 but were
123
NATIONAL
FUEL GAS COMPANY
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
not recognized in the financial statements. As of
November 25, 2009, there were no subsequent events which
required recognition or disclosure.
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|
|
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|
|
|
|
|
|
Additions
|
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|
|
|
|
|
|
|
|
|
|
|
Balance
|
|
|
Charged
|
|
|
Additions
|
|
|
|
|
|
Balance
|
|
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at
|
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|
to
|
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Charged
|
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|
|
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at
|
|
|
|
Beginning
|
|
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Costs
|
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to
|
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|
|
|
End
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of
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and
|
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Other
|
|
|
|
|
|
of
|
|
Description
|
|
Period
|
|
|
Expenses
|
|
|
Accounts(1)
|
|
|
Deductions(2)
|
|
|
Period
|
|
|
|
(Thousands)
|
|
|
Year Ended September 30, 2009
|
|
|
|
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|
|
|
|
|
|
|
|
|
|
|
|
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Allowance for Uncollectible Accounts
|
|
$
|
33,117
|
|
|
$
|
31,464
|
|
|
$
|
2,751
|
|
|
$
|
28,998
|
|
|
$
|
38,334
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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|
|
|
|
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|
Year Ended September 30, 2008
|
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allowance for Uncollectible Accounts
|
|
$
|
28,654
|
|
|
$
|
27,274
|
|
|
$
|
2,734
|
|
|
$
|
25,545
|
|
|
$
|
33,117
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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|
Year Ended September 30, 2007
|
|
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allowance for Uncollectible Accounts
|
|
$
|
31,427
|
|
|
$
|
27,652
|
|
|
$
|
1,414
|
|
|
$
|
31,839
|
|
|
$
|
28,654
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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(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. |
124
|
|
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, 2009.
Managements
Annual 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, 2009. 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, 2009.
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 an attestation report on the effectiveness of the
Companys internal control over financial reporting as of
September 30, 2009. 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, 2009 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 2010
125
Annual Meeting of Stockholders will be filed with the SEC not
later than 120 days after September 30, 2009. The
information concerning directors will be set forth in the
definitive Proxy Statement under the headings entitled
Nominees for Election as Directors for Three-Year Terms to
Expire in 2013, Directors Whose Terms Expire in
2012, Directors Whose Terms Expire in 2011,
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 2010
Annual Meeting of Stockholders will be filed with the SEC not
later than 120 days after September 30, 2009. The
information concerning executive compensation will be 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 2010
Annual Meeting of Stockholders will be filed with the SEC not
later than 120 days after September 30, 2009. The
equity compensation plan information will be 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 2010
Annual Meeting of Stockholders will be filed with the SEC not
later than 120 days after September 30, 2009. The
information concerning security ownership of certain beneficial
owners will be 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 2010
Annual Meeting of Stockholders will be filed with the SEC not
later than 120 days after September 30, 2009. The
information concerning security ownership of
126
management will be 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 2010
Annual Meeting of Stockholders will be filed with the SEC not
later than 120 days after September 30, 2009. The
information regarding certain relationships and related
transactions will be 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 2010
Annual Meeting of Stockholders will be filed with the SEC not
later than 120 days after September 30, 2009. The
information concerning principal accountant fees and services
will be 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)
|
127
|
|
|
|
|
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)
|
|
|
|
|
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)
|
|
|
|
|
Officers Certificate establishing 8.75% Notes due
2019, dated April 6, 2009 (Exhibit 4.4,
Form 8-K
dated April 6, 2009 in File
No. 1-3880)
|
|
|
|
|
Amended and Restated Rights Agreement, dated as of
December 4, 2008, between the Company and The Bank of New
York, as rights agent (Exhibit 4.1,
Form 8-K
dated December 4, 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)
|
|
|
|
|
Agreement to Extend Duration of Director Services Agreement,
dated June 1, 2009, between the Company and Philip C.
Ackerman (Exhibit 10.1,
Form 10-Q
for the quarterly period ended June 30, 2009 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)
|
|
|
|
|
Management Contracts and Compensatory Plans and Arrangements:
|
128
|
|
|
|
|
Exhibit
|
|
Description of
|
Number
|
|
Exhibits
|
|
|
|
|
|
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
(Exhibit 10.1,
Form 10-K
for the fiscal year ended September 30, 2008 in File
No. 1-3880)
|
|
|
|
|
Form of Amended and Restated Employment Continuation and
Noncompetition Agreement among the Company, Seneca Resources
Corporation and Matthew D. Cabell (Exhibit 10.2,
Form 10-K
for the fiscal year ended September 30, 2008 in File
No. 1-3880)
|
|
|
|
|
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)
|
|
10
|
.1
|
|
Description of September 17, 2009 restricted stock award
|
|
10
|
.2
|
|
Description of post-employment medical and prescription drug
benefits
|
|
|
|
|
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)
|
|
|
|
|
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 December 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)
|
|
|
|
|
Amended and Restated National Fuel Gas Company 2007 Annual At
Risk Compensation Incentive Program (Exhibit 10.3,
Form 10-K
for the fiscal year ended September 30, 2008 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)
|
|
|
|
|
Description of performance goals for certain executive officers
under the Amended and Restated National Fuel Gas Company 2007
Annual At Risk Compensation Incentive Program
(Exhibit 10.3,
Form 10-Q
for the quarterly period ended December 31, 2008 in File
No. 1-3880)
|
|
|
|
|
National Fuel Gas Company Executive Annual Cash Incentive
Program (Exhibit 10.4,
Form 10-K
for the fiscal year ended September 30, 2008 in File
No. 1-3880)
|
|
|
|
|
Description of performance goals for an executive officer under
the Companys Executive Annual Cash Incentive Program
(Exhibit 10.3,
Form 10-Q
for the quarterly period ended December 31, 2008 in File
No. 1-3880)
|
|
|
|
|
Administrative Rules of the Compensation Committee of the Board
of Directors of National Fuel Gas Company, as amended and
restated effective 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)
|
129
|
|
|
|
|
Exhibit
|
|
Description of
|
Number
|
|
Exhibits
|
|
|
|
|
|
Amendment to National Fuel Gas Company Deferred Compensation
Plan, dated September 27, 1995 (Exhibit 10.9,
Form 10-K
for fiscal year ended September 30, 1995 in File
No. 1-3880)
|
|
|
|
|
Amendment to National Fuel Gas Company Deferred Compensation
Plan, dated September 19, 1996 (Exhibit 10.10,
Form 10-K
for fiscal year ended September 30, 1996 in File
No. 1-3880)
|
|
|
|
|
National Fuel Gas Company Deferred Compensation Plan, as amended
and restated through March 20, 1997 (Exhibit 10.3,
Form 10-K
for fiscal year ended September 30, 1997 in File
No. 1-3880)
|
|
|
|
|
Amendment to National Fuel Gas Company Deferred Compensation
Plan, dated June 16, 1997 (Exhibit 10.4,
Form 10-K
for fiscal year ended September 30, 1997 in File
No. 1-3880)
|
|
|
|
|
Amendment No. 2 to the National Fuel Gas Company Deferred
Compensation Plan, dated March 13, 1998 (Exhibit 10.1,
Form 10-K
for fiscal year ended September 30, 1998 in File
No. 1-3880)
|
|
|
|
|
Amendment to the National Fuel Gas Company Deferred Compensation
Plan, dated February 18, 1999 (Exhibit 10.1,
Form 10-Q
for the quarterly period ended March 31, 1999 in File
No. 1-3880)
|
|
|
|
|
Amendment to National Fuel Gas Company Deferred Compensation
Plan, dated June 15, 2001 (Exhibit 10.3,
Form 10-K
for fiscal year ended September 30, 2001 in File
No. 1-3880)
|
|
|
|
|
Amendment to the National Fuel Gas Company Deferred Compensation
Plan, dated October 21, 2005 (Exhibit 10.5,
Form 10-K
for fiscal year ended September 30, 2005 in File
No. 1-3880)
|
|
|
|
|
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)
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|
|
|
|
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)
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|
|
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|
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)
|
|
|
|
|
Life Insurance Premium Agreement, dated September 17, 2009,
between the Company and David F. Smith (Exhibit 10.1,
Form 8-K
dated September 23, 2009 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)
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130
|
|
|
|
|
Exhibit
|
|
Description of
|
Number
|
|
Exhibits
|
|
|
|
|
|
Amendments to National Fuel Gas Company and Participating
Subsidiaries Executive Retirement Plan, dated September 18,
1997 (Exhibit 10.9,
Form 10-K
for fiscal year ended September 30, 1997 in File
No. 1-3880)
|
|
|
|
|
Amendments to National Fuel Gas Company and Participating
Subsidiaries Executive Retirement Plan, dated December 10,
1998 (Exhibit 10.2,
Form 10-Q
for the quarterly period ended December 31, 1998 in File
No. 1-3880)
|
|
|
|
|
Amendments to National Fuel Gas Company and Participating
Subsidiaries Executive Retirement Plan, effective
September 16, 1999 (Exhibit 10.15,
Form 10-K
for fiscal year ended September 30, 1999 in File
No. 1-3880)
|
|
|
|
|
Amendment to National Fuel Gas Company and Participating
Subsidiaries Executive Retirement Plan, effective
September 5, 2001 (Exhibit 10.4,
Form 10-K/A
for fiscal year ended September 30, 2001, in File
No. 1-3880)
|
|
|
|
|
National Fuel Gas Company and Participating Subsidiaries
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)
|
|
|
|
|
National Fuel Gas Company and Participating Subsidiaries
Executive Retirement Plan, Amended and Restated as of
September 24, 2008 (Exhibit 10.5,
Form 10-K
for the fiscal year ended September 30, 2008 in File
No. 1-3880)
|
|
|
|
|
National Fuel Gas Company and Participating Subsidiaries 1996
Executive Retirement Plan Trust Agreement (II), dated
May 10, 1996 (Exhibit 10.13,
Form 10-K
for fiscal year ended September 30, 1996 in File
No. 1-3880)
|
|
|
|
|
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)
|
|
|
|
|
National Fuel Gas Company 2009 Non-Employee Director Equity
Compensation Plan (Exhibit 10.1,
Form 10-Q
for the quarterly period ended March 31, 2009 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 10.1,
Form 10-Q
for the quarterly period ended March 31, 2008 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 December 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)
|
131
|
|
|
|
|
Exhibit
|
|
Description of
|
Number
|
|
Exhibits
|
|
|
12
|
|
|
Statements regarding Computation of Ratios: Ratio of Earnings to
Fixed Charges for the fiscal years ended September 30, 2005
through 2009
|
|
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
|
|
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
|
132
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 25, 2009
Pursuant to the requirements of the Securities Exchange Act of
1934, this report has been signed below by the following persons
on behalf of the registrant and in the capacities and on the
dates indicated.
|
|
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|
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|
|
Signature
|
|
Title
|
|
|
|
|
|
|
|
|
/s/ P.
C. Ackerman
P.
C. Ackerman
|
|
Chairman of the Board and Director
|
|
Date: November 25, 2009
|
|
|
|
|
|
R.
T. Brady
|
|
Director
|
|
Date:
|
|
|
|
|
|
/s/ R.
D. Cash
R.
D. Cash
|
|
Director
|
|
Date: November 25, 2009
|
|
|
|
|
|
/s/ S.
E. Ewing
S.
E. Ewing
|
|
Director
|
|
Date: November 25, 2009
|
|
|
|
|
|
/s/ R.
E. Kidder
R.
E. Kidder
|
|
Director
|
|
Date: November 25, 2009
|
|
|
|
|
|
/s/ C.
G. Matthews
C.
G. Matthews
|
|
Director
|
|
Date: November 25, 2009
|
|
|
|
|
|
/s/ G.
L. Mazanec
G.
L. Mazanec
|
|
Director
|
|
Date: November 25, 2009
|
|
|
|
|
|
/s/ R.
G. Reiten
R.
G. Reiten
|
|
Director
|
|
Date: November 25, 2009
|
|
|
|
|
|
/s/ F.
V. Salerno
F.
V. Salerno
|
|
Director
|
|
Date: November 25, 2009
|
|
|
|
|
|
/s/ D.
F. Smith
D.
F. Smith
|
|
President, Chief Executive
Officer and Director
|
|
Date: November 25, 2009
|
133
|
|
|
|
|
|
|
Signature
|
|
Title
|
|
|
|
|
|
|
|
|
/s/ R.
J. Tanski
R.
J. Tanski
|
|
Treasurer and Principal
Financial Officer
|
|
Date: November 25, 2009
|
|
|
|
|
|
/s/ K.
M. Camiolo
K.
M. Camiolo
|
|
Controller and Principal
Accounting Officer
|
|
Date: November 25, 2009
|
134