e10vq
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
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QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the quarterly period ended June 30, 2010
OR
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o |
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the transition period from to
Commission File Number 1-3880
NATIONAL FUEL GAS COMPANY
(Exact name of registrant as specified in its charter)
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New Jersey
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13-1086010 |
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(State or other jurisdiction of
incorporation or organization)
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(I.R.S. Employer
Identification No.) |
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6363 Main Street |
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Williamsville, New York
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14221 |
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(Address of principal executive offices)
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(Zip Code) |
(716) 857-7000
(Registrants
telephone number, including area code)
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 þ NO o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer,
or a non-accelerated filer, or a smaller reporting company. See 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) |
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Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the
Exchange Act). YES o NO þ
Indicate the number of shares outstanding of each of the issuers classes of common stock, as of
the latest practicable date:
Common stock, $1 par value, outstanding at July 31, 2010: 81,970,322 shares.
GLOSSARY OF TERMS
Frequently used abbreviations, acronyms, or terms used in this report:
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National Fuel Gas Companies |
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Company
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The Registrant, the Registrant and its subsidiaries or the Registrants
subsidiaries as appropriate in the context of the disclosure |
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Distribution Corporation
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National Fuel Gas Distribution Corporation |
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Empire
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Empire Pipeline, Inc. |
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ESNE
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Energy Systems North East, LLC |
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Highland
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Highland Forest Resources, Inc. |
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Horizon
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Horizon Energy Development, Inc. |
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Horizon LFG
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Horizon LFG, Inc. |
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Horizon Power
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Horizon Power, Inc. |
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Midstream Corporation
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National Fuel Gas Midstream Corporation |
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Model City
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Model City Energy, LLC |
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National Fuel
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National Fuel Gas Company |
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NFR
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National Fuel Resources, Inc. |
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Registrant
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National Fuel Gas Company |
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Seneca
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Seneca Resources Corporation |
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Seneca Energy
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Seneca Energy II, LLC |
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Supply Corporation
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National Fuel Gas Supply Corporation |
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Regulatory Agencies |
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EPA
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United States Environmental Protection Agency |
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FASB
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Financial Accounting Standards Board |
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FERC
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Federal Energy Regulatory Commission |
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NYDEC
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New York State Department of Environmental Conservation |
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NYPSC
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State of New York Public Service Commission |
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PaPUC
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Pennsylvania Public Utility Commission |
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SEC
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Securities and Exchange Commission |
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Other |
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2009 Form 10-K
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The Companys Annual Report on Form 10-K for the year ended
September 30, 2009 |
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Bbl
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Barrel (of oil) |
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Bcf
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Billion cubic feet (of natural gas) |
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Board foot
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A measure of lumber and/or timber equal to 12 inches in length by 12
inches in width by one inch in thickness. |
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Btu
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British thermal unit; the amount of heat needed to raise the temperature
of one pound of water one degree Fahrenheit. |
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Capital expenditure
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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. |
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Degree day
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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. |
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Derivative
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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. |
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Development costs
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Costs incurred to obtain access to proved reserves and to provide
facilities for extracting, treating, gathering and storing the oil and gas. |
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Dth
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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. |
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Exchange Act
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Securities Exchange Act of 1934, as amended |
-2-
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GLOSSARY OF TERMS (Cont.) |
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Expenditures for long-lived assets
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Includes capital expenditures, stock acquisitions and/or investments in
partnerships. |
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Exploration costs
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Costs incurred in identifying areas that may warrant examination, as well
as costs incurred in examining specific areas, including drilling
exploratory wells. |
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Firm transportation and/or storage
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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. |
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GAAP
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Accounting principles generally accepted in the United States of America |
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Goodwill
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An intangible asset representing the difference between the fair value of
a company and the price at which a company is purchased. |
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Hedging
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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. |
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Hub
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Location where pipelines intersect enabling the trading, transportation,
storage, exchange, lending and borrowing of natural gas. |
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Interruptible transportation and/or storage
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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. |
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LIBOR
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London Interbank Offered Rate |
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LIFO
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Last-in, first-out |
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Mbbl
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Thousand barrels (of oil) |
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Mcf
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Thousand cubic feet (of natural gas) |
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MD&A
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Managements Discussion and Analysis of Financial Condition and
Results of Operations |
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MDth
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Thousand decatherms (of natural gas) |
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MMBtu
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Million British thermal units |
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MMcf
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Million cubic feet (of natural gas) |
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NGA
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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. |
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NYMEX
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New York Mercantile Exchange. An exchange which maintains a futures
market for crude oil and natural gas. |
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Open Season
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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. |
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Precedent Agreement
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An agreement between a pipeline company and a potential customer to
sign a service agreement after specified events (called conditions
precedent) happen, usually within a specified time. |
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Proved developed reserves
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Reserves that can be expected to be recovered through existing wells
with existing equipment and operating methods. |
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Proved undeveloped reserves
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Reserves that are expected to be recovered from new wells on undrilled
acreage, or from existing wells where a relatively major
expenditure is
required to make these reserves productive. |
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Reserves
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The unproduced but recoverable oil and/or gas in place in a formation
which has been proven by production. |
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Restructuring
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Generally referring to partial deregulation of the pipeline and/or utility
industries by a statutory or regulatory process. Restructuring of
federally regulated natural gas pipelines has 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. |
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S&P
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Standard & Poors Ratings Service |
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SAR
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Stock appreciation right |
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Stock acquisitions
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Investments in corporations. |
-3-
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GLOSSARY OF TERMS (Concl.) |
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Unbundled service
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A service that has been separated from other services, with rates
charged that reflect only the cost of the separated service. |
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VEBA
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Voluntary Employees Beneficiary Association |
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WNC
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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. |
-4-
INDEX
The Company has nothing to report under this item.
Reference to the Company in this report means the Registrant or the Registrant and its
subsidiaries collectively, as appropriate in the context of the disclosure. All references to a
certain year in this report are to the Companys fiscal year ended September 30 of that year,
unless otherwise noted.
This Form 10-Q contains forward-looking statements within the meaning of Section 21E of the
Securities Exchange Act of 1934. Forward-looking statements should be read with the cautionary
statements and important factors included in this Form 10-Q at Item 2 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.
.
-5-
Part I. Financial Information
Item 1. Financial Statements
National Fuel Gas Company
Consolidated Statements of Income and Earnings
Reinvested in the Business
(Unaudited)
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Three Months Ended |
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June 30, |
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(Thousands of Dollars, Except Per Common Share Amounts) |
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2010 |
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2009 |
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INCOME |
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Operating Revenues |
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$ |
354,127 |
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$ |
367,111 |
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Operating Expenses |
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Purchased Gas |
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98,400 |
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126,969 |
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Operation and Maintenance |
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97,388 |
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91,679 |
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Property, Franchise and Other Taxes |
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18,605 |
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17,576 |
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Depreciation, Depletion and Amortization |
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50,588 |
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43,659 |
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264,981 |
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279,883 |
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Operating Income |
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89,146 |
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87,228 |
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Other Income (Expense): |
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Income from Unconsolidated Subsidiaries |
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624 |
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627 |
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Interest Income |
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569 |
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1,460 |
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Other Income |
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851 |
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1,522 |
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Interest Expense on Long-Term Debt |
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(21,115 |
) |
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(21,756 |
) |
Other Interest Expense |
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(1,874 |
) |
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(2,539 |
) |
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Income Before Income Taxes |
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68,201 |
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66,542 |
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Income Tax Expense |
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25,616 |
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23,638 |
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Net Income Available for Common Stock |
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42,585 |
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42,904 |
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EARNINGS REINVESTED IN THE BUSINESS |
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Balance at April 1 |
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1,038,869 |
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932,119 |
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1,081,454 |
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975,023 |
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Dividends on Common Stock
(2010 - $0.345 per share; 2009 - $0.335 per share) |
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|
(28,278 |
) |
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|
(26,761 |
) |
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Balance at June 30 |
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$ |
1,053,176 |
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$ |
948,262 |
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Earnings Per Common Share: |
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Basic: |
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Net Income Available for Common Stock |
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$ |
0.52 |
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$ |
0.54 |
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Diluted: |
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Net Income Available for Common Stock |
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$ |
0.51 |
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$ |
0.53 |
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Weighted Average Common Shares Outstanding: |
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Used in Basic Calculation |
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81,801,377 |
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|
79,551,195 |
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Used in Diluted Calculation |
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82,970,921 |
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80,391,402 |
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See Notes to Condensed Consolidated Financial Statements
-6-
Item 1. Financial Statements (Cont.)
National Fuel Gas Company
Consolidated Statements of Income and Earnings
Reinvested in the Business
(Unaudited)
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Nine Months Ended |
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June 30, |
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(Thousands of Dollars, Except Per Common Share Amounts) |
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2010 |
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2009 |
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INCOME |
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Operating Revenues |
|
$ |
1,482,518 |
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$ |
1,778,919 |
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Operating Expenses |
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Purchased Gas |
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605,617 |
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|
941,171 |
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Operation and Maintenance |
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|
308,903 |
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311,496 |
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Property, Franchise and Other Taxes |
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|
57,719 |
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56,709 |
|
Depreciation, Depletion and Amortization |
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142,433 |
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|
127,715 |
|
Impairment of Oil and Gas Producing Properties |
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182,811 |
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1,114,672 |
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|
1,619,902 |
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|
Operating Income |
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367,846 |
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|
159,017 |
|
Other Income (Expense): |
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Income from Unconsolidated Subsidiaries |
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1,696 |
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|
2,719 |
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Impairment of Investment in Partnership |
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(1,804 |
) |
Interest Income |
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|
2,049 |
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|
4,358 |
|
Other Income |
|
|
2,473 |
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|
7,350 |
|
Interest Expense on Long-Term Debt |
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|
(65,238 |
) |
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|
(57,357 |
) |
Other Interest Expense |
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|
(5,264 |
) |
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|
(5,013 |
) |
|
Income Before Income Taxes |
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|
303,562 |
|
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|
109,270 |
|
Income Tax Expense |
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|
116,050 |
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|
35,560 |
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|
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|
|
|
|
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|
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|
Net Income Available for Common Stock |
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|
187,512 |
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|
|
73,710 |
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|
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|
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|
|
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EARNINGS REINVESTED IN THE BUSINESS |
|
|
|
|
|
|
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|
Balance at October 1 |
|
|
948,293 |
|
|
|
953,799 |
|
|
|
|
|
1,135,805 |
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|
1,027,509 |
|
Adoption of
Authoritative Guidance for Defined Benefit Pension and Other Post-Retirement Plans |
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|
|
|
|
(804 |
) |
Dividends on Common Stock
(2010 - $1.015 per share; 2009 - $0.985 per share) |
|
|
(82,629 |
) |
|
|
(78,443 |
) |
|
Balance at June 30 |
|
$ |
1,053,176 |
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|
$ |
948,262 |
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|
|
|
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Earnings Per Common Share: |
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|
|
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Basic: |
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|
|
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Net Income Available for Common Stock |
|
$ |
2.31 |
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|
$ |
0.93 |
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Diluted: |
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|
|
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Net Income Available for Common Stock |
|
$ |
2.27 |
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|
$ |
0.92 |
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|
Weighted Average Common Shares Outstanding: |
|
|
|
|
|
|
|
|
Used in Basic Calculation |
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|
81,178,000 |
|
|
|
79,450,838 |
|
|
Used in Diluted Calculation |
|
|
82,556,730 |
|
|
|
80,248,787 |
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|
See Notes to Condensed Consolidated Financial Statements
-7-
Item 1. Financial Statements (Cont.)
National Fuel Gas Company
Consolidated Balance Sheets
(Unaudited)
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June 30, |
|
|
September 30, |
|
(Thousands of Dollars) |
|
2010 |
|
|
2009 |
|
|
|
|
ASSETS |
|
|
|
|
|
|
|
|
Property, Plant and Equipment |
|
$ |
5,518,060 |
|
|
$ |
5,184,844 |
|
Less Accumulated Depreciation, Depletion
and Amortization |
|
|
2,164,383 |
|
|
|
2,051,482 |
|
|
|
|
|
3,353,677 |
|
|
|
3,133,362 |
|
|
Current Assets |
|
|
|
|
|
|
|
|
Cash and Temporary Cash Investments |
|
|
458,847 |
|
|
|
408,053 |
|
Cash Held in Escrow |
|
|
2,000 |
|
|
|
2,000 |
|
Hedging Collateral Deposits |
|
|
8,222 |
|
|
|
848 |
|
Receivables Net of Allowance for Uncollectible Accounts of
$40,786 and $38,334, Respectively |
|
|
143,684 |
|
|
|
144,466 |
|
Unbilled Utility Revenue |
|
|
12,957 |
|
|
|
18,884 |
|
Gas Stored Underground |
|
|
27,245 |
|
|
|
55,862 |
|
Materials and Supplies at average cost |
|
|
32,753 |
|
|
|
24,520 |
|
Other Current Assets |
|
|
42,639 |
|
|
|
68,474 |
|
Deferred Income Taxes |
|
|
32,893 |
|
|
|
53,863 |
|
|
|
|
|
761,240 |
|
|
|
776,970 |
|
|
|
|
|
|
|
|
|
|
|
Other Assets |
|
|
|
|
|
|
|
|
Recoverable Future Taxes |
|
|
138,435 |
|
|
|
138,435 |
|
Unamortized Debt Expense |
|
|
13,116 |
|
|
|
14,815 |
|
Other Regulatory Assets |
|
|
518,225 |
|
|
|
530,913 |
|
Deferred Charges |
|
|
6,447 |
|
|
|
2,737 |
|
Other Investments |
|
|
76,354 |
|
|
|
78,503 |
|
Investments in Unconsolidated Subsidiaries |
|
|
14,037 |
|
|
|
14,940 |
|
Goodwill |
|
|
5,476 |
|
|
|
5,476 |
|
Intangible Assets |
|
|
20,188 |
|
|
|
21,536 |
|
Fair Value of Derivative Financial Instruments |
|
|
41,897 |
|
|
|
44,817 |
|
Other |
|
|
269 |
|
|
|
6,625 |
|
|
|
|
|
834,444 |
|
|
|
858,797 |
|
|
|
|
|
|
|
|
|
|
|
Total Assets |
|
$ |
4,949,361 |
|
|
$ |
4,769,129 |
|
|
See Notes to Condensed Consolidated Financial Statements
-8-
Item 1. Financial Statements (Cont.)
National Fuel Gas Company
Consolidated Balance Sheets
(Unaudited)
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June 30, |
|
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September 30, |
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(Thousands of Dollars) |
|
2010 |
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|
2009 |
|
|
|
|
CAPITALIZATION AND LIABILITIES |
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Capitalization: |
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Comprehensive Shareholders Equity |
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|
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|
Common Stock, $1 Par Value
Authorized - 200,000,000 Shares; Issued
and Outstanding 81,965,317 Shares and
80,499,915 Shares, Respectively |
|
$ |
81,965 |
|
|
$ |
80,500 |
|
Paid in Capital |
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|
644,751 |
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|
|
602,839 |
|
Earnings Reinvested in the Business |
|
|
1,053,176 |
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|
|
948,293 |
|
|
Total Common Shareholder Equity Before
Items of Other Comprehensive Loss |
|
|
1,779,892 |
|
|
|
1,631,632 |
|
Accumulated Other Comprehensive Loss |
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|
(38,153 |
) |
|
|
(42,396 |
) |
|
Total Comprehensive Shareholders Equity |
|
|
1,741,739 |
|
|
|
1,589,236 |
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Long-Term Debt, Net of Current Portion |
|
|
1,049,000 |
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|
|
1,249,000 |
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|
Total Capitalization |
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|
2,790,739 |
|
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|
2,838,236 |
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Current and Accrued Liabilities |
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Notes Payable to Banks and Commercial Paper |
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Current Portion of Long-Term Debt |
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|
200,000 |
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|
|
|
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Accounts Payable |
|
|
106,087 |
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|
|
90,723 |
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Amounts Payable to Customers |
|
|
51,014 |
|
|
|
105,778 |
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Dividends Payable |
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|
28,278 |
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|
|
26,967 |
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Interest Payable on Long-Term Debt |
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|
17,203 |
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|
|
32,031 |
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Customer Advances |
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|
1,029 |
|
|
|
24,555 |
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Customer Security Deposits |
|
|
18,618 |
|
|
|
17,430 |
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Other Accruals and Current Liabilities |
|
|
65,244 |
|
|
|
18,875 |
|
Fair Value of Derivative Financial Instruments |
|
|
2,776 |
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|
|
2,148 |
|
|
|
|
|
490,249 |
|
|
|
318,507 |
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|
|
|
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|
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Deferred Credits |
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|
|
|
|
|
|
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Deferred Income Taxes |
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|
735,558 |
|
|
|
663,876 |
|
Taxes Refundable to Customers |
|
|
67,057 |
|
|
|
67,046 |
|
Unamortized Investment Tax Credit |
|
|
3,463 |
|
|
|
3,989 |
|
Cost of Removal Regulatory Liability |
|
|
123,357 |
|
|
|
105,546 |
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Other Regulatory Liabilities |
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|
86,106 |
|
|
|
120,229 |
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Pension and Other Post-Retirement Liabilities |
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|
420,361 |
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415,888 |
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Asset Retirement Obligations |
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|
92,601 |
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|
91,373 |
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Other Deferred Credits |
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|
139,870 |
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|
|
144,439 |
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|
|
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1,668,373 |
|
|
|
1,612,386 |
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Commitments and Contingencies |
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Total Capitalization and Liabilities |
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$ |
4,949,361 |
|
|
$ |
4,769,129 |
|
|
See Notes to Condensed Consolidated Financial Statements
-9-
Item 1. Financial Statements (Cont.)
National Fuel Gas Company
Consolidated Statement of Cash Flows
(Unaudited)
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Nine Months Ended |
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June 30, |
|
(Thousands of Dollars) |
|
2010 |
|
|
2009 |
|
|
|
|
OPERATING ACTIVITIES |
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|
|
|
|
|
|
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Net Income Available for Common Stock |
|
$ |
187,512 |
|
|
$ |
73,710 |
|
Adjustments to Reconcile Net Income to Net Cash
Provided by Operating Activities: |
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|
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Impairment of Oil and Gas Producing Properties |
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|
|
|
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|
182,811 |
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Depreciation, Depletion and Amortization |
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|
142,433 |
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|
|
127,715 |
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Deferred Income Taxes |
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|
63,813 |
|
|
|
(85,494 |
) |
Income from Unconsolidated Subsidiaries, Net of
Cash Distributions |
|
|
904 |
|
|
|
180 |
|
Impairment of Investment in Partnership |
|
|
|
|
|
|
1,804 |
|
Excess Tax Benefits Associated with Stock-Based
Compensation Awards |
|
|
(13,207 |
) |
|
|
(5,927 |
) |
Other |
|
|
7,884 |
|
|
|
11,751 |
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Change in: |
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Hedging Collateral Deposits |
|
|
(7,374 |
) |
|
|
(6,358 |
) |
Receivables and Unbilled Utility Revenue |
|
|
6,676 |
|
|
|
(5,520 |
) |
Gas Stored Underground and Materials and Supplies |
|
|
20,384 |
|
|
|
71,491 |
|
Unrecovered Purchased Gas Costs |
|
|
|
|
|
|
35,808 |
|
Prepayments and Other Current Assets |
|
|
39,043 |
|
|
|
37,904 |
|
Accounts Payable |
|
|
127 |
|
|
|
(82,146 |
) |
Amounts Payable to Customers |
|
|
(54,764 |
) |
|
|
43,019 |
|
Customer Advances |
|
|
(23,526 |
) |
|
|
(29,788 |
) |
Customer Security Deposits |
|
|
1,188 |
|
|
|
3,314 |
|
Other Accruals and Current Liabilities |
|
|
30,961 |
|
|
|
162,903 |
|
Other Assets |
|
|
29,197 |
|
|
|
(8,517 |
) |
Other Liabilities |
|
|
(11,358 |
) |
|
|
(14,453 |
) |
|
Net Cash Provided by Operating Activities |
|
|
419,893 |
|
|
|
514,207 |
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|
|
|
|
|
|
|
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INVESTING ACTIVITIES |
|
|
|
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|
|
|
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Capital Expenditures |
|
|
(327,513 |
) |
|
|
(240,312 |
) |
Cash Held in Escrow |
|
|
|
|
|
|
(2,000 |
) |
Net Proceeds from Sale of Oil and Gas Producing Properties |
|
|
|
|
|
|
3,701 |
|
Other |
|
|
(273 |
) |
|
|
(1,674 |
) |
|
Net Cash Used in Investing Activities |
|
|
(327,786 |
) |
|
|
(240,285 |
) |
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|
|
|
|
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|
|
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FINANCING ACTIVITIES |
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|
|
|
|
|
|
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Excess Tax Benefits Associated with Stock-Based
Compensation Awards |
|
|
13,207 |
|
|
|
5,927 |
|
Net Proceeds from Issuance of Long-Term Debt |
|
|
|
|
|
|
247,780 |
|
Reduction of Long-Term Debt |
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|
|
|
|
|
(100,000 |
) |
Dividends Paid on Common Stock |
|
|
(81,318 |
) |
|
|
(77,398 |
) |
Net Proceeds from Issuance of Common Stock |
|
|
26,798 |
|
|
|
14,760 |
|
|
Net Cash Provided by (Used in) Financing Activities |
|
|
(41,313 |
) |
|
|
91,069 |
|
|
|
|
|
|
|
|
|
|
|
Net Increase in Cash and Temporary Cash Investments |
|
|
50,794 |
|
|
|
364,991 |
|
|
|
|
|
|
|
|
|
|
Cash and Temporary Cash Investments at October 1 |
|
|
408,053 |
|
|
|
68,239 |
|
|
|
|
|
|
|
|
|
|
|
Cash and Temporary Cash Investments at June 30 |
|
$ |
458,847 |
|
|
$ |
433,230 |
|
|
See Notes to Condensed Consolidated Financial Statements
-10-
Item 1. Financial Statements (Cont.)
National Fuel Gas Company
Consolidated Statements of Comprehensive Income
(Unaudited)
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|
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Three Months Ended |
|
|
|
June 30, |
|
(Thousands of Dollars) |
|
2010 |
|
|
2009 |
|
|
|
|
Net Income Available for Common Stock |
|
$ |
42,585 |
|
|
$ |
42,904 |
|
|
Other Comprehensive Income (Loss), Before Tax: |
|
|
|
|
|
|
|
|
Foreign Currency Translation Adjustment |
|
|
77 |
|
|
|
(42 |
) |
Unrealized Gain (Loss) on Securities Available for Sale
Arising During the Period |
|
|
(3,361 |
) |
|
|
3,775 |
|
Unrealized Gain (Loss) on Derivative Financial Instruments
Arising During the Period |
|
|
16,528 |
|
|
|
(24,446 |
) |
Reclassification Adjustment for Realized Gains on
Derivative Financial Instruments in Net Income |
|
|
(11,830 |
) |
|
|
(24,853 |
) |
|
Other Comprehensive Income (Loss), Before Tax |
|
|
1,414 |
|
|
|
(45,566 |
) |
|
Income Tax Expense (Benefit) Related to Unrealized Gain (Loss)
on Securities Available for Sale Arising During the Period |
|
|
(1,271 |
) |
|
|
1,429 |
|
Income Tax Expense (Benefit) Related to Unrealized Gain (Loss)
on Derivative Financial Instruments Arising During the Period |
|
|
6,794 |
|
|
|
(9,950 |
) |
Reclassification Adjustment for Income Tax Expense on
Realized Gains on Derivative Financial Instruments
in Net Income |
|
|
(4,858 |
) |
|
|
(10,108 |
) |
|
Income Taxes Net |
|
|
665 |
|
|
|
(18,629 |
) |
|
Other Comprehensive Income (Loss) |
|
|
749 |
|
|
|
(26,937 |
) |
|
Comprehensive Income |
|
$ |
43,334 |
|
|
$ |
15,967 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended |
|
|
|
June 30, |
|
(Thousands of Dollars) |
|
2010 |
|
|
2009 |
|
|
|
|
Net Income Available for Common Stock |
|
$ |
187,512 |
|
|
$ |
73,710 |
|
|
Other Comprehensive Income, Before Tax: |
|
|
|
|
|
|
|
|
Foreign Currency Translation Adjustment |
|
|
140 |
|
|
|
(1 |
) |
Unrealized Loss on Securities Available for Sale
Arising During the Period |
|
|
(2,916 |
) |
|
|
(9,202 |
) |
Unrealized Gain on Derivative Financial Instruments
Arising During the Period |
|
|
39,308 |
|
|
|
127,357 |
|
Reclassification Adjustment for Realized Gains on
Derivative Financial Instruments in Net Income |
|
|
(29,472 |
) |
|
|
(93,260 |
) |
|
Other Comprehensive Income, Before Tax |
|
|
7,060 |
|
|
|
24,894 |
|
|
Income Tax Benefit Related to Unrealized Loss
on Securities Available for Sale Arising During the Period |
|
|
(1,104 |
) |
|
|
(3,475 |
) |
Income Tax Expense Related to Unrealized Gain
on Derivative Financial Instruments Arising During the Period |
|
|
16,041 |
|
|
|
51,576 |
|
Reclassification Adjustment for Income Tax Expense on
Realized Gains on Derivative Financial Instruments
in Net Income |
|
|
(12,120 |
) |
|
|
(37,478 |
) |
|
Income Taxes Net |
|
|
2,817 |
|
|
|
10,623 |
|
|
Other Comprehensive Income |
|
|
4,243 |
|
|
|
14,271 |
|
|
Comprehensive Income |
|
$ |
191,755 |
|
|
$ |
87,981 |
|
|
|
|
|
|
|
|
|
|
|
See Notes to Condensed Consolidated Financial Statements
-11-
Item 1. Financial Statements (Cont.)
National Fuel Gas Company
Notes to Condensed Consolidated Financial Statements
(Unaudited)
Note 1 Summary of Significant Accounting Policies
Principles of Consolidation. The Company consolidates its majority owned entities. The equity
method is used to account for minority owned entities. All significant intercompany balances and
transactions are eliminated.
The preparation of the consolidated financial statements in conformity with GAAP requires
management to make estimates and assumptions that affect the reported amounts of assets and
liabilities and disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses during the reporting period. Actual
results could differ from those estimates.
Reclassification. Certain prior year amounts have been reclassified to conform with current year
presentation.
Earnings for Interim Periods. The Company, in its opinion, has included all adjustments that are
necessary for a fair statement of the results of operations for the reported periods. The
consolidated financial statements and notes thereto, included herein, should be read in conjunction
with the financial statements and notes for the years ended September 30, 2009, 2008 and 2007 that
are included in the Companys 2009 Form 10-K. The consolidated financial statements for the year
ended September 30, 2010 will be audited by the Companys independent registered public accounting
firm after the end of the fiscal year.
The earnings for the nine months ended June 30, 2010 should not be taken as a prediction of
earnings for the entire fiscal year ending September 30, 2010. Most of the business of the Utility
and Energy Marketing segments is seasonal in nature and is influenced by weather conditions. Due
to the seasonal nature of the heating business in the Utility and Energy Marketing segments,
earnings during the winter months normally represent a substantial part of the earnings that those
segments are expected to achieve for the entire fiscal year. The Companys business segments are
discussed more fully in Note 7 Business Segment Information.
Consolidated Statement of Cash Flows. For purposes of the Consolidated Statement of Cash Flows,
the Company considers all highly liquid debt instruments purchased with a maturity of generally
three months or less to be cash equivalents.
At June 30, 2010, the Company accrued $24.3 million of capital expenditures in the Exploration
and Production segment, the majority of which was in the Appalachian region. This amount was
excluded from the Consolidated Statement of Cash Flows at June 30, 2010 since it represented a
non-cash investing activity at that date.
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. These amounts were excluded from the
Consolidated Statement of Cash Flows at September 30, 2009 since they represented non-cash
investing activities at that date. These capital expenditures were paid during the quarter ended
December 31, 2009 and have been included in the Consolidated Statement of Cash Flows for the nine
months ended June 30, 2010.
At June 30, 2009, the Company accrued $9.4 million of capital expenditures in the Exploration
and Production segment, the majority of which was in the Appalachian region. This amount was
excluded from the Consolidated Statement of Cash Flows at June 30, 2009 since it represents a
non-cash investing activity at that date.
-12-
Item 1. Financial Statements (Cont.)
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 nine months ended June 30,
2009.
Hedging Collateral Deposits. This is an account title for cash held in margin accounts funded by
the Company to serve as collateral for hedging positions. At June 30, 2010, the Company had
hedging collateral deposits of $6.4 million related to its exchange-traded futures contracts and
$1.8 million related to its over-the-counter crude oil swap agreements. In accordance with its
accounting policy, the Company does not offset hedging collateral deposits paid or received against
related derivative financial instrument 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 June 30, 2010 and September 30, 2009. Seneca
placed this amount in escrow as part of the purchase price. Currently, the Company and Ivanhoe
Energy are negotiating a final resolution to the issue of whether Ivanhoe Energy is entitled to
some or all of the amount held in escrow.
Gas Stored Underground Current. In the Utility segment, gas stored underground current is
carried at lower of cost or market, on a LIFO method. Gas stored underground current normally
declines during the first and second quarters of the year and is replenished during the third and
fourth quarters. In the Utility segment, the current cost of replacing gas withdrawn from storage
is recorded in the Consolidated Statements of Income and a reserve for gas replacement is recorded
in the Consolidated Balance Sheets under the caption Other Accruals and Current Liabilities.
Such reserve, which amounted to $44.6 million at June 30, 2010, is reduced to zero by September 30
of each year as the inventory is replenished.
Property, Plant and Equipment. In the Companys Exploration and Production segment, oil and gas
property acquisition, exploration and development costs are capitalized under the full cost method
of accounting. Under this methodology, all costs associated with property acquisition, exploration
and development activities are capitalized, including internal costs directly identified with
acquisition, exploration and development activities. The internal costs that are capitalized do not
include any costs related to production, general corporate overhead, or similar activities. The
Company does not recognize any gain or loss on the sale or other disposition of oil and gas
properties unless the gain or loss would significantly alter the relationship between capitalized
costs and proved reserves of oil and gas attributable to a cost center.
Capitalized costs include costs related to unproved properties, which are excluded from
amortization until proved reserves are found or it is determined that the unproved properties are
impaired. Such costs amounted to $192.0 million at June 30, 2010. 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. The
Companys
-13-
Item 1. Financial Statements (Cont.)
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. At June 30, 2010, the Companys capitalized costs were below the full cost ceiling for
the Companys oil and gas properties. As a result, an impairment charge was not required at June
30, 2010.
Accumulated Other Comprehensive Loss. The components of Accumulated Other Comprehensive Loss, net
of related tax effect, are as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
At June 30, 2010 |
|
|
At September 30, 2009 |
|
Funded Status of the Pension and
Other Post-Retirement Benefit Plans |
|
$ |
(63,802 |
) |
|
$ |
(63,802 |
) |
Cumulative Foreign Currency
Translation Adjustment |
|
|
36 |
|
|
|
(104 |
) |
Net Unrealized Gain on Derivative
Financial Instruments |
|
|
24,406 |
|
|
|
18,491 |
|
Net Unrealized Gain on Securities
Available for Sale |
|
|
1,207 |
|
|
|
3,019 |
|
|
|
|
|
|
|
|
Accumulated Other Comprehensive
Loss |
|
$ |
(38,153 |
) |
|
$ |
(42,396 |
) |
|
|
|
|
|
|
|
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 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 SARs as determined using the Treasury Stock Method. Stock
options and SARs that are antidilutive are excluded from the calculation of diluted earnings per
common share. For both the quarter and nine months ended June 30, 2010, there were no stock
options excluded as being antidilutive. There were 544,500 and 237,538 SARs excluded as being
antidilutive for the quarter and nine months ended June 30, 2010, respectively. For both the
quarter and nine months ended June 30, 2009, there were 765,000 stock options excluded as being
antidilutive. In addition, there were 365,000 SARs excluded as being antidilutive for both the
quarter and nine months ended June 30, 2009.
Stock-Based Compensation. During the nine months ended June 30, 2010, the Company granted 520,500
performance-based SARs having a weighted average exercise price of $52.10 per share. The weighted
average grant date fair value of these SARs was $12.06 per share. These SARs may be settled in
cash, in shares of common stock of the Company, or in a combination of cash and shares of common
stock of the Company, as determined by the Company. These SARs are considered equity awards under
the current authoritative guidance for stock-based compensation. The accounting for those SARs is
the same as the accounting for stock options. There were no SARs granted during the quarter ended
June 30, 2010. The performance-based SARs granted during the nine months ended June 30, 2010 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 weighted average grant date fair value of these
performance-based SARs granted during the nine months ended June 30, 2010 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.
There were no stock options granted during the quarter or nine months ended June 30, 2010. The
Company granted 4,000 restricted share awards (non-vested stock as defined by the current
accounting literature) during the nine months ended June 30, 2010. The weighted average fair value
of such restricted shares was $52.10 per share. There were no restricted share awards granted
during the quarter ended June 30, 2010.
-14-
Item 1. Financial Statements (Cont.)
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. The FASBs
authoritative guidance for using fair value to measure nonfinancial assets and nonfinancial
liabilities on a nonrecurring basis became effective during the quarter ended December 31, 2009.
The Companys nonfinancial assets and nonfinancial liabilities were not impacted by this guidance
during the nine months ended June 30, 2010. The Company has identified Goodwill as being the major
nonfinancial asset that may be impacted by the adoption of this guidance. The impact of this
guidance will be known when the Company performs its annual test for goodwill impairment at the end
of the fiscal year; however, at this time, it is not expected to be material. The Company has
identified Asset Retirement Obligations as a nonfinancial liability that may be impacted by the
adoption of the guidance. The impact of this guidance will be known when the Company recognizes
new asset retirement obligations. However, at this time, the Company believes the impact of the
guidance will be immaterial. Additionally, in February 2010, the FASB issued updated guidance that
includes additional requirements and disclosures regarding fair value measurements. The guidance
now requires the gross presentation of activity within the Level 3 roll forward and requires
disclosure of details on transfers in and out of Level 1 and 2 fair value measurements. It also
provides further clarification on the level of disaggregation of fair value measurements and
disclosures on inputs and valuation techniques. The Company has updated its disclosures to reflect
the new requirements in Note 2 Fair Value Measurements, except for the Level 3 roll forward
gross presentation, which will be effective as of the Companys first quarter of fiscal 2012.
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 used to value oil and gas
reserves with 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. Additionally, on January 6, 2010, the
FASB amended the oil and gas accounting standards to conform to the SEC final rule on Modernization
of Oil and Gas Reporting. The revised reporting and disclosure requirements will be 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.
In June 2009, the FASB issued amended authoritative guidance to improve and clarify financial
reporting requirements by companies involved with variable interest entities. The new guidance
requires a company to perform an analysis to determine whether the companys variable interest or
interests give it a controlling financial interest in a variable interest entity. The analysis
also assists in identifying the primary beneficiary of a variable interest entity. This
authoritative guidance will be effective as of the Companys first quarter of fiscal 2011. Given
the current organizational structure of the Company, the Company does not believe this
authoritative guidance will have any impact on its consolidated financial statements.
-15-
Item 1. Financial Statements (Cont.)
Note 2 Fair Value Measurements
The FASB authoritative guidance regarding fair value measurements 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 following table sets forth, by level within the fair value hierarchy, the Companys
financial assets and liabilities (as applicable) that were accounted for at fair value on a
recurring basis as of June 30, 2010 and 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. In January 2010, the FASB issued amended authoritative guidance respecting
disclosures related to fair value measurements. The amended guidance requires disclosure of
financial instruments and liabilities by class of assets and liabilities (not major category of
assets and liabilities). In addition, this amended guidance also requires enhanced disclosures
about the valuation techniques and inputs used to measure fair value and disclosures of transfers
in and out of Level 1 or 2. During the quarter ended March 31, 2010, the Company adopted this
amended guidance.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Recurring Fair Value Measures |
|
At fair value as of June 30, 2010 |
|
(Thousands of Dollars) |
|
Level 1 |
|
|
Level 2 |
|
|
Level 3 |
|
|
Total |
|
|
Assets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash Equivalents Money Market Mutual Funds |
|
$ |
303,261 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
303,261 |
|
Derivative Financial Instruments: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity Futures Contracts Gas |
|
|
576 |
|
|
|
|
|
|
|
|
|
|
|
576 |
|
Over the Counter Swaps Oil |
|
|
|
|
|
|
58 |
|
|
|
79 |
|
|
|
137 |
|
Over the Counter Swaps Gas |
|
|
|
|
|
|
41,184 |
|
|
|
|
|
|
|
41,184 |
|
Other Investments: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balanced Equity Mutual Fund |
|
|
15,805 |
|
|
|
|
|
|
|
|
|
|
|
15,805 |
|
Common Stock Financial Services Industry |
|
|
5,762 |
|
|
|
|
|
|
|
|
|
|
|
5,762 |
|
Other Common Stock |
|
|
201 |
|
|
|
|
|
|
|
|
|
|
|
201 |
|
Hedging Collateral Deposits (1) |
|
|
8,222 |
|
|
|
|
|
|
|
|
|
|
|
8,222 |
|
|
|
|
Total |
|
$ |
333,827 |
|
|
$ |
41,242 |
|
|
$ |
79 |
|
|
$ |
375,148 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative Financial Instruments: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity Futures Contracts Gas |
|
$ |
2,521 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
2,521 |
|
Over the Counter Swaps Oil |
|
|
|
|
|
|
|
|
|
|
225 |
|
|
|
225 |
|
Over the Counter Swaps Gas |
|
|
|
|
|
|
30 |
|
|
|
|
|
|
|
30 |
|
|
|
|
Total |
|
$ |
2,521 |
|
|
$ |
30 |
|
|
$ |
225 |
|
|
$ |
2,776 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Net Assets/(Liabilities) |
|
$ |
331,306 |
|
|
$ |
41,212 |
|
|
$ |
(146 |
) |
|
$ |
372,372 |
|
|
|
|
|
|
|
(1) |
|
The Companys requirement to post hedging collateral deposits is based on the
fair value determined by the Companys counterparties, which may differ from the Companys
assessment of fair value. Hedging collateral deposits may also include closed derivative positions
in which the broker has not cleared the cash from the account to offset the derivative liability.
The Company records liabilities related to closed derivative positions in Other Accruals and
Current Liabilities on the Consolidated Balance Sheet. These liabilities are relieved when the
broker clears the cash from the hedging collateral deposit account. |
-16-
Item 1. Financial Statements (Cont.)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Recurring Fair Value Measures |
|
At fair value as of September 30, 2009 |
|
(Thousands of Dollars) |
|
Level 1 |
|
|
Level 2 |
|
|
Level 3 |
|
|
Total |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Net Assets/(Liabilities) |
|
$ |
420,898 |
|
|
$ |
10,388 |
|
|
$ |
26,969 |
|
|
$ |
458,255 |
|
|
|
|
Derivative Financial Instruments
At June 30, 2010, the derivative financial instruments reported in Level 1 consist of NYMEX
futures contracts used in the Companys Energy Marketing and Pipeline and Storage segments (at
September 30, 2009, the derivative financial instruments reported in Level 1 consist of NYMEX
futures used in the Companys Energy Marketing segment). Hedging collateral deposits of $6.4
million 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 and some of the crude
oil swap agreements used in the Companys Exploration and Production segment and natural gas swap
agreements used in the Energy Marketing segment at June 30, 2010 (at September 30, 2009, the
derivative financial instruments reported in Level 2 consist of natural gas swap agreements used in
the Companys Exploration and Production and Energy Marketing segments). The fair value of these
swap agreements is based on an internal, discounted cash flow model that uses observable inputs
(i.e. LIBOR based discount rates and basis differential information, if applicable, at active
natural gas/crude oil trading markets). At June 30, 2010, the derivative financial instruments
reported in Level 3 consist of a majority of the Exploration and Production segments crude oil
swap agreements (at September 30, 2009, all of the Exploration and Production segments crude oil
swap agreements were reported as Level 3). Hedging collateral deposits of $1.8 million associated
with these oil swap agreements have been reported in Level 1. The fair value of the crude oil swap
agreements is based on an internal, discounted cash flow model that uses both observable (i.e.
LIBOR based discount rates) and unobservable inputs (i.e. basis differential information of crude
oil trading markets with low trading volume). Based on an assessment of the counterparties credit
risk, the fair market value of the price swap agreements reported as Level 2 and Level 3 assets
have been reduced by $0.7 million and $0.9 million at June 30, 2010 and September 30, 2009,
respectively. The fair market value of the price swap agreements reported as Level 2 liabilities
at September 30, 2009 have been reduced by less than $0.1 million based on an assessment of the
Companys credit risk. (Note: As the fair value of the price swap agreements reported as Level 2
and 3 liabilities at June 30, 2010 was minor and the hedging collateral sufficiently covered the
liabilities, there was no credit reserve recorded for the Level 2 and 3 liabilities at June 30,
2010.) These credit reserves were 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.
The tables listed below provide reconciliations of the beginning and ending net balances for
assets and liabilities measured at fair value and classified as Level 3 for the quarter and nine
months ended June 30, 2010 and 2009, respectively. For the quarter ended June 30, 2010, no
transfers in or out of Level 1 or Level 2 occurred.
-17-
Item 1. Financial Statements (Cont.)
Fair Value Measurements Using Unobservable Inputs (Level 3)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Gains/Losses- |
|
|
|
|
|
|
|
|
|
|
|
|
|
Realized and Unrealized |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Included in Other |
|
|
|
|
|
|
|
|
|
March 31, |
|
|
Included in |
|
|
Comprehensive |
|
|
Transfer In/Out of |
|
|
June 30, |
|
(Thousands of Dollars) |
|
2010 |
|
|
Earnings |
|
|
Income (Loss) |
|
|
Level 3 |
|
|
2010 |
|
Derivative Financial Instruments(2) |
|
$ |
(14,100 |
) |
|
$ |
(2,172 |
)(1) |
|
$ |
16,126 |
|
|
$ |
|
|
|
$ |
(146 |
) |
|
|
|
(1) |
|
Amounts are reported in Operating Revenues in the Consolidated Statement of
Income for the three months ended June 30, 2010. |
|
(2) |
|
Derivative Financial Instruments are shown on a net basis. |
Fair Value Measurements Using Unobservable Inputs (Level 3)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Gains/Losses- |
|
|
|
|
|
|
|
|
|
|
|
|
|
Realized and Unrealized |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Included in Other |
|
|
Transfer |
|
|
|
|
|
|
September 30, |
|
|
Included in |
|
|
Comprehensive |
|
|
In/Out of |
|
|
June 30, |
|
(Thousands of Dollars) |
|
2009 |
|
|
Earnings |
|
|
Income (Loss) |
|
|
Level 3 |
|
|
2010 |
|
Derivative Financial Instruments(2) |
|
$ |
26,969 |
|
|
$ |
(6,969 |
)(1) |
|
$ |
(20,146 |
) |
|
$ |
|
|
|
$ |
(146 |
) |
|
|
|
(1) |
|
Amounts are reported in Operating Revenues in the Consolidated Statement of
Income for the nine months ended June 30, 2010. |
|
(2) |
|
Derivative Financial Instruments are shown on a net basis. |
Fair Value Measurements Using Unobservable Inputs (Level 3)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Gains/Losses- |
|
|
|
|
|
|
|
|
|
|
|
|
|
Realized and Unrealized |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Included in Other |
|
|
|
|
|
|
|
|
|
March 31, |
|
|
Included in |
|
|
Comprehensive |
|
|
Transfer In/Out of |
|
|
|
|
|
(Thousands of Dollars) |
|
2009 |
|
|
Earnings |
|
|
Income (Loss) |
|
|
Level 3 |
|
|
June 30, 2009 |
|
Derivative Financial Instruments(2) |
|
$ |
79,159 |
|
|
$ |
(13,662 |
)(1) |
|
$ |
(22,459 |
) |
|
$ |
(8,492 |
) |
|
$ |
34,546 |
|
|
|
|
(1) |
|
Amounts are reported in Operating Revenues in the Consolidated Statement of
Income for the three months ended June 30, 2009. |
|
(2) |
|
Derivative Financial Instruments are shown on a net basis. |
Fair Value Measurements Using Unobservable Inputs (Level 3)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Gains/Losses |
|
|
|
|
|
|
|
|
|
|
|
|
|
Realized and Unrealized |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Included in Other |
|
|
Transfer |
|
|
|
|
|
|
September 30, |
|
|
Included in |
|
|
Comprehensive |
|
|
In/Out of |
|
|
|
|
(Thousands of Dollars) |
|
2008 |
|
|
Earnings |
|
|
Income (Loss) |
|
|
Level 3 |
|
|
June 30, 2009 |
|
Derivative Financial Instruments(2) |
|
$ |
6,333 |
|
|
$ |
(49,443 |
)(1) |
|
$ |
86,148 |
|
|
$ |
(8,492 |
) |
|
$ |
34,546 |
|
|
|
|
(1) |
|
Amounts are reported in Operating Revenues in the Consolidated Statement of
Income for the nine months ended June 30, 2009. |
|
(2) |
|
Derivative Financial Instruments are shown on a net basis. |
-18-
Item 1. Financial Statements (Cont.)
Note 3 Financial Instruments
Long-Term Debt. 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 ratings and
current market conditions in determining the yield, and subsequently, the fair market value of the
debt. Based on these criteria, the fair market value of long-term debt, including current portion,
was as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30, 2010 |
|
|
September 30, 2009 |
|
|
|
Carrying |
|
|
|
|
|
Carrying |
|
|
|
|
|
|
Amount |
|
|
Fair Value |
|
|
Amount |
|
|
Fair Value |
|
Long-Term Debt |
|
$ |
1,249,000 |
|
|
$ |
1,372,413 |
|
|
$ |
1,249,000 |
|
|
$ |
1,347,368 |
|
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 $54.6 million at June 30, 2010 and $54.2 million at
September 30, 2009. The fair value of the equity mutual fund was $15.8 million at June 30, 2010 and
September 30, 2009. The gross unrealized loss on this equity mutual fund was $1.4 million at June
30, 2010 and $1.0 million at September 30, 2009. Management does not consider this investment to
be other than temporarily impaired. The fair value of the stock of an insurance company was $5.8
million at June 30, 2010 and $8.3 million at September 30, 2009. The gross unrealized gain on this
stock was $3.4 million at June 30, 2010 and $5.9 million at September 30, 2009. 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, Energy Marketing and Pipeline and Storage 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, withdrawal of gas from storage to meet customer demand, and the
potential decline in the value of gas held in storage. The duration of the Companys hedges do not
typically exceed 3 years.
The Company has presented its net derivative assets and liabilities on its Consolidated
Balance Sheets at June 30, 2010 and September 30, 2009 as shown in the table below.
|
|
|
|
|
|
|
|
|
|
|
Fair Values of Derivative Instruments |
|
|
(Thousands of Dollars) |
Derivatives |
|
Asset Derivatives |
|
Liability Derivatives |
|
Designated as |
|
Consolidated |
|
|
|
Consolidated |
|
|
Hedging |
|
Balance Sheet |
|
|
|
Balance Sheet |
|
|
Instruments |
|
Location |
|
Fair Value |
|
Location |
|
Fair Value |
Commodity |
|
Fair Value of |
|
|
|
Fair Value of |
|
|
Contracts at |
|
Derivative |
|
|
|
Derivative |
|
|
June 30, |
|
Financial |
|
|
|
Financial |
|
|
2010 |
|
Instruments |
|
$41,897 |
|
Instruments |
|
$2,776 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value of |
|
|
|
Fair Value of |
|
|
Commodity |
|
Derivative |
|
|
|
Derivative |
|
|
Contracts at |
|
Financial |
|
|
|
Financial |
|
|
September 30, 2009 |
|
Instruments |
|
$44,817 |
|
Instruments |
|
$2,148 |
|
|
|
|
|
-19-
Item 1. Financial Statements (Cont.)
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 Sheets at June 30,
2010 and September 30, 2009.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivatives |
|
|
|
|
|
|
Designated as |
|
Fair Values of Derivative Instruments |
|
Hedging |
|
(Thousands of Dollars) |
|
Instruments |
|
Gross Asset Derivatives |
|
|
Gross Liability Derivatives |
|
|
|
Fair Value |
|
|
Fair Value |
|
Commodity Contracts
at June 30, 2010 |
|
$ |
52,984 |
|
|
$ |
13,863 |
|
|
|
|
|
|
|
|
Commodity Contracts
at September 30,
2009 |
|
$ |
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 (loss) and reclassified into earnings in the 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.
At June 30, 2010, the Companys Exploration and Production segment had the following commodity
derivative contracts (swaps) outstanding to hedge forecasted sales (where the Company uses short
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
|
|
41.4 Bcf (all short positions) |
Crude Oil
|
|
2,803,000 Bbls (all short positions) |
At June 30, 2010, 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
|
|
4.8 Bcf (4.5 Bcf short positions (forecasted storage
withdrawals) and 0.3 Bcf long positions (forecasted storage
injections)) |
At June 30, 2010, the Companys Pipeline and Storage segment had the following commodity
derivative contracts (futures contracts) 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):
|
|
|
Commodity |
|
Units |
Natural Gas
|
|
1.5 Bcf (all short positions) |
-20-
Item 1. Financial Statements (Cont.)
At June 30, 2010, the Companys Exploration and Production segment had $39.9 million ($23.5
million after tax) of net hedging gains included in the accumulated other comprehensive income
(loss) balance. It is expected that $26.1 million ($15.4 million after tax) of those gains will be
reclassified into the Consolidated Statement of Income within the next 12 months as the expected
sales of the underlying commodities occur. See Note 1, under Accumulated Other Comprehensive
Income (Loss), for the after-tax gain pertaining to derivative financial instruments (Net
Unrealized Gain (Loss) on Derivative Financial Instruments in Note 1 includes the Exploration and
Production, Energy Marketing and Pipeline and Storage segments).
At June 30, 2010, the Companys Energy Marketing segment had $1.4 million ($0.8 million after
tax) of net hedging gains included in the accumulated other comprehensive income (loss) balance.
It is expected that the full amount will be reclassified into the Consolidated Statement of Income
within the next 12 months as the sales and purchases of the underlying commodities occur. See Note
1, under Accumulated Other Comprehensive Income (Loss), for the after-tax gain pertaining to
derivative financial instruments (Net Unrealized Gain (Loss) on Derivative Financial Instruments in
Note 1 includes the Exploration and Production, Energy Marketing and Pipeline and Storage
segments).
At June 30, 2010, the Companys Pipeline and Storage segment had $0.1 million (less than $0.1
million after tax) of net hedging gains included in the accumulated other comprehensive income
(loss) balance. It is expected that the full amount will be reclassified into the Consolidated
Statement of Income within the next 12 months as the expected sales of the underlying commodities
occur. See Note 1, under Accumulated Other Comprehensive Income (Loss), for the after-tax gain
pertaining to derivative financial instruments (Net Unrealized Gain (Loss) on Derivative Financial
Instruments in Note 1 includes the Exploration and Production, Energy Marketing and Pipeline and
Storage segments).
-21-
Item 1. Financial Statements (Cont.)
The Effect of Derivative Financial Instruments on the Statement of Financial Performance for the
Three Months Ended June 30, 2010 and 2009 (Thousands of Dollars)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Location of |
|
|
|
Amount of Derivative Gain or |
|
|
|
|
|
|
|
|
|
Amount of Derivative Gain or |
|
|
Derivative Gain or |
|
|
(Loss) Reclassified from |
|
|
Location of |
|
|
|
|
|
|
(Loss) Recognized in Other |
|
|
(Loss) Reclassified |
|
|
Accumulated Other |
|
|
Derivative Gain or |
|
|
|
|
|
|
Comprehensive Income (Loss) |
|
|
from Accumulated |
|
|
Comprehensive Income (Loss) |
|
|
(Loss) Recognized |
|
|
Derivative Gain or (Loss) |
|
|
|
on the Consolidated |
|
|
Other Comprehensive |
|
|
on the Consolidated Balance |
|
|
in the Consolidated |
|
|
Recognized in the |
|
|
|
Statement of Comprehensive |
|
|
Income (Loss) on |
|
|
Sheet into the Consolidated |
|
|
Statement of Income |
|
|
Consolidated Statement of |
|
|
|
Income (Loss) |
|
|
the Consolidated |
|
|
Statement of Income |
|
|
(Ineffective |
|
|
Income (Ineffective Portion |
|
|
|
(Effective Portion) |
|
|
Balance Sheet into |
|
|
(Effective Portion) |
|
|
Portion and Amount |
|
|
and Amount Excluded from |
|
Derivatives in Cash |
|
for the Three |
|
|
the Consolidated |
|
|
for the Three |
|
|
Excluded from |
|
|
Effectiveness Testing) for |
|
Flow Hedging |
|
Months Ended |
|
|
Statement of Income |
|
|
Months Ended |
|
|
Effectiveness |
|
|
the Three Months Ended |
|
Relationships |
|
June 30, |
|
|
(Effective Portion) |
|
|
June 30, |
|
|
Testing) |
|
|
June 30, |
|
|
|
2010 |
|
|
2009 |
|
|
|
|
|
|
2010 |
|
|
2009 |
|
|
|
|
|
|
2010 |
|
|
2009 |
|
Commodity Contracts
Exploration &
Production segment |
|
$ |
16,445 |
|
|
$ |
(23,013 |
) |
|
Operating Revenue |
|
$ |
11,592 |
|
|
$ |
22,940 |
|
|
Operating Revenue |
|
$ |
|
|
|
$ |
158 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity Contracts
Energy Marketing
segment |
|
$ |
519 |
|
|
$ |
(1,433 |
) |
|
Purchased Gas |
|
$ |
238 |
|
|
$ |
1,913 |
|
|
Operating Revenue |
|
$ |
|
|
|
$ |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity Contracts
Pipeline &
Storage segment |
|
$ |
(436 |
) |
|
$ |
|
|
|
Operating Revenue |
|
$ |
|
|
|
$ |
|
|
|
Operating Revenue |
|
$ |
|
|
|
$ |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
16,528 |
|
|
$ |
(24,446 |
) |
|
|
|
|
|
$ |
11,830 |
|
|
$ |
24,853 |
|
|
|
|
|
|
$ |
|
|
|
$ |
158 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
-22-
Item 1. Financial Statements (Cont.)
The Effect of Derivative Financial Instruments on the Statement of Financial Performance for the
Nine Months Ended June 30, 2010 and 2009 (Thousands of Dollars)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Location of |
|
|
|
Amount of Derivative Gain or |
|
|
|
|
|
|
|
|
|
Amount of Derivative Gain or |
|
|
Derivative Gain or |
|
|
(Loss) Reclassified from |
|
|
Location of |
|
|
|
|
|
|
(Loss) Recognized in Other |
|
|
(Loss) Reclassified |
|
|
Accumulated Other |
|
|
Derivative Gain or |
|
|
|
|
|
|
Comprehensive Income (Loss) |
|
|
from Accumulated |
|
|
Comprehensive Income (Loss) |
|
|
(Loss) Recognized |
|
|
Derivative Gain or (Loss) |
|
|
|
on the Consolidated |
|
|
Other Comprehensive |
|
|
on the Consolidated Balance |
|
|
in the Consolidated |
|
|
Recognized in the |
|
|
|
Statement of Comprehensive |
|
|
Income (Loss) on |
|
|
Sheet into the Consolidated |
|
|
Statement of Income |
|
|
Consolidated Statement of |
|
|
|
Income (Loss) |
|
|
the Consolidated |
|
|
Statement of Income |
|
|
(Ineffective |
|
|
Income (Ineffective Portion |
|
|
|
(Effective Portion) |
|
|
Balance Sheet into |
|
|
(Effective Portion) |
|
|
Portion and Amount |
|
|
and Amount Excluded from |
|
Derivatives in Cash |
|
for the Nine |
|
|
the Consolidated |
|
|
for the Nine |
|
|
Excluded from |
|
|
Effectiveness Testing) for |
|
Flow Hedging |
|
Months Ended |
|
|
Statement of Income |
|
|
Months Ended |
|
|
Effectiveness |
|
|
the Nine Months Ended |
|
Relationships |
|
June 30, |
|
|
(Effective Portion) |
|
|
June 30, |
|
|
Testing) |
|
|
June 30, |
|
|
|
2010 |
|
|
2009 |
|
|
|
|
|
|
2010 |
|
|
2009 |
|
|
|
|
|
|
2010 |
|
|
2009 |
|
Commodity Contracts
Exploration &
Production segment |
|
$ |
32,910 |
|
|
$ |
117,764 |
|
|
Operating Revenue |
|
$ |
29,170 |
|
|
$ |
71,324 |
|
|
Operating Revenue |
|
$ |
|
|
|
$ |
424 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity Contracts
Energy Marketing
segment |
|
$ |
5,821 |
|
|
$ |
9,410 |
|
|
Purchased Gas |
|
$ |
(209 |
) |
|
$ |
21,328 |
|
|
Operating Revenue |
|
$ |
|
|
|
$ |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity Contracts
Pipeline &
Storage segment |
|
$ |
577 |
|
|
$ |
|
|
|
Operating Revenue |
|
$ |
511 |
|
|
$ |
1,290 |
|
|
Operating Revenue |
|
$ |
|
|
|
$ |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity Contracts
All Other
(1) |
|
$ |
|
|
|
$ |
183 |
|
|
Purchased Gas |
|
$ |
|
|
|
$ |
(682 |
) |
|
Purchased Gas |
|
$ |
|
|
|
$ |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
39,308 |
|
|
$ |
127,357 |
|
|
|
|
|
|
$ |
29,472 |
|
|
$ |
93,260 |
|
|
|
|
|
|
$ |
|
|
|
$ |
424 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
There were no open hedging positions at June 30, 2010. As such there is no mention of these positions in the preceeding sections of this footnote. |
-23-
Item 1. Financial Statements (Cont.)
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 the decline in the value
of natural gas held in storage. With respect to fixed price sales commitments, the Company enters
into long positions to mitigate the risk of price increases for natural gas supplies that could
occur after the Company enters into fixed price sales agreements with its customers. With respect
to fixed price purchase commitments, the Company enters into short positions to mitigate the risk
of price decreases that could occur after the Company locks into fixed price purchase deals with
its suppliers. With respect to storage hedges, the Company enters into short positions to mitigate
the risk of price decreases that could result in a lower of cost or market writedown of the value
of natural gas in storage that is recorded in the Companys financial statements. As of June 30,
2010, the Companys Energy Marketing segment had fair value hedges covering approximately 10.8 Bcf
(9.3 Bcf of fixed price sales commitments (all long positions), 1.3 Bcf of fixed price purchase
commitments (all short positions) and 0.2 Bcf of storage hedges (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 |
|
$ |
(892,512 |
) |
|
$ |
892,512 |
|
Purchased Gas |
|
$ |
(502,195 |
) |
|
$ |
502,195 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amount of Derivative Gain or |
|
|
|
|
|
|
|
(Loss) Recognized in the |
|
|
|
Location of Derivative Gain or |
|
|
Consolidated Statement of Income |
|
|
|
(Loss) Recognized in the |
|
|
for the Nine Months Ended June |
|
Derivatives in |
|
Consolidated Statement of |
|
|
30, 2010 |
|
Fair Value Hedging Relationships |
|
Income |
|
|
(In Thousands) |
|
Commodity Contracts Energy
Marketing segment
(1) |
|
Operating Revenues |
|
$ |
(893 |
) |
|
|
|
|
|
|
|
|
|
Commodity Contracts Energy
Marketing segment
(2) |
|
Purchased Gas |
|
$ |
(456 |
) |
|
|
|
|
|
|
|
|
|
Commodity Contracts Energy
Marketing segment
(3) |
|
Purchased Gas |
|
$ |
(46 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
(1,395 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
(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 natural gas held in storage. |
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
eleven counterparties of which ten of the eleven counterparties are in a net gain position. On
average, the Company had $4.1 million of credit exposure per counterparty in a gain position at
June 30, 2010. BP Energy Company (an affiliate of BP Corporation North America, Inc.) was one of
the ten counterparties in a gain position. At June 30, 2010, the Company had a $7.2 million
receivable with BP Energy Company. The Company considered the credit quality of BP Energy Company
(as it does with all of its counterparties) in determining hedge effectiveness and believes the
hedges remain effective. The Company had not received any collateral from these counterparties at
June 30, 2010 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.
-24-
Item 1. Financial Statements (Cont.)
As of June 30, 2010, nine of the eleven 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 June 30, 2010, the fair market value of the derivative financial instrument assets with a
credit-risk related contingency feature was $27.1 million according to the Companys internal model
(discussed in Note 2 Fair Value Measurements). At June 30, 2010, the fair market value of the
derivative financial instrument liability with a credit-risk related contingency feature was $0.3
million according to the Companys internal model (discussed in Note 2 Fair Value Measurements).
The Companys internal model may yield a different fair value than the fair value determined by the
Companys counterparties. The Companys requirement to post hedging collateral deposits is based
on the fair value determined by the Companys counterparties. For its over-the-counter crude oil
swap agreements, which are in a liability position, the Company was required to post $1.8 million
in hedging collateral deposits at June 30, 2010. This is discussed in Note 1 under Hedging
Collateral Deposits.
For its exchange traded futures contracts which are in a liability position, the Company had
posted $5.8 million in hedging collateral, and for its exchange traded futures contracts which are
in an asset position, the Company had posted $0.6 million in hedging collateral as of June 30,
2010. 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 and margin
requirements it has with its counterparties.
The Companys requirement to post hedging collateral deposits is based on the fair value
determined by the Companys counterparties, which may differ from the Companys assessment of fair
value. Hedging collateral deposits may also include closed derivative positions in which the
broker has not cleared the cash from the account to offset the derivative liability. The Company
records liabilities related to closed derivative positions in Other Accruals and Current
Liabilities on the Consolidated Balance Sheet. These liabilities are relieved when the broker
clears the cash from the hedging collateral deposit account. This is discussed in Note 1 under
Hedging Collateral Deposits.
Note 4 Income Taxes
The components of federal and state income taxes included in the Consolidated Statements of
Income are as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended |
|
|
|
June 30, |
|
|
|
2010 |
|
|
2009 |
|
Current Income Taxes |
|
|
Federal |
|
$ |
42,323 |
|
|
$ |
95,526 |
|
State |
|
|
9,914 |
|
|
|
25,528 |
|
|
|
|
|
|
|
|
|
|
Deferred Income Taxes |
|
|
|
|
|
|
|
|
Federal |
|
|
50,079 |
|
|
|
(67,051 |
) |
State |
|
|
13,734 |
|
|
|
(18,443 |
) |
|
|
|
|
|
|
116,050 |
|
|
|
35,560 |
|
Deferred Investment Tax Credit |
|
|
(523 |
) |
|
|
(523 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
Total Income Taxes |
|
$ |
115,527 |
|
|
$ |
35,037 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Presented as Follows: |
|
|
|
|
|
|
|
|
Other Income |
|
$ |
(523 |
) |
|
$ |
(523 |
) |
Income Tax Expense |
|
|
116,050 |
|
|
|
35,560 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Income Taxes |
|
$ |
115,527 |
|
|
$ |
35,037 |
|
|
|
|
-25-
Item 1. Financial Statements (Cont.)
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 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended |
|
|
|
June 30, |
|
|
|
2010 |
|
|
2009 |
|
|
|
|
U.S. Income Before Income Taxes |
|
$ |
303,039 |
|
|
$ |
108,747 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Income Tax
Expense, Computed at Federal Statutory Rate of 35% |
|
$ |
106,064 |
|
|
$ |
38,061 |
|
|
|
|
|
|
|
|
|
|
Increase (Reduction) in Taxes Resulting From: |
|
|
|
|
|
|
|
|
State Income Taxes |
|
|
15,371 |
|
|
|
4,605 |
|
Domestic Production Activities Deduction |
|
|
(711 |
) |
|
|
(1,790 |
) |
Miscellaneous |
|
|
(5,197 |
) |
|
|
(5,839 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
Total Income Taxes |
|
$ |
115,527 |
|
|
$ |
35,037 |
|
|
|
|
Significant components of the Companys deferred tax liabilities and assets are as follows (in
thousands):
|
|
|
|
|
|
|
|
|
|
|
At June 30, 2010 |
|
|
At September 30, 2009 |
|
|
|
|
Deferred Tax Liabilities: |
|
|
|
|
|
|
|
|
Property, Plant and Equipment |
|
$ |
781,581 |
|
|
$ |
733,581 |
|
Pension and Other Post-Retirement Benefit
Costs |
|
|
177,124 |
|
|
|
178,440 |
|
Other |
|
|
55,716 |
|
|
|
54,977 |
|
|
|
|
Total Deferred Tax Liabilities |
|
|
1,014,421 |
|
|
|
966,998 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred Tax Assets: |
|
|
|
|
|
|
|
|
Pension and Other Post-Retirement Benefit
Costs |
|
|
(214,161 |
) |
|
|
(212,299 |
) |
Other |
|
|
(97,595 |
) |
|
|
(144,686 |
) |
|
|
|
Total Deferred Tax Assets |
|
|
(311,756 |
) |
|
|
(356,985 |
) |
|
|
|
Total Net Deferred Income Taxes |
|
$ |
702,665 |
|
|
$ |
610,013 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Presented as Follows: |
|
|
|
|
|
|
|
|
Net Deferred Tax Liability/(Asset) Current |
|
$ |
(32,893 |
) |
|
$ |
(53,863 |
) |
Net Deferred Tax Liability Non-Current |
|
|
735,558 |
|
|
|
663,876 |
|
|
|
|
Total Net Deferred Income Taxes |
|
$ |
702,665 |
|
|
$ |
610,013 |
|
|
|
|
During the quarter ended March 31, 2010, the Company reduced its deferred tax asset relating
to the Medicare Part D subsidy by $30 million to reflect changes made by the fundamental health
care reform legislation enacted during that quarter. In conjunction with the reduction of the
deferred tax asset, the Company reduced its Medicare Part D regulatory liability by $30 million.
In the Companys Utility and Pipeline and Storage segments, the Companys post-retirement benefit
plans are funded by a component of tariff rates charged to customers. As such, prior to the
fundamental health care reform legislation, the $30 million tax benefit had been recorded as a
regulatory liability in anticipation of flowing that tax benefit back to customers through adjusted
tariff rates.
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 $67.1 million and $67.0 million at June 30, 2010 and September 30, 2009, respectively. Also,
regulatory assets representing future amounts collectible from customers, corresponding to
additional deferred income taxes not previously recorded because of prior ratemaking practices,
amounted to $138.4 million at both June 30, 2010 and September 30, 2009.
-26-
Item 1. Financial Statements (Cont.)
The Company files federal and various state income tax returns. The Internal Revenue Service
(IRS) is currently conducting an examination of the Company for fiscal 2009 and fiscal 2010 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
2007 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.
As of June 30, 2010, the Company had a federal net operating loss carryover of $21.2 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.
Note 5 Capitalization
Common Stock. During the nine months ended June 30, 2010, the Company issued 1,714,768 original
issue shares of common stock as a result of stock option exercises and 4,000 original issue shares
for restricted stock awards (non-vested stock as defined by the current accounting literature for
stock-based compensation). The Company also issued 10,089 original issue shares of common stock to
the non-employee directors of the Company who receive compensation under the Companys Retainer
Policy for Non-Employee Directors, as partial consideration for the directors services during the
nine months ended June 30, 2010. 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 the nine months ended June 30, 2010, 263,455 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.
Current Portion of Long-Term Debt. Current Portion of Long-Term Debt at June 30, 2010 consists of
$200 million of 7.50% medium-term notes that mature in November 2010.
Note 6 Commitments and Contingencies
Environmental Matters. The Company is subject to various federal, state and local laws and
regulations relating to the protection of the environment. The Company has established procedures
for the ongoing evaluation of its operations to identify potential environmental exposures and to
comply with regulatory policies and procedures. It is the Companys policy to accrue estimated
environmental clean-up costs (investigation and remediation) when such amounts can reasonably be
estimated and it is probable that the Company will be required to incur such costs.
The Company has agreed with the NYDEC to remediate a 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
$14.8 million.
At June 30, 2010, the Company has estimated its remaining clean-up costs related to former
manufactured gas plant sites and third party waste disposal sites (including the former
manufactured gas plant site discussed above) will be in the range of $17.5 million to $21.7
million. The minimum estimated liability of $17.5 million, which includes the $14.8 million
discussed above, has been recorded on the Consolidated Balance Sheet at June 30, 2010. The Company
expects to recover these environmental clean-up costs through rate recovery.
-27-
Item 1. Financial Statements (Cont.)
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.
Other. 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 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 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.
Note 7 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 the reported
segments is based upon a combination of factors including differences in products and services,
regulatory environment and geographic factors.
The data presented in the tables below reflect the reported segments and reconciliations to
consolidated amounts. As stated in the 2009 Form 10-K, 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. There have been no changes in the basis of segmentation nor in the
basis of measuring segment profit or loss from those used in the Companys 2009 Form 10-K. There
have been no material changes in the amount of assets for any operating segment from the amounts
disclosed in the 2009 Form 10-K.
Quarter Ended June 30, 2010 (Thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploration |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Corporate and |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
and |
|
|
|
|
|
|
Total Reportable |
|
|
|
|
|
|
Intersegment |
|
|
|
|
|
|
Utility |
|
|
Pipeline and Storage |
|
|
Production |
|
|
Energy Marketing |
|
|
Segments |
|
|
All Other |
|
|
Eliminations |
|
|
Total Consolidated |
|
|
Revenue from
External Customers |
|
$ |
126,326 |
|
|
$ |
32,086 |
|
|
$ |
112,802 |
|
|
$ |
72,830 |
|
|
$ |
344,044 |
|
|
$ |
9,859 |
|
|
$ |
224 |
|
|
$ |
354,127 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Intersegment Revenues |
|
$ |
2,653 |
|
|
$ |
19,466 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
22,119 |
|
|
$ |
1,418 |
|
|
$ |
(23,537 |
) |
|
$ |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment Profit: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income (Loss) |
|
$ |
5,969 |
|
|
$ |
7,234 |
|
|
$ |
27,883 |
|
|
$ |
1,411 |
|
|
$ |
42,497 |
|
|
$ |
186 |
|
|
$ |
(98 |
) |
|
$ |
42,585 |
|
Nine Months Ended June 30, 2010 (Thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploration |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Corporate and |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
and |
|
|
|
|
|
|
Total Reportable |
|
|
|
|
|
|
Intersegment |
|
|
|
|
|
|
Utility |
|
|
Pipeline and Storage |
|
|
Production |
|
|
Energy Marketing |
|
|
Segments |
|
|
All Other |
|
|
Eliminations |
|
|
Total Consolidated |
|
|
Revenue from
External Customers |
|
$ |
707,323 |
|
|
$ |
107,560 |
|
|
$ |
328,312 |
|
|
$ |
303,103 |
|
|
$ |
1,446,298 |
|
|
$ |
35,568 |
|
|
$ |
652 |
|
|
$ |
1,482,518 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Intersegment Revenues |
|
$ |
13,315 |
|
|
$ |
60,289 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
73,604 |
|
|
$ |
1,418 |
|
|
$ |
(75,022 |
) |
|
$ |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment Profit: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income (Loss) |
|
$ |
62,254 |
|
|
$ |
30,036 |
|
|
$ |
85,046 |
|
|
$ |
8,472 |
|
|
$ |
185,808 |
|
|
$ |
2,925 |
|
|
$ |
(1,221 |
) |
|
$ |
187,512 |
|
-28-
Item 1. Financial Statements (Cont.)
Quarter Ended June 30, 2009 (Thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploration |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Corporate and |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
and |
|
|
|
|
|
|
Total Reportable |
|
|
|
|
|
|
Intersegment |
|
|
|
|
|
|
Utility |
|
|
Pipeline and Storage |
|
|
Production |
|
|
Energy Marketing |
|
|
Segments |
|
|
All Other |
|
|
Eliminations |
|
|
Total Consolidated |
|
|
Revenue from
External Customers |
|
$ |
158,310 |
|
|
$ |
30,791 |
|
|
$ |
97,619 |
|
|
$ |
71,894 |
|
|
$ |
358,614 |
|
|
$ |
8,269 |
|
|
$ |
228 |
|
|
$ |
367,111 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Intersegment Revenues |
|
$ |
2,940 |
|
|
$ |
20,033 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
22,973 |
|
|
$ |
374 |
|
|
$ |
(23,347 |
) |
|
$ |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment Profit: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income (Loss) |
|
$ |
5,396 |
|
|
$ |
9,221 |
|
|
$ |
27,083 |
|
|
$ |
1,331 |
|
|
$ |
43,031 |
|
|
$ |
(1,086 |
) |
|
$ |
959 |
|
|
$ |
42,904 |
|
Nine Months Ended June 30, 2009 (Thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploration |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Corporate and |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
and |
|
|
|
|
|
|
Total Reportable |
|
|
|
|
|
|
Intersegment |
|
|
|
|
|
|
Utility |
|
|
Pipeline and Storage |
|
|
Production |
|
|
Energy Marketing |
|
|
Segments |
|
|
All Other |
|
|
Eliminations |
|
|
Total Consolidated |
|
|
Revenue from
External Customers |
|
$ |
1,009,962 |
|
|
$ |
105,904 |
|
|
$ |
281,410 |
|
|
$ |
350,445 |
|
|
$ |
1,747,721 |
|
|
$ |
30,523 |
|
|
$ |
675 |
|
|
$ |
1,778,919 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Intersegment Revenues |
|
$ |
13,339 |
|
|
$ |
62,026 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
75,365 |
|
|
$ |
3,890 |
|
|
$ |
(79,255 |
) |
|
$ |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment Profit: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income (Loss) |
|
$ |
60,303 |
|
|
$ |
41,582 |
|
|
$ |
(38,366 |
) |
|
$ |
7,509 |
|
|
$ |
71,028 |
|
|
$ |
(46 |
) |
|
$ |
2,728 |
|
|
$ |
73,710 |
|
Note 8 Intangible Assets
The components of the Companys intangible assets were as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
At September 30, |
|
|
|
At June 30, 2010 |
|
|
2009 |
|
|
|
Gross |
|
|
|
|
|
|
Net |
|
|
Net |
|
|
|
Carrying |
|
|
Accumulated |
|
|
Carrying |
|
|
Carrying |
|
|
|
Amount |
|
|
Amortization |
|
|
Amount |
|
|
Amount |
|
Intangible Assets Subject to Amortization: |
|
|
|
|
|
|
Long-Term Transportation Contracts |
|
$ |
4,701 |
|
|
$ |
(2,926 |
) |
|
$ |
1,775 |
|
|
$ |
2,071 |
|
Long-Term Gas Purchase Contracts |
|
|
31,864 |
|
|
|
(13,451 |
) |
|
|
18,413 |
|
|
|
19,465 |
|
|
|
|
|
|
|
|
|
$ |
36,565 |
|
|
$ |
(16,377 |
) |
|
$ |
20,188 |
|
|
$ |
21,536 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Aggregate Amortization Expense: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30, 2010 |
|
$ |
449 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30, 2009 |
|
$ |
497 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended June 30, 2010 |
|
$ |
1,348 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended June 30, 2009 |
|
$ |
1,547 |
|
|
|
|
|
|
|
|
|
|
|
|
|
The gross carrying amount of intangible assets subject to amortization at June 30, 2010
remained unchanged from September 30, 2009. 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 $0.1 million for the remainder of
2010 and $0.4 million annually for 2011, 2012, 2013 and 2014. Amortization expense for the
long-term gas purchase contracts is estimated to be $0.4 million for the remainder of 2010 and $1.4
million annually for 2011, 2012, 2013 and 2014.
-29-
Item 1. Financial Statements (Cont.)
Note 9 Retirement Plan and Other Post-Retirement Benefits
Components of Net Periodic Benefit Cost (in thousands):
Three months ended June 30,
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Retirement Plan |
|
|
Other Post-Retirement Benefits |
|
|
|
2010 |
|
|
2009 |
|
|
2010 |
|
|
2009 |
|
Service Cost |
|
$ |
3,249 |
|
|
$ |
2,728 |
|
|
$ |
1,075 |
|
|
$ |
950 |
|
Interest Cost |
|
|
11,077 |
|
|
|
11,709 |
|
|
|
6,254 |
|
|
|
6,875 |
|
Expected Return on Plan Assets |
|
|
(14,585 |
) |
|
|
(14,489 |
) |
|
|
(6,583 |
) |
|
|
(7,904 |
) |
Amortization of Prior Service Cost |
|
|
164 |
|
|
|
183 |
|
|
|
(427 |
) |
|
|
(268 |
) |
Amortization of Transition Amount |
|
|
|
|
|
|
|
|
|
|
135 |
|
|
|
566 |
|
Amortization of Losses |
|
|
5,410 |
|
|
|
1,419 |
|
|
|
6,470 |
|
|
|
2,318 |
|
Net Amortization and Deferral for |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Regulatory Purposes (Including |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volumetric Adjustments) (1) |
|
|
(920 |
) |
|
|
2,255 |
|
|
|
(569 |
) |
|
|
3,878 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Periodic Benefit Cost |
|
$ |
4,395 |
|
|
$ |
3,805 |
|
|
$ |
6,355 |
|
|
$ |
6,415 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine months ended June 30,
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Retirement Plan |
|
|
Other Post-Retirement Benefits |
|
|
|
2010 |
|
|
2009 |
|
|
2010 |
|
|
2009 |
|
Service Cost |
|
$ |
9,747 |
|
|
$ |
8,185 |
|
|
$ |
3,224 |
|
|
$ |
2,851 |
|
Interest Cost |
|
|
33,231 |
|
|
|
35,127 |
|
|
|
18,763 |
|
|
|
20,624 |
|
Expected Return on Plan Assets |
|
|
(43,756 |
) |
|
|
(43,468 |
) |
|
|
(19,751 |
) |
|
|
(23,711 |
) |
Amortization of Prior Service Cost |
|
|
492 |
|
|
|
548 |
|
|
|
(1,282 |
) |
|
|
(805 |
) |
Amortization of Transition Amount |
|
|
|
|
|
|
|
|
|
|
405 |
|
|
|
1,699 |
|
Amortization of Losses |
|
|
16,230 |
|
|
|
4,257 |
|
|
|
19,411 |
|
|
|
6,953 |
|
Net Amortization and Deferral for |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Regulatory Purposes (Including |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volumetric Adjustments) (1) |
|
|
2,896 |
|
|
|
12,853 |
|
|
|
2,919 |
|
|
|
16,232 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Periodic Benefit Cost |
|
$ |
18,840 |
|
|
$ |
17,502 |
|
|
$ |
23,689 |
|
|
$ |
23,843 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
The Companys policy is to record retirement plan and other post-retirement
benefit costs in the Utility segment on a volumetric basis to reflect the fact that the
Utility segment experiences higher throughput of natural gas in the winter months and lower
throughput of natural gas in the summer months. |
Prior to the adoption of authoritative guidance related to accounting for defined benefit
pension and other postretirement plans, 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
during fiscal 2009. As allowed by the authoritative guidance, these costs were calculated using
June 30, 2008 measurement date data. Three of those months pertained to the period of July 1, 2008
to September 30, 2008. The pension and other post-retirement benefit costs for that period
amounted to $3.8 million and were recorded by the Company during the nine months ended June 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 nine months ended June 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.
-30-
Item 1. Financial Statements (Cont.)
Employer Contributions. During the nine months ended June 30, 2010, the Company contributed $20.2
million to its tax-qualified, noncontributory defined-benefit retirement plan (Retirement Plan) and
$21.4 million to its VEBA trusts and 401 (h) accounts for its other post-retirement benefits. In
the remainder of 2010, the Company does not expect to contribute to the Retirement Plan. It is
likely that the Company will have to fund larger amounts to the Retirement Plan subsequent to
fiscal 2010 in order to be in compliance with the Pension Protection Act of 2006. In the
remainder of 2010, the Company expects to contribute approximately $4.1 million to its VEBA trusts
and 401(h) accounts.
-31-
Item 2. Managements Discussion and
Analysis of Financial Condition and Results of Operations
OVERVIEW
[Please note that this overview is primarily a high-level summary
of items that are discussed in greater detail in subsequent sections of this report.]
The Company is a diversified energy holding company that owns a number of subsidiary operating
companies, and reports financial results in four reportable business segments. For the quarter
ended June 30, 2010 compared to the quarter ended June 30, 2009, the Company experienced a decrease
in earnings of $0.3 million, primarily due to lower earnings in the Pipeline and Storage segment.
For the nine months ended June 30, 2010 compared to the nine months ended June 30, 2009, the
Company experienced an increase in earnings of $113.8 million. The earnings increase for the
nine-month period was driven largely by an impairment charge of $182.8 million ($108.2 million
after tax) recorded in the Exploration and Production segment during the nine months ended June 30,
2009 that did not recur during the nine months ended June 30, 2010. In the Companys Exploration
and Production segment, oil and gas property acquisitions, and 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, the
book value of the Companys oil and gas properties exceeded the ceiling, resulting in the
impairment charge mentioned above. For further discussion of the ceiling test results at June 30,
2010 and a sensitivity analysis to changes in crude oil and natural gas commodity prices, refer to
the Critical Accounting Estimates section below. For further discussion of the Companys earnings,
refer to the Results of Operations section below.
The Company continues to focus on the development of its Marcellus Shale acreage in the
Appalachian region of its Exploration and Production segment. The Marcellus Shale is a Middle
Devonian-age geological shale formation that is present, nearly a mile or more below the surface,
in the Appalachian region of the United States, including much of Pennsylvania and southern New
York. Due to the depth at which this formation is found, drilling and completion costs, including
the drilling and completion of horizontal wells with hydraulic fracturing, are very expensive.
However, independent geological studies have indicated that this formation could yield natural gas
reserves measured in the trillions of cubic feet. The Company owns approximately 738,000 net acres
within the Marcellus Shale area and anticipates a significant increase in its reserve base from
development in the Marcellus Shale. With this in mind, and with a natural desire to realize the
value of these assets in a responsible and orderly fashion, the Company has spent significant
amounts in this region. For the nine months ended June 30, 2010, the Company spent $217.6 million
towards the development of the Marcellus Shale. This included paying $71.8 million in March 2010
for two tracts of leasehold acreage in Tioga and Potter Counties in Pennsylvania. The Company
acquired these tracts, consisting of approximately 18,000 net acres, in order to expand its
holdings of Marcellus Shale acreage. These tracts are geologically and geographically similar to
the Companys existing Marcellus Shale acreage in the area, and will help the Company continue its
developmental drilling program.
Coincident with the development of its Marcellus Shale acreage, the Company is building
pipeline gathering and transmission facilities to connect Marcellus Shale production with existing
pipelines in the region and is pursuing the development of additional pipeline and storage capacity
in order to meet anticipated demand for the large amount of Marcellus Shale production expected to
come on-line in the months and years to come. Two of these projects, the Tioga County Extension
Project and the Northern Access expansion project, are considered significant for Empire and
Supply Corporation. Both projects are designed to receive natural gas produced from the Marcellus
Shale and transport it to Canada and the Northeast United States to meet growing demand in those
areas. During the past year, Empire and Supply Corporation have experienced a decline in the
volumes of natural gas received at the Canada/United States border at the Niagara River to be
shipped across their systems. The historical price advantage for gas sold at the Niagara import
points has declined as production in the Canadian producing regions has declined or been diverted
to other demand areas, and as production from new shale plays has increased in the United States.
These factors have been causing shippers to seek alternative gas supplies and consequently
alternative transportation routes. Empire and Supply Corporation have seen transportation volumes
decrease as a result of this situation. The Tioga County Extension Project and the Northern
Access expansion project are designed to provide an alternative gas supply source for the
customers of Empire and Supply Corporation. These projects, which are discussed more completely in
the Investing Cash Flow section that follows, also will involve significant capital expenditures.
-32-
Item 2. Managements Discussion and Analysis
of Financial Condition and Results of Operations (Cont.)
From a capital resources perspective, the Company has been able to meet its capital
expenditure needs for all of the above projects by using cash from operations. The Company had
$458.8 million in Cash and Temporary Cash Investments at June 30, 2010, as shown on the Companys
Consolidated Balance Sheet. For the remainder of 2010, the Company expects that it will be able to
use cash on hand and cash from operations as its first means of financing capital expenditures,
with short-term borrowings being its next source of funding. It is not expected that long-term
financing will be required to meet capital expenditure needs until 2011.
The possibility of environmental risks associated with a well completion technology referred
to as hydraulic fracturing continues to be debated. In Pennsylvania, where the Company is focusing
its Marcellus Shale development efforts, the permitting and regulatory processes seem to strike a
balance between the environmental concerns associated with hydraulic fracturing and the benefits of
increased natural gas production. Hydraulic fracturing is a well stimulation technique that has
been used for many years, and in the Companys experience, one that the Company believes has little
impact to the environment. Nonetheless, the potential for increased state or federal regulation of
hydraulic fracturing could impact future costs of drilling in the Marcellus Shale and lead to
operational delays or restrictions. There is also the risk that drilling could be prohibited on
certain acreage that is prospective for the Marcellus Shale. For example, New York State currently has a
moratorium on hydraulic fracturing of new horizontal wells in the Marcellus Shale. However, due to
the small amount of Marcellus Shale acreage owned by the Company in New York State, the moratorium
is not expected to have a significant impact on the Companys plans for Marcellus Shale
development. Please refer to the Risk Factors section of the Form 10-K for the year ended
September 30, 2009 as well as updates to that section in both the Form 10-Q for the quarter ended
December 31, 2009 and the Form 10-Q for the quarter ended March 31, 2010 for further discussion.
On July 16, 2010, the Company entered into an Asset Purchase and Sale Agreement whereby the
Company intends to sell its sawmill in Marienville, Pennsylvania and approximately 40 million board
feet of logs, lumber and timber consisting of yard inventory along with unexpired timber cutting
contracts and certain land and timber holdings designed to provide the purchaser with a supply of
logs for the mill. Despite this sale, the Company intends to retain substantially all of its land
and timber holdings, along with mineral rights on land to be sold. The Company will maintain a
forestry operation, however, as part of this change in focus, the Company will no longer be
processing lumber products. At closing, which is expected to occur in September 2010, the Company
estimates receiving proceeds of approximately $15 million. In addition, the purchaser will assume
approximately $7 million in payment obligations under the Companys timber cutting contracts with
various timber suppliers. The aforementioned supply of logs is expected to occur over a five-year
period, during which time the Company anticipates receiving up to an additional $10 million in
proceeds. The Company does not anticipate a material impact to earnings from this sale.
CRITICAL ACCOUNTING ESTIMATES
For a complete discussion of critical accounting estimates, refer to Critical Accounting
Estimates in Item 7 of the Companys 2009 Form 10-K and Item 2 of the Companys December 31, 2009
and March 31, 2010 Form 10-Qs. There have been no material changes to those disclosures other than
as set forth below. The information presented below is an update of, and should be read in
conjunction with, the critical accounting estimates in those documents.
Oil and Gas Exploration and Development Costs. The Company, in its Exploration and Production
segment, follows the full cost method of accounting for determining the book value of its oil and
natural gas properties. In accordance with this methodology, the Company is required to perform a
quarterly ceiling test. Under the ceiling test, the present value of future revenues from the
Companys oil and gas reserves based on current market prices (the ceiling) is compared with the
book value of the Companys oil and gas properties at the balance sheet date. If the book value of
the oil and gas properties exceeds the ceiling, a non-cash impairment charge must be recorded to
reduce the book value of the oil and gas properties to the calculated ceiling. At June 30, 2010,
the ceiling exceeded the book value of the oil and gas properties by approximately $231 million.
The quoted Cushing, Oklahoma spot price for West Texas Intermediate oil at June 30, 2010 was $75.59
per Bbl. The quoted Henry Hub spot price for natural gas at June 30, 2010 was $4.68 per MMBtu.
(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
-33-
Item 2. Managements Discussion and Analysis of Financial Condition and Results of Operations
(Cont.)
ceiling, rather than the Cushing oil and Henry Hub natural gas prices, which are only indicative of
current prices.) If natural gas prices used in the ceiling test calculation at June 30, 2010 had
been $1 per MMBtu lower, the ceiling would have exceeded the book value of the Companys oil and
gas properties by approximately $168 million. If crude oil prices used in the ceiling test
calculation at June 30, 2010 had been $5 per Bbl lower, the ceiling would have exceeded the book
value of the Companys oil and gas properties by approximately $183 million. If both natural gas
and crude oil prices used in the ceiling test calculation at June 30, 2010 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 $120 million. These calculated amounts are based solely on
price changes and do not take into account any other changes to the ceiling test calculation. For
a more complete discussion of the full cost method of accounting, refer to Oil and Gas Exploration
and Development Costs under Critical Accounting Estimates in Item 7 of the Companys 2009 Form
10-K.
RESULTS OF OPERATIONS
Earnings
The Companys earnings were $42.6 million for the quarter ended June 30, 2010 compared to
earnings of $42.9 million for the quarter ended June 30, 2009. The decrease in earnings of $0.3
million is a result of lower earnings in the Pipeline and Storage segment and a loss in the
Corporate category. Higher earnings in the Exploration and Production, Utility and Energy
Marketing segments and the All Other category partially offset these decreases.
The Companys earnings were $187.5 million for the nine months ended June 30, 2010 compared to
earnings of $73.7 million for the nine months ended June 30, 2009. The increase in earnings of
$113.8 million is primarily the result of higher earnings in the Exploration and Production
segment. The Utility and Energy Marketing segments, as well as the All Other category, also
contributed to the increase in earnings. Lower earnings in the Pipeline and Storage segment and a
loss in the Corporate category slightly offset these increases. The Companys earnings for the
nine months ended June 30, 2009 includes 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.
Additional discussion of earnings in each of the business segments can be found in the
business segment information that follows. Note that all amounts used in the earnings discussions
are after-tax amounts, unless otherwise noted.
Earnings (Loss) by Segment
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Nine Months Ended |
|
|
|
June 30, |
|
|
June 30, |
|
|
|
|
|
|
|
|
|
|
|
Increase |
|
|
|
|
|
|
|
|
|
|
Increase |
|
(Thousands) |
|
2010 |
|
|
2009 |
|
|
(Decrease) |
|
|
2010 |
|
|
2009 |
|
|
(Decrease) |
|
Utility |
|
$ |
5,969 |
|
|
$ |
5,396 |
|
|
$ |
573 |
|
|
$ |
62,254 |
|
|
$ |
60,303 |
|
|
$ |
1,951 |
|
Pipeline and Storage |
|
|
7,234 |
|
|
|
9,221 |
|
|
|
(1,987 |
) |
|
|
30,036 |
|
|
|
41,582 |
|
|
|
(11,546 |
) |
Exploration and Production |
|
|
27,883 |
|
|
|
27,083 |
|
|
|
800 |
|
|
|
85,046 |
|
|
|
(38,366 |
) |
|
|
123,412 |
|
Energy Marketing |
|
|
1,411 |
|
|
|
1,331 |
|
|
|
80 |
|
|
|
8,472 |
|
|
|
7,509 |
|
|
|
963 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Reportable Segments |
|
|
42,497 |
|
|
|
43,031 |
|
|
|
(534 |
) |
|
|
185,808 |
|
|
|
71,028 |
|
|
|
114,780 |
|
All Other |
|
|
186 |
|
|
|
(1,086 |
) |
|
|
1,272 |
|
|
|
2,925 |
|
|
|
(46 |
) |
|
|
2,971 |
|
Corporate |
|
|
(98 |
) |
|
|
959 |
|
|
|
(1,057 |
) |
|
|
(1,221 |
) |
|
|
2,728 |
|
|
|
(3,949 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Consolidated |
|
$ |
42,585 |
|
|
$ |
42,904 |
|
|
$ |
(319 |
) |
|
$ |
187,512 |
|
|
$ |
73,710 |
|
|
$ |
113,802 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
-34-
Item 2. Managements Discussion and Analysis of Financial Condition and Results of Operations
(Cont.)
Utility
Utility Operating Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Nine Months Ended |
|
|
|
June 30, |
|
|
June 30, |
|
|
|
|
|
|
|
|
|
|
|
Increase |
|
|
|
|
|
|
|
|
|
|
Increase |
|
(Thousands) |
|
2010 |
|
|
2009 |
|
|
(Decrease) |
|
|
2010 |
|
|
2009 |
|
|
(Decrease) |
|
Retail Sales Revenues: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Residential |
|
$ |
88,158 |
|
|
$ |
119,746 |
|
|
$ |
(31,588 |
) |
|
$ |
521,202 |
|
|
$ |
786,170 |
|
|
$ |
(264,968 |
) |
Commercial |
|
|
10,721 |
|
|
|
15,627 |
|
|
|
(4,906 |
) |
|
|
73,438 |
|
|
|
122,197 |
|
|
|
(48,759 |
) |
Industrial |
|
|
696 |
|
|
|
808 |
|
|
|
(112 |
) |
|
|
4,579 |
|
|
|
6,835 |
|
|
|
(2,256 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
99,575 |
|
|
|
136,181 |
|
|
|
(36,606 |
) |
|
|
599,219 |
|
|
|
915,202 |
|
|
|
(315,983 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Transportation |
|
|
20,909 |
|
|
|
22,012 |
|
|
|
(1,103 |
) |
|
|
92,112 |
|
|
|
94,951 |
|
|
|
(2,839 |
) |
Off-System Sales |
|
|
5,486 |
|
|
|
|
|
|
|
5,486 |
|
|
|
20,491 |
|
|
|
3,740 |
|
|
|
16,751 |
|
Other |
|
|
3,009 |
|
|
|
3,057 |
|
|
|
(48 |
) |
|
|
8,816 |
|
|
|
9,408 |
|
|
|
(592 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
128,979 |
|
|
$ |
161,250 |
|
|
$ |
(32,271 |
) |
|
$ |
720,638 |
|
|
$ |
1,023,301 |
|
|
$ |
(302,663 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Utility Throughput
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Nine Months Ended |
|
|
|
June 30, |
|
|
June 30, |
|
|
|
|
|
|
|
|
|
|
|
Increase |
|
|
|
|
|
|
|
|
|
|
Increase |
|
(MMcf) |
|
2010 |
|
|
2009 |
|
|
(Decrease) |
|
|
2010 |
|
|
2009 |
|
|
(Decrease) |
|
Retail Sales: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Residential |
|
|
7,055 |
|
|
|
8,468 |
|
|
|
(1,413 |
) |
|
|
50,292 |
|
|
|
55,001 |
|
|
|
(4,709 |
) |
Commercial |
|
|
920 |
|
|
|
1,221 |
|
|
|
(301 |
) |
|
|
7,666 |
|
|
|
8,984 |
|
|
|
(1,318 |
) |
Industrial |
|
|
66 |
|
|
|
55 |
|
|
|
11 |
|
|
|
512 |
|
|
|
499 |
|
|
|
13 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
8,041 |
|
|
|
9,744 |
|
|
|
(1,703 |
) |
|
|
58,470 |
|
|
|
64,484 |
|
|
|
(6,014 |
) |
Transportation |
|
|
10,530 |
|
|
|
10,747 |
|
|
|
(217 |
) |
|
|
51,957 |
|
|
|
52,476 |
|
|
|
(519 |
) |
Off-System Sales |
|
|
1,124 |
|
|
|
|
|
|
|
1,124 |
|
|
|
4,034 |
|
|
|
513 |
|
|
|
3,521 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
19,695 |
|
|
|
20,491 |
|
|
|
(796 |
) |
|
|
114,461 |
|
|
|
117,473 |
|
|
|
(3,012 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Degree Days
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Percent Colder |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Warmer) Than |
|
Three Months Ended June 30 |
|
Normal |
|
|
2010 |
|
|
2009 |
|
|
Normal (1) |
|
|
Prior Year (1) |
|
Buffalo |
|
|
927 |
|
|
|
665 |
|
|
|
854 |
|
|
|
(28.3 |
) |
|
|
(22.1 |
) |
Erie |
|
|
885 |
|
|
|
631 |
|
|
|
821 |
|
|
|
(28.7 |
) |
|
|
(23.1 |
) |
Nine Months Ended
June 30 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Buffalo |
|
|
6,514 |
|
|
|
6,152 |
|
|
|
6,558 |
|
|
|
(5.6 |
) |
|
|
(6.2 |
) |
Erie |
|
|
6,108 |
|
|
|
5,842 |
|
|
|
6,064 |
|
|
|
(4.4 |
) |
|
|
(3.7 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Percents compare actual 2010 degree days to normal degree days and actual 2010
degree days to actual 2009 degree days. |
2010 Compared with 2009
Operating revenues for the Utility segment decreased $32.3 million for the quarter ended June
30, 2010 as compared with the quarter ended June 30, 2009. This decrease largely resulted from a
$36.6 million decrease in retail gas sales revenues and a $1.1 million decrease in transportation
revenues, partially offset by a $5.5 million increase in off-system sales revenues. The decrease in
retail gas sales revenues of $36.6 million was largely a function of warmer weather and slightly
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 lower cost of purchased gas combined
with the refunding of previously over-recovered purchased gas
-35-
Item 2. Managements Discussion and Analysis of Financial Condition and Results of Operations
(Cont.)
costs. The Utility segments average cost of purchased gas, including the cost of transportation
and storage, was $6.70 per Mcf for the quarter ended June 30, 2010, a decrease of 2.6% from the
average cost of $6.88 per Mcf for the quarter ended June 30, 2009. The decrease in transportation
revenues of $1.1 million was primarily due to a 0.2 Bcf decrease in transportation throughput,
largely the result of warmer weather.
The increase in off-system sales revenues of $5.5 million was largely due to the Utility
segment not engaging in off-system sales from November 2008 through October 2009. This was due to
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 FERC standards of
conduct. In light of and in reliance on this clarification, Distribution Corporation determined
that it could resume engaging in off-system sales on non-affiliated pipelines. Such off-system
sales resumed in November 2009. Due to profit sharing with retail customers, the margins resulting
from off-system sales are minimal and there was not a material impact to earnings.
Operating revenues for the Utility segment decreased $302.7 million for the nine months ended
June 30, 2010 as compared with the nine months ended June 30, 2009. This decrease largely resulted
from a $316.0 million decrease in retail gas sales revenues and a $2.8 million decrease in
transportation revenues, partially offset by a $16.8 million increase in off-system sales revenues.
The decrease in retail gas sales revenues of $316.0 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) and warmer weather. The recovery of lower gas costs resulted from a lower cost of
purchased gas combined with the refunding of previously over-recovered purchased gas costs. The
Utility segments average cost of purchased gas, including the cost of transportation and storage,
was $7.16 per Mcf for the nine months ended June 30, 2010, a decrease of 16.1% from the average
cost of $8.53 per Mcf for the nine months ended June 30, 2009. The decrease in transportation
revenues of $2.8 million was primarily due to a 0.5 Bcf decrease in transportation throughput,
largely the result of warmer weather. The increase in off-system sales revenues of $16.8 million
was attributable to the reasons discussed above. Due to profit sharing with retail customers, the
margins resulting from off-system sales are minimal and there was not a material impact to
earnings.
The Utility segments earnings for the quarter ended June 30, 2010 were $6.0 million, an
increase of $0.6 million when compared with earnings of $5.4 million for the quarter ended June 30,
2009.
In the New York jurisdiction, earnings increased $0.4 million. The positive earnings impact
associated with lower interest expense ($0.9 million) and lower income tax expense of $0.2 million
(due to a lower effective tax rate) were partially offset by higher operating expenses of $0.7
million (primarily due to higher personnel costs, partially offset by a decrease in bad debt
expense due to lower gas costs). The decrease in interest expense was primarily due to a decrease
in storage inventory carrying costs caused by a decline in the net storage inventory balances as
well as a decline in interest rates.
In the Pennsylvania jurisdiction, earnings increased $0.2 million. The positive earnings
impact associated with a decrease in income tax expense of $1.7 million (primarily relating to
additional tax-deductible repairs) and lower operating expenses of $0.1 million (primarily a
decrease in bad debt expense due to lower gas costs) was partially offset by the negative earnings
impact of warmer weather ($0.9 million) and higher interest expense on deferred gas costs ($0.5
million), largely due to an over-recovery of gas costs during fiscal 2009 (due to a decline in gas
prices during fiscal 2009).
The impact of weather variations on earnings in the New York jurisdiction is mitigated by that
jurisdictions weather normalization clause (WNC). The WNC in New York, which covers the
eight-month period from October through May, has had a stabilizing effect on earnings for the New
York rate jurisdiction. For the quarter ended June 30, 2010, the WNC preserved earnings of
approximately $1.0 million, as weather was warmer than normal for the period. For the quarter
ended June 30, 2009, the WNC preserved earnings of approximately $0.4 million, as weather was
warmer than normal for the period.
-36-
Item 2. Managements Discussion and Analysis of Financial Condition and Results of Operations
(Cont.)
The Utility segments earnings for the nine months ended June 30, 2010 were $62.3 million, an
increase of $2.0 million when compared with earnings of $60.3 million for the nine months ended
June 30, 2009.
In the New York jurisdiction, earnings decreased $0.1 million. The positive earnings impact
associated with lower operating expenses of $0.5 million (primarily a decrease in bad debt expense
due to lower gas costs) and lower income tax expense of $0.4 million (due to a lower effective tax
rate) were more than offset by an increase in interest expense ($0.5 million) and routine
regulatory true-up adjustments ($0.9 million).
In the Pennsylvania jurisdiction, earnings increased $2.1 million. The positive earnings
impact associated with a decrease in income tax expense of $5.0 million (primarily relating to
additional tax-deductible repairs) and lower operating expenses of $3.2 million (primarily a
decrease in bad debt expense due to lower gas costs) were the main factors in the earnings
increase. These factors were partially offset by lower usage per account ($2.1 million), warmer
weather ($0.9 million), routine regulatory true-up adjustments ($0.2 million), and higher interest
expense ($2.3 million). The phrase usage per account refers to average gas consumption per
account after factoring out any impact that weather may have had on consumption. The increase in
interest expense was partially due to the Companys April 2009 debt issuance that was issued at a
significantly higher interest rate than the debt that had matured in March 2009. In addition,
accrued interest on deferred gas costs increased as a result of an over-recovery of gas costs
during fiscal 2009 (due to a decline in gas prices during fiscal 2009).
For the nine months ended June 30, 2010, the WNC in the New York jurisdiction preserved
earnings of approximately $1.3 million, as weather was warmer than normal. For the nine months
ended June 30, 2009, the WNC reduced earnings by approximately $0.2 million, as weather was colder
than normal.
Pipeline and Storage
Pipeline and Storage Operating Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Nine Months Ended |
|
|
|
June 30, |
|
|
June 30, |
|
|
|
|
|
|
|
|
|
|
|
Increase |
|
|
|
|
|
|
|
|
|
|
Increase |
|
(Thousands) |
|
2010 |
|
|
2009 |
|
|
(Decrease) |
|
|
2010 |
|
|
2009 |
|
|
(Decrease) |
|
Firm Transportation |
|
$ |
32,205 |
|
|
$ |
32,894 |
|
|
$ |
(689 |
) |
|
$ |
106,926 |
|
|
$ |
105,931 |
|
|
$ |
995 |
|
Interruptible Transportation |
|
|
618 |
|
|
|
635 |
|
|
|
(17 |
) |
|
|
1,458 |
|
|
|
2,862 |
|
|
|
(1,404 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
32,823 |
|
|
|
33,529 |
|
|
|
(706 |
) |
|
|
108,384 |
|
|
|
108,793 |
|
|
|
(409 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Firm Storage Service |
|
|
16,646 |
|
|
|
16,648 |
|
|
|
(2 |
) |
|
|
50,032 |
|
|
|
50,101 |
|
|
|
(69 |
) |
Interruptible Storage Service |
|
|
19 |
|
|
|
4 |
|
|
|
15 |
|
|
|
78 |
|
|
|
18 |
|
|
|
60 |
|
Other |
|
|
2,064 |
|
|
|
643 |
|
|
|
1,421 |
|
|
|
9,355 |
|
|
|
9,018 |
|
|
|
337 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
51,552 |
|
|
$ |
50,824 |
|
|
$ |
728 |
|
|
$ |
167,849 |
|
|
$ |
167,930 |
|
|
$ |
(81 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pipeline and Storage Throughput
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Nine Months Ended |
|
|
|
June 30, |
|
|
June 30, |
|
|
|
|
|
|
|
|
|
|
|
Increase |
|
|
|
|
|
|
|
|
|
|
Increase |
|
(MMcf) |
|
2010 |
|
|
2009 |
|
|
(Decrease) |
|
|
2010 |
|
|
2009 |
|
|
(Decrease) |
|
Firm Transportation |
|
|
52,448 |
|
|
|
60,798 |
|
|
|
(8,350 |
) |
|
|
245,233 |
|
|
|
296,524 |
|
|
|
(51,291 |
) |
Interruptible Transportation |
|
|
1,016 |
|
|
|
501 |
|
|
|
515 |
|
|
|
3,575 |
|
|
|
3,375 |
|
|
|
200 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
53,464 |
|
|
|
61,299 |
|
|
|
(7,835 |
) |
|
|
248,808 |
|
|
|
299,899 |
|
|
|
(51,091 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010 Compared with 2009
Operating revenues for the Pipeline and Storage segment increased $0.7 million in the quarter
ended June 30, 2010 as compared with the quarter ended June 30, 2009. The increase was primarily
due to an increase in efficiency gas revenues ($1.0 million) reported as part of other revenues in
the table above. This increase was primarily due to higher gas prices and higher efficiency gas
volumes during the quarter ended
-37-
Item 2. Managements Discussion and Analysis of Financial Condition and Results of Operations
(Cont.)
June 30, 2010 as compared with the quarter ended June 30, 2009. Under Supply Corporations tariff
with shippers, Supply Corporation is allowed to retain a set percentage of shipper-supplied gas to
cover compressor fuel costs and for 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 buyers on the open market. The excess gas
that is retained as inventory, as well as any gains resulting from the sale of such inventory,
represent efficiency gas revenue to Supply Corporation. This increase was partially offset by a
decrease in transportation revenues of $0.7 million due to a reduction in the level of short-term
contracts entered into by shippers quarter over quarter as such shippers utilized lower priced
routes.
Operating revenues for the Pipeline and Storage segment for the nine months ended June 30,
2010 decreased $0.1 million as compared with the nine months ended June 30, 2009. The decrease was
due to a decrease in interruptible transportation revenues of $1.4 million largely due to a
decrease in the gathering rate under Supply Corporations tariff. Offsetting the decrease was an
increase in firm transportation revenues of $1.0 million. This increase was primarily the result
of higher revenues from the Empire Connector, which was placed in service in December 2008,
partially offset by shippers utilizing lower priced routes as discussed above. Also offsetting the
decrease was an increase in efficiency gas revenues of $0.6 million due to higher efficiency gas
volumes and the non-recurrence of an efficiency gas inventory write down which occurred during the
nine months ended June 30, 2009. These increases to efficiency gas revenues were partially offset
by lower gas prices and a lower gain, period over period, on the sale of retained efficiency gas
volumes held in inventory.
Transportation volume for the quarter ended June 30, 2010 decreased by 7.8 Bcf from the prior
years quarter. For the nine months ended June 30, 2010, transportation volumes decreased by 51.1
Bcf from the prior years nine-month period. These decreases were largely due to shippers seeking
alternative lower priced gas supply (and in some cases, not renewing short-term transportation
contracts) combined with warmer weather and lower industrial demand. The reason shippers are
seeking lower priced gas supply is primarily because of the relatively higher price of Canadian
natural gas supplies available at the United States/Canadian border at the Niagara River near
Buffalo, New York compared to the lower pricing for domestic supplies. Empires proposed Tioga
County Extension Project and Supply Corporations Northern Access expansion project, both of
which are discussed in the Investing Cash Flow section that follows, are designed to utilize that
available pipeline capacity by receiving natural gas produced from the Marcellus Shale and
transporting it to Canada and the Northeast United States where demand has been growing. Much of
the impact of lower volumes is offset by the straight fixed-variable rate design utilized by Supply
Corporation and Empire. However, this rate design does not protect Supply Corporation or Empire in
situations where shippers do not renew their existing contracts and new shippers do not contract
for that capacity at the same quantity and rate. In that situation, Supply Corporation or Empire
can propose revised rates and services in a rate case at the FERC.
The Pipeline and Storage segments earnings for the quarter ended June 30, 2010 were $7.2
million, a decrease of $2.0 million when compared with earnings of $9.2 million for the quarter
ended June 30, 2009. The earnings decrease was due to the earnings impact of lower transportation
revenues of $0.5 million, as discussed above, combined with higher property taxes ($0.5 million),
higher operating expenses ($1.1 million) and lower interest income ($0.3 million). The increase
in property taxes is primarily a result of additional property taxes and higher payments in lieu
of taxes associated with the Empire Connector. The increase in operating expenses can primarily
be attributed to higher pension expense, higher personnel costs, the recording of gas losses
related to one of Supply Corporations storage wells and an increase in the reserve for
preliminary project costs associated with Supply Corporations West-to-East Overbeck to Leidy
project. These operating expense increases (totaling $2.5 million) were partly offset by the
reversal of reserves for preliminary project costs associated with Empires Tioga County Extension
Project and Supply Corporations Line N Expansion Project (totaling $1.4 million) since the
Company has determined that it is highly probable that the projects will be built. Refer to the
Investing Cash Flow section that follows for further discussion of the reversal of these reserves.
The reserve reversal also includes costs associated with the relocation of the existing Line N.
The decline in interest income is a result of lower interest rates. The earnings decreases were
partially offset by the earnings impact associated with higher efficiency gas revenue of $0.6
million, as discussed above.
-38-
Item 2. Managements Discussion and Analysis of Financial Condition and Results of Operations
(Cont.)
The Pipeline and Storage segments earnings for the nine months ended June 30, 2010 were
$30.0 million, a decrease of $11.6 million when compared with earnings of $41.6 million for the
nine months ended June 30, 2009. The decrease in earnings is primarily due to a decrease in the
allowance for funds used during construction ($2.8 million), higher operating costs ($3.3
million), higher property taxes ($1.6 million), higher interest expense ($3.2 million) and lower
interest income ($0.5 million). Lower transportation revenues of $0.3 million, as discussed
above, also contributed to the earnings decrease. The decrease in allowance for funds used
during construction (equity component) is a result of the construction of the Empire Connector,
which was completed and placed in service on December 10, 2008. The increase in operating
expenses can primarily be attributed to higher pension expense, higher personnel costs, and an
increase in the reserve for preliminary project costs associated with Supply Corporations
West-to-East Overbeck to Leidy project. The reversal of reserves for preliminary project costs
associated with Empires Tioga County Extension Project and Supply Corporations Line N Expansion
Project and relocation of Line N discussed above did not have a significant impact on earnings for
the nine months ended June 30, 2010 as substantially all of the preliminary project costs related
to the reserve reversals were incurred during the nine months ended June 30, 2010. The increase
in property taxes is primarily a result of additional property taxes and higher payments in lieu
of taxes associated with the Empire Connector. The increase in interest expense can be attributed
to higher debt balances and a higher average interest rate on borrowings combined with a decrease
in the allowance for borrowed funds used during construction resulting from the completion of the
Empire Connector. The increase in the average interest rate stems from the Companys April 2009
debt issuance. The decline in interest income is a result of lower cash balances and lower
interest rates. The earnings decreases were partially offset by the earnings impact associated
with higher efficiency gas revenue of $0.4 million, as discussed above.
Exploration and Production
Exploration and Production Operating Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Nine Months Ended |
|
|
|
June 30, |
|
|
June 30, |
|
|
|
|
|
|
|
|
|
|
|
Increase |
|
|
|
|
|
|
|
|
|
|
Increase |
|
(Thousands) |
|
2010 |
|
|
2009 |
|
|
(Decrease) |
|
|
2010 |
|
|
2009 |
|
|
(Decrease) |
|
Gas (after Hedging) |
|
$ |
48,381 |
|
|
$ |
38,450 |
|
|
$ |
9,931 |
|
|
$ |
135,761 |
|
|
$ |
118,345 |
|
|
$ |
17,416 |
|
Oil (after Hedging) |
|
|
60,891 |
|
|
|
56,690 |
|
|
|
4,201 |
|
|
|
183,800 |
|
|
|
156,340 |
|
|
|
27,460 |
|
Gas Processing Plant |
|
|
7,207 |
|
|
|
5,380 |
|
|
|
1,827 |
|
|
|
22,078 |
|
|
|
18,785 |
|
|
|
3,293 |
|
Other |
|
|
218 |
|
|
|
270 |
|
|
|
(52 |
) |
|
|
380 |
|
|
|
717 |
|
|
|
(337 |
) |
Intrasegment Elimination (1) |
|
|
(3,895 |
) |
|
|
(3,171 |
) |
|
|
(724 |
) |
|
|
(13,707 |
) |
|
|
(12,777 |
) |
|
|
(930 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
112,802 |
|
|
$ |
97,619 |
|
|
$ |
15,183 |
|
|
$ |
328,312 |
|
|
$ |
281,410 |
|
|
$ |
46,902 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Represents the elimination of certain West Coast gas production included in
Gas (after Hedging) in the table above that was 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. |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Nine Months Ended |
|
|
|
June 30, |
|
|
June 30, |
|
|
|
|
|
|
|
|
|
|
|
Increase |
|
|
|
|
|
|
|
|
|
|
Increase |
|
Production Volumes |
|
2010 |
|
|
2009 |
|
|
(Decrease) |
|
|
2010 |
|
|
2009 |
|
|
(Decrease) |
|
Gas Production (MMcf) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gulf Coast |
|
|
2,745 |
|
|
|
3,307 |
|
|
|
(562 |
) |
|
|
8,079 |
|
|
|
7,118 |
|
|
|
961 |
|
West Coast |
|
|
940 |
|
|
|
1,014 |
|
|
|
(74 |
) |
|
|
2,866 |
|
|
|
3,063 |
|
|
|
(197 |
) |
Appalachia |
|
|
4,741 |
|
|
|
2,155 |
|
|
|
2,586 |
|
|
|
11,084 |
|
|
|
6,065 |
|
|
|
5,019 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Production |
|
|
8,426 |
|
|
|
6,476 |
|
|
|
1,950 |
|
|
|
22,029 |
|
|
|
16,246 |
|
|
|
5,783 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil Production
(Mbbl) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gulf Coast |
|
|
135 |
|
|
|
176 |
|
|
|
(41 |
) |
|
|
389 |
|
|
|
470 |
|
|
|
(81 |
) |
West Coast |
|
|
661 |
|
|
|
654 |
|
|
|
7 |
|
|
|
2,007 |
|
|
|
1,984 |
|
|
|
23 |
|
Appalachia |
|
|
13 |
|
|
|
14 |
|
|
|
(1 |
) |
|
|
34 |
|
|
|
41 |
|
|
|
(7 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Production |
|
|
809 |
|
|
|
844 |
|
|
|
(35 |
) |
|
|
2,430 |
|
|
|
2,495 |
|
|
|
(65 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
-39-
Item 2. Managements Discussion and Analysis of Financial
Condition and Results of Operations (Cont.)
Average Prices
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Nine Months Ended |
|
|
|
June 30, |
|
|
June 30, |
|
|
|
|
|
|
|
|
|
|
|
Increase |
|
|
|
|
|
|
|
|
|
|
Increase |
|
|
|
2010 |
|
|
2009 |
|
|
(Decrease) |
|
|
2010 |
|
|
2009 |
|
|
(Decrease) |
|
Average Gas Price/Mcf |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gulf Coast |
|
$ |
4.95 |
|
|
$ |
3.95 |
|
|
$ |
1.00 |
|
|
$ |
5.26 |
|
|
$ |
4.90 |
|
|
$ |
0.36 |
|
West Coast |
|
$ |
4.38 |
|
|
$ |
3.04 |
|
|
$ |
1.34 |
|
|
$ |
4.92 |
|
|
$ |
4.10 |
|
|
$ |
0.82 |
|
Appalachia |
|
$ |
4.45 |
|
|
$ |
4.11 |
|
|
$ |
0.34 |
|
|
$ |
5.10 |
|
|
$ |
6.06 |
|
|
$ |
(0.96 |
) |
Weighted Average |
|
$ |
4.61 |
|
|
$ |
3.86 |
|
|
$ |
0.75 |
|
|
$ |
5.13 |
|
|
$ |
5.18 |
|
|
$ |
(0.05 |
) |
Weighted Average After Hedging |
|
$ |
5.74 |
|
|
$ |
5.94 |
|
|
$ |
(0.20 |
) |
|
$ |
6.16 |
|
|
$ |
7.28 |
|
|
$ |
(1.12 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Oil Price/Bbl |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gulf Coast |
|
$ |
76.42 |
|
|
$ |
56.29 |
|
|
$ |
20.13 |
|
|
$ |
78.64 |
|
|
$ |
50.64 |
|
|
$ |
28.00 |
|
West Coast |
|
$ |
71.92 |
|
|
$ |
55.77 |
|
|
$ |
16.15 |
|
|
$ |
71.79 |
|
|
$ |
46.84 |
|
|
$ |
24.95 |
|
Appalachia |
|
$ |
74.90 |
|
|
$ |
48.93 |
|
|
$ |
25.97 |
|
|
$ |
77.77 |
|
|
$ |
54.90 |
|
|
$ |
22.87 |
|
Weighted Average |
|
$ |
72.72 |
|
|
$ |
55.77 |
|
|
$ |
16.95 |
|
|
$ |
72.97 |
|
|
$ |
47.69 |
|
|
$ |
25.28 |
|
Weighted Average After Hedging |
|
$ |
75.23 |
|
|
$ |
67.19 |
|
|
$ |
8.04 |
|
|
$ |
75.65 |
|
|
$ |
62.67 |
|
|
$ |
12.98 |
|
2010 Compared with 2009
Operating revenues for the Exploration and Production segment increased $15.2 million for the
quarter ended June 30, 2010 as compared with the quarter ended June 30, 2009. Oil production
revenue after hedging increased $4.2 million. An increase in the weighted average price of oil
after hedging ($8.04 per Bbl) was the primary cause, as oil production levels were slightly lower
quarter over quarter. Gas production revenue after hedging increased $9.9 million. An increase in
Appalachian natural gas production was partially offset by lower Gulf Coast production and a $0.20
per Mcf decrease in the weighted average price of gas after hedging. The increase in Appalachian
production was primarily due to higher production from Marcellus Shale wells. Production from
existing Gulf Coast properties continued its general decline and there was no production from new
fields during the quarter ended June 30, 2010 as compared to the quarter ended June 30, 2009 to
offset that decline. The decline in Gulf Coast production reflects the Companys decision to
de-emphasize Gulf Coast production and place more emphasis on Marcellus Shale production in the
Appalachian region.
Operating revenues for the Exploration and Production segment increased $46.9 million for the
nine months ended June 30, 2010 as compared with the nine months ended June 30, 2009. Oil
production revenue after hedging increased $27.5 million. An increase in the weighted average
price of oil after hedging ($12.98 per Bbl) was the primary cause, as oil production levels were
slightly lower period over period. Gas production revenue after hedging increased $17.4 million.
Increases in Gulf Coast and Appalachian production were partially offset by a $1.12 per Mcf
decrease in the weighted average price of gas after hedging. The increase in Gulf Coast production
resulted from a new discovery (Cyclops) that came on-line late in the quarter ended March 31, 2009,
which more than offset the decline in production from existing fields. The increase in Appalachian
production is mainly due to Marcellus Shale production that came on-line during the nine months
ended June 30, 2010.
The Exploration and Production segments earnings for the quarter ended June 30, 2010 were
$27.9 million, an increase of $0.8 million when compared with earnings of $27.1 million for the
quarter ended June 30, 2009. Higher crude oil prices and higher natural gas production increased
earnings by $4.2 million and $7.5 million, respectively. In addition, higher processing plant
revenues ($0.7 million) largely due to an increase in the commodity prices of residual gas and
liquids sold at Senecas processing plants in the West Coast region further contributed to an
increase in earnings. Decreased interest expense ($0.4 million) due to the capitalization of
interest on unproved properties (as a result of the Companys increased emphasis in developing
assets in the Marcellus Shale) also contributed to the earnings increase. Lower crude oil
production ($1.5 million) and lower natural gas prices ($1.1 million) partially offset the increase
in earnings. In addition, the earnings increases noted above were mostly offset by higher
depletion expense ($3.6 million), higher lease operating expenses ($3.1 million), the
earnings impact associated with higher income tax
-40-
Item 2. Managements Discussion and Analysis of Financial Condition and Results of Operations
(Cont.)
expense ($1.7 million), and higher general and administrative and other operating expenses ($1.0
million). The increase in depletion expense was primarily due to an increase in production and
depletable base (largely due to increased capital spending in the Appalachian region). The
increase in lease operating expenses was largely due to higher steaming costs in California,
additional production properties related to the acquisition of Ivanhoe Energys United States oil
and gas properties in July 2009, and an increase in the costs associated with a higher number of
production properties in Appalachia. The increase in general and administrative and other
operating expenses is mainly due to higher personnel costs (specifically in the Appalachian
region).
The Exploration and Production segments earnings for the nine months ended June 30, 2010 were
$85.0 million, compared with a loss of $38.4 million for the nine months ended June 30, 2009, an
increase of $123.4 million. The increase in earnings is primarily the result of the non-recurrence
of an impairment charge of $108.2 million during the quarter ended December 31, 2008, as discussed
in the Overview section above. Higher crude oil prices and higher natural gas production increased
earnings by $20.5 million and $27.4 million, respectively. Higher processing plant revenues ($1.5
million) largely due to an increase in the commodity prices of residual gas and liquids sold at
Senecas processing plants in the West Coast region further contributed to an increase in earnings.
In addition, lower interest expense ($1.6 million) due to a lower average amount of debt
outstanding and the capitalization of interest, discussed above, further contributed to an increase
in earnings. Lower crude oil production ($2.6 million) and lower natural gas prices ($16.1
million) partially offset the increase in earnings. In addition, the earnings increases noted
above were partially offset by higher depletion expense ($7.5 million), higher lease operating
expenses ($4.6 million), the earnings impact associated with higher income tax expense ($2.7
million), lower interest income ($1.1 million), and higher general and administrative and other
operating expenses ($0.9 million). The increase in depletion expense was primarily due to an
increase in production and depletable base (largely due to increased capital spending in the
Appalachian region). The increase in lease operating expenses was largely due to higher steaming
costs in California, additional production properties related to the acquisition of Ivanhoe
Energys United States oil and gas properties in July 2009, and an increase in the costs associated
with a higher number of production properties in Appalachia. The decrease in interest income is
primarily due to lower interest rates on cash investment balances. The increase in general and
administrative and other operating expenses is mainly due to higher personnel costs (specifically
in the Appalachian region).
Energy Marketing
Energy Marketing Operating Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Nine Months Ended |
|
|
|
June 30, |
|
|
June 30, |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase |
|
(Thousands) |
|
2010 |
|
|
2009 |
|
|
Increase |
|
|
2010 |
|
|
2009 |
|
|
(Decrease) |
|
Natural Gas (after Hedging) |
|
$ |
72,759 |
|
|
$ |
71,870 |
|
|
$ |
889 |
|
|
$ |
302,931 |
|
|
$ |
350,331 |
|
|
$ |
(47,400 |
) |
Other |
|
|
71 |
|
|
|
24 |
|
|
|
47 |
|
|
|
172 |
|
|
|
114 |
|
|
|
58 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
72,830 |
|
|
$ |
71,894 |
|
|
$ |
936 |
|
|
$ |
303,103 |
|
|
$ |
350,445 |
|
|
$ |
(47,342 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy Marketing Volume
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Nine Months Ended |
|
|
|
June 30, |
|
|
June 30, |
|
|
|
2010 |
|
|
2009 |
|
|
Decrease |
|
|
2010 |
|
|
2009 |
|
|
Increase |
|
Natural Gas (MMcf) |
|
|
13,047 |
|
|
|
14,634 |
|
|
|
(1,587 |
) |
|
|
51,144 |
|
|
|
50,459 |
|
|
|
685 |
|
-41-
Item 2. Managements Discussion and Analysis of Financial Condition and Results of Operations
(Cont.)
2010 Compared with 2009
Operating revenues for the Energy Marketing segment increased $0.9 million for the quarter
ended June 30, 2010 as compared with the quarter ended June 30, 2009. The slight increase reflects
an increase in gas sales revenue due to a higher average price of natural gas that was recovered
through revenues. The decline in volume is largely attributable to fewer 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 transactions had the effect of increasing revenue and volume sold
with minimal impact to earnings.
Operating revenues for the Energy Marketing segment decreased $47.3 million for the nine
months ended June 30, 2010 as compared with the nine months ended June 30, 2009. The decrease
primarily reflects a decline in gas sales revenue due to a lower average price of natural gas that
was recovered through revenues. The increase in volume is largely attributable to 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 transactions had the effect of increasing revenue and volume sold
with minimal impact to earnings.
The Energy Marketing segments earnings for the quarter ended June 30, 2010 were $1.4 million,
an increase of $0.1 million when compared with earnings of $1.3 million for the quarter ended June
30, 2009. The Energy Marketing segments earnings for the nine months ended June 30, 2010 were
$8.5 million, an increase of $1.0 million when compared with earnings of $7.5 million for the nine
months ended June 30, 2009. These increases were partially attributable to higher margin of $0.5
million and $1.0 million for the quarter and nine-month periods, respectively. The increase in
margin was primarily driven by improved average margins per Mcf as well as the marketing
flexibility that the Energy Marketing segment derives from its contracts for storage capacity.
Higher operating expenses of $0.3 million and $0.1 million for the quarter and nine-month periods,
respectively, partially offset the increase in earnings. The increase in operating expenses for
the quarter and nine months ended June 30, 2010 was primarily due to a June 2010 accrual for U.S.
Customs merchandise processing fees that may be due for certain past gas imports from Canada. For
the nine months ended June 30, 2010 as compared to the prior years nine-month period, the increase
in operating expenses was partly offset by lower bad debt expense.
Corporate and All Other
2010 Compared with 2009
Corporate and All Other recorded earnings of $0.1 million for the quarter ended June 30, 2010,
an increase of $0.2 million when compared with losses of $0.1 million for the quarter ended June
30, 2009. The increase in earnings was due to higher margins of $3.0 million, which was mostly
attributable to higher margins from log and lumber sales (partially due to the increase in timber
harvested from low cost basis, Company owned lands) coupled with higher revenues from Midstream
Corporations pipeline and gathering operations. The increase was partially offset by higher income
tax expense of $1.1 million (due to a higher effective tax rate), higher depreciation and depletion
expense of $0.8 million (mostly attributable to increased depletion expense due to an increase in
timber harvested from Company owned lands), and higher operating costs of $0.4 million (mostly
attributable to an increase in Midstream Corporations operating activities). Midstream Corporation
was formed to build, own and operate natural gas processing and pipeline gathering facilities in
the Appalachian region.
For the nine months ended June 30, 2010, Corporate and All Other had earnings of $1.7 million,
a decrease of $1.0 million when compared with earnings of $2.7 million for the nine months ended
June 30, 2009. The decrease in earnings was due to higher interest expense of $3.9 million
(primarily the result of higher borrowings at a higher interest rate due to the $250 million of
8.75% notes that were issued in April 2009), higher income tax expense of $3.6 million (due to a
higher effective tax rate), higher depreciation and depletion expense of $1.6 million (mostly
attributable to increased depletion expense due to an increase in timber harvested from Company
owned lands), decreased earnings from unconsolidated subsidiaries of $0.6 million (due to the
lower price of electricity sold by Seneca Energy (a subsidiary that generates electricity
-42-
Item 2. Managements Discussion and Analysis of Financial Condition and Results of Operations
(Cont.)
using methane gas obtained from landfills owned by outside parties)), and higher operating costs of
$0.4 million (mostly attributable to an increase in Midstream Corporations operating activities).
In addition, the non-recurrence of a gain resulting from a death benefit on corporate-owned life
insurance policies held by the Company of $2.3 million that occurred during the quarter ended
December 31, 2008 further reduced earnings. The decreases were partially offset by higher margins
of $6.5 million and higher interest income of $3.2 million. The increase in margins was mostly
attributable to higher margins from log and lumber sales (partially due to the increase in timber
harvested from low cost basis, Company owned lands) coupled with higher revenues from Midstream
Corporations pipeline and gathering operations. The increase in interest income was due to higher
intercompany interest collected from the Companys other operating segments as a result of the
allocation of the aforementioned April 2009 debt issuance to such segments. In addition, during
the quarter ended December 31, 2008, ESNE, an unconsolidated subsidiary of Horizon Power, recorded
an impairment charge of $3.6 million, which did not recur. Horizon Powers 50% share of impairment
was $1.8 million ($1.1 million on an after tax basis).
Interest Income
Interest income was $0.9 million lower in the quarter ended June 30, 2010 as compared with the
quarter ended June 30, 2009. For the nine months ended June 30, 2010, interest income decreased
$2.3 million as compared with the nine months ended June 30, 2009. The impact of lower interest
rates on cash investment balances more than offset the impact of higher cash investment balances.
Other Income
Other income decreased $0.7 million for the quarter ended June 30, 2010 as compared with the
quarter ended June 30, 2009. This decrease is largely attributable to smaller quarter-over-quarter
increases in the value of corporate-owned life insurance policies. For the nine months ended June
30, 2010, other income decreased $4.9 million as compared with the nine months ended June 30, 2009.
This decrease is attributable to a $2.8 million decrease in the allowance for funds used during
construction in the Pipeline and Storage segment mainly associated with the Empire Connector
project. In addition, a death benefit gain on corporate-owned life insurance policies of $2.3
million recognized during the first quarter of 2009 did not recur in 2010.
Interest Expense on Long-Term Debt
Interest expense on long-term debt decreased $0.6 million for the quarter ended June 30, 2010
as compared with the quarter ended June 30, 2009. For the nine months ended June 30, 2010, interest
expense on long-term debt increased $7.9 million as compared with the nine months ended June 30,
2009. During fiscal 2009, the Exploration and Production segment significantly increased its
capital expenditures related to unproved properties in the Marcellus Shale area of the Appalachian
region. As a result, the Company capitalized interest costs associated with the capital
expenditures, which decreased interest expense by $0.9 million. During the quarter ended June 30,
2010, this decrease more than offset the increase in interest expense as a result of a higher
average amount of long-term debt outstanding combined with higher average interest rates. For the
nine months ended June 30, 2010, the decrease in interest expense as a result of the aforementioned
capitalized interest ($0.9 million) was more than offset by the increase in the 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 partly
offset by the repayment of $100 million of 6.0% medium-term notes that matured in March 2009.
Other Interest Expense
Other Interest expense decreased $0.7 million for the quarter ended June 30, 2010 as compared
with the quarter ended June 30, 2009. The decrease is mainly due to lower interest expense on
regulatory deferrals (primarily deferred gas costs) in the Utility segment. For the nine months
ended June 30, 2010, other interest expense increased $0.3 million as compared with the nine months
ended June 30, 2009. The increase in interest expense is mainly attributed to a decrease in the
allowance for borrowed funds used during construction resulting from the completion of the Empire
Connector, which was partially offset by a decrease in interest expense on regulatory deferrals
(primarily deferred gas costs) in the Utility segment.
-43-
Item 2. Managements Discussion and Analysis of Financial Condition and Results of Operations
(Cont.)
CAPITAL RESOURCES AND LIQUIDITY
The Companys primary source of cash during the nine-month period ended June 30, 2010
consisted of cash provided by operating activities. The Companys primary source of cash during
the nine-month period ended June 30, 2009 consisted of cash provided by operating activities and
proceeds from the issuance of long-term debt. These sources of cash were supplemented by issues of
new shares of common stock as a result of stock option exercises for both the nine-month periods
ended June 30, 2010 and June 30, 2009. During the nine months ended June 30, 2010 and June 30,
2009, the common stock used to fulfill the requirements of the Companys 401(k) plans and Direct
Stock Purchase and Dividend Reinvestment Plan was obtained via open market purchases.
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 partnerships, deferred income taxes, and
income or loss from unconsolidated subsidiaries net of cash distributions.
Cash provided by operating activities in the Utility and the Pipeline and Storage segments may
vary substantially from period to period 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.
Because of the seasonal nature of the heating business in the Utility and Energy Marketing
segments, revenues in these segments are relatively high during the heating season, primarily the
first and second quarters of the fiscal year, and receivable balances historically increase during
these periods from the receivable balances at September 30.
The storage gas inventory normally declines during the first and second quarters of the fiscal
year and is replenished during the third and fourth quarters. For storage gas inventory accounted
for under the LIFO method, the current cost of replacing gas withdrawn from storage is recorded in
the Consolidated Statements of Income and a reserve for gas replacement is recorded in the
Consolidated Balance Sheets under the caption Other Accruals and Current Liabilities. Such
reserve is reduced as the inventory is replenished.
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 $419.9 million for the nine months ended
June 30, 2010, a decrease of $94.3 million compared with $514.2 million provided by operating
activities for the nine months ended June 30, 2009. The decrease 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 was reflected in Amounts
Payable to Customers on the Companys Consolidated Balance Sheet. Since September 30, 2009, the
Company has been refunding that over-recovery to its customers. From a consolidated perspective,
higher interest payments on long-term debt also contributed to the decrease in cash provided by
operating activities.
-44-
Item 2. Managements Discussion and Analysis of Financial Condition and Results of Operations
(Cont.)
Investing Cash Flow
Expenditures for Long-Lived Assets
The Companys expenditures for long-lived assets totaled $342.0 million during the nine months
ended June 30, 2010 and $232.9 million for the nine months ended June 30, 2009. The table below
presents these expenditures:
Total Expenditures for Long-Lived Assets
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended June 30, |
|
|
|
|
|
|
|
|
|
Increase |
|
(Millions) |
|
2010 |
|
|
2009 |
|
|
(Decrease) |
|
Utility |
|
$ |
39.5 |
|
|
$ |
40.4 |
|
|
$ |
(0.9 |
) |
Pipeline and Storage |
|
|
22.2 |
|
|
|
37.2 |
(3) |
|
|
(15.0 |
) |
Exploration and Production |
|
|
273.8 |
(1) (2) |
|
|
151.7 |
(4) |
|
|
122.1 |
|
All Other |
|
|
6.5 |
(2) |
|
|
3.9 |
|
|
|
2.6 |
|
Eliminations |
|
|
|
|
|
|
(0.3 |
) (5) |
|
|
0.3 |
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
342.0 |
|
|
$ |
232.9 |
|
|
$ |
109.1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Amount includes $24.3 million of accrued capital expenditures at June 30, 2010,
the majority of which was in the Appalachian region. This amount has been excluded from the
Consolidated Statement of Cash Flows at June 30, 2010 since it represents a non-cash investing
activity at that date. |
|
(2) |
|
Capital expenditures for the Exploration and Production segment for the
nine months ended June 30, 2010 exclude $9.1 million of accrued capital expenditures, the majority
of which was in the Appalachian region. Capital expenditures for All Other for the nine months
ended June 30, 2010 exclude $0.7 million of accrued capital expenditures related to the
construction of the Midstream Covington Gathering System. Both of these amounts were accrued at
September 30, 2009 and paid during the nine months ended June 30, 2010. These amounts were
excluded from the Consolidated Statement of Cash Flows at September 30, 2009 since they represented
non-cash investing activities at that date. These amounts have been included in the Consolidated
Statement of Cash Flows at June 30, 2010. |
|
(3) |
|
Amount for the nine months ended June 30, 2009 excludes $16.8 million of
accrued capital expenditures related to the Empire Connector project accrued at September 30, 2008
and paid during the nine months ended June 30, 2009. 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. The amount has been included in the Consolidated Statement of
Cash Flows at June 30, 2009. |
|
(4) |
|
Amount for the nine months ended June 30, 2009 includes $9.4 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 June 30, 2009 since it
represents a non-cash investing activity at that date. |
|
(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. |
Utility
The majority of the Utility capital expenditures for the nine months ended June 30, 2010 and
June 30, 2009 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 capital expenditures for the nine months ended June
30, 2010 were related to additions, improvements, and replacements to this segments transmission
and gas storage systems. The Pipeline and Storage capital expenditure amounts for the nine months
ended June 30, 2010 also include $5.8 million spent on the Lamont Project, discussed below. The
majority of the Pipeline and Storage capital expenditures for the nine months ended June 30, 2009
were related to the Empire Connector project, which was placed into service on December 10, 2008,
as well as additions, improvements, and replacements to this segments transmission and gas storage
systems.
-45-
Item 2. Managements Discussion and Analysis of Financial Condition and Results of Operations
(Cont.)
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 and paying for preliminary survey and
investigation costs, which are initially recorded as Deferred Charges on the Consolidated Balance
Sheet. An offsetting reserve is established as those preliminary survey and investigation costs are
incurred, which reduces the Deferred Charges balance and increases Operation and Maintenance
Expense on the Consolidated Statement of Income. The Company reviews all projects on a quarterly
basis, and if it is determined that it is highly probable that the project will be built, the
reserve is reversed. This reversal reduces Operation and Maintenance Expense and reestablishes the
original balance in Deferred Charges. After the reversal of the reserve, amounts remain in
Deferred Charges until construction begins, at which point the balance is transferred from Deferred
Charges to Construction Work in Progress, a component of Property, Plant and Equipment on the
Consolidated Balance Sheet.
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 (TETCO
Holbrook) in southwestern Pennsylvania (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 September 2011. On October 20, 2009, the FERC granted
Supply Corporations request for a pre-filing environmental review of the Line N Expansion Project,
and on June 11, 2010, Supply Corporation filed an NGA Section 7(c) application to the FERC for
approval of the project. The preliminary cost estimate for the Line N Expansion Project is $23
million. As of June 30, 2010, approximately $0.4 million has been spent to study the Line N
Expansion Project. The Company has determined that it is highly probable that this project will be
built. Accordingly, all previous reserves have been reversed and the $0.4 million has been
reestablished as a Deferred Charge on the Consolidated Balance Sheet. Supply Corporation has also
executed a precedent agreement for an additional 150,000 Dth/day of capacity on Line N to TETCO
Holbrook for service beginning November 2012 (Line N Phase II Expansion Project). The
preliminary cost estimate for the Line N Phase II Expansion Project is approximately $30 million.
As of June 30, 2010, no preliminary survey and investigation charges had been spent on this
project.
The second strategic horsepower expansion project, involving the addition of compression at
Supply Corporations existing interconnect with Tennessee Gas Pipeline (TGP) at Lamont,
Pennsylvania, was placed in-service on June 15, 2010 (Lamont Project). The Lamont Project, which
is designed and contracted for 40,000 Dth/day of firm transportation, affords shippers a
transportation path from their current and anticipated Marcellus production located in Elk and
Cameron Counties, Pennsylvania to markets attached to TGPs 300 Line. The Lamont Project was
constructed under Supply Corporations existing blanket construction certificate authority from the
FERC. The cost estimate for the Lamont Project is $6 million. As of June 30, 2010, approximately
$5.8 million has been spent related to the Lamont Project, all of which has been capitalized as
Property, Plant and Equipment at June 30, 2010. A second Lamont project phase is also being
planned (Lamont Phase II Project). With the construction of additional horsepower, up to 50,000
Dth/day of incremental firm capacity could be available by July 2011. Supply Corporation has one
signed precedent agreement for a portion of this capacity and is completing negotiations for a
second agreement for the remainder. The preliminary cost estimate for the Lamont Phase II Project
is approximately $7 million. As of June 30, 2010, no preliminary survey and investigation charges
had been spent on the Lamont Phase II project.
Supply Corporation has also signed a binding precedent agreement to provide 320,000 Dth/day of
firm transportation capacity in conjunction with its Northern Access expansion project. Upon
satisfaction of the conditions in the precedent agreement, Statoil Natural Gas LLC will enter into
a 20-year firm transportation agreement for 320,000 Dth/day. This capacity, which was offered and
awarded in Supply Corporations Open Season 159 that commenced January 12, 2010 and ended
February 17, 2010, will provide the subscribing shipper with a firm transportation path from the
Ellisburg area into the TransCanada Pipeline at Niagara. This path is attractive because it
provides a route for Marcellus shale gas, principally
-46-
Item 2. Managements Discussion and Analysis of Financial Condition and Results of Operations
(Cont.)
along the TGP 300 Line in northern Pennsylvania, to be distributed from the Marcellus supply basin
to northern markets. Service is expected to begin in late 2012, and Supply Corporation will shortly
begin working on an application for FERC authorization of the project. The project facilities
involve additional compression at Supply Corporations existing interconnects with TGP at Ellisburg
and at East Aurora, along with other system enhancements. The preliminary cost estimate for the
Northern Access expansion is $60 million, substantially all of which is expected to be incurred in
fiscal 2012. As of June 30, 2010, no preliminary survey and investigation charges had been spent
on this project.
In addition, Supply Corporation continues to actively pursue its largest planned expansion,
the West-to-East (W2E) pipeline project, which is designed to transport Rockies and/or locally
produced natural gas supplies to the Ellisburg/Leidy/Corning area. Supply Corporation anticipates
that the development of the W2E project will occur in phases. So, based on requests from the
Marcellus producing community for transportation service, 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; together W2E Overbeck to Leidy) of the W2E pipeline project. As
currently envisioned, the W2E Overbeck to Leidy project is designed to transport at least 425,000
Dth/day, and involves construction of a new 82-mile pipeline through Elk, Cameron, Clinton,
Clearfield and Jefferson Counties to the Leidy Hub, from Marcellus and other producing areas along
over 300 miles of Supply Corporations existing pipeline system. The W2E Overbeck to Leidy project
also includes a total of approximately 25,000 horsepower of compression at two separate stations.
The project may be built in phases depending on the development of Marcellus production along the
corridor, with the first facilities expected to go in service in 2013.
The binding Open Season for the W2E Overbeck to Leidy project concluded on October 8, 2009
with participation by several Marcellus producers. Supply Corporation received requests for 175,000
Dth/day of firm transportation capacity, and has executed binding precedent agreements to provide
125,000 Dth/day of firm transportation. Supply Corporation is pursuing post-Open Season capacity
requests for the remaining capacity. On March 31, 2010, the FERC granted Supply Corporations
request for a pre-filing environmental review of the W2E Overbeck to Leidy project, and Supply
Corporation is in the process of preparing an NGA Section 7(c) application. The capital cost of
this project is estimated to be $260 million. As of June 30, 2010, approximately $2.7 million has
been spent to study the W2E Overbeck to Leidy project, which has been included in preliminary
survey and investigation charges and has been fully reserved for at June 30, 2010.
Supply Corporation has developed plans for new storage capacity by expansion of two of its
existing storage facilities. The expansion of the East Branch and Galbraith fields, which could be
completed in early 2013, will provide 7.9 MMDth of incremental storage capacity and approximately
88 MDth per day of additional withdrawal deliverability. Supply Corporation expects that the
availability of this incremental storage capacity could complement the W2E Overbeck to Leidy
project by providing incremental transportation throughput to and from various market interconnect
points. It could also serve to balance the increasing flow of Appalachian gas supply through the
western Pennsylvania area with the growing demand for gas on the East Coast. This storage expansion
project would require an NGA Section 7 (c) application, which Supply Corporation has not yet filed.
The preliminary cost estimate for this storage expansion project is $64 million. As of June 30,
2010, approximately $1.0 million has been spent to study this storage expansion project, which has
been included in preliminary survey and investigation charges and has been fully reserved for at
June 30, 2010. The specific timeline associated with the storage expansion will depend on market
development.
Supply Corporation expects that its previously announced Appalachian Lateral project will
complement the W2E Overbeck to Leidy project due to its strategic upstream location. The
Appalachian Lateral pipeline, which would be routed through several counties in central
Pennsylvania where producers are actively drilling and seeking market access for their newly
discovered reserves, will be able to collect and transport locally produced Marcellus shale gas
into the W2E Overbeck to Leidy facilities. Supply Corporation expects to continue marketing
efforts for all remaining sections of the W2E/Appalachian Lateral project. The timeline and
projected costs associated with sections other than W2E Overbeck to Leidy, including the
Appalachian Lateral project, will depend on market development. As of June 30, 2010, no
preliminary survey and investigation charges had been spent on the remaining sections of the
W2E/Appalachian Lateral project.
-47-
Item 2. Managements Discussion and Analysis of Financial Condition and Results of Operations
(Cont.)
On October 1, 2009, Empire commenced its Open Season 006 for an expansion project that will
provide at least 300,000 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 $47
million. This project would enable shippers to deliver their gas at existing Empire
interconnections with Millennium Pipeline at Corning, New York, with the TransCanada Pipeline at
the Niagara River at Chippawa, and with utility and power generation markets along its path, as
well as to a planned new interconnection with TGPs 200 Line (Zone 5) in Ontario County, New York.
Empire completed the non-binding Open Season process on November 25, 2009 for capacity in the Tioga
County Extension Project, and has signed binding precedent agreements with two shippers
representing the total capacity of the project of 350,000 Dth/day. On January 28, 2010, the FERC
granted Empires request for a pre-filing environmental review of the Tioga County Extension
Project, and Empire is in the process of preparing an NGA Section 7 (c) application to the FERC for
approval of the project, which it expects to file this August. Empire anticipates that these
facilities will be placed in-service on or after September 1, 2011. As of June 30, 2010,
approximately $1.5 million has been spent to study the Tioga County Extension Project. The Company
has determined that it is highly probable that this project will be built. Accordingly, all
previous reserves have been reversed and the $1.5 million has been reestablished as a Deferred
Charge on the Consolidated Balance Sheet.
The Company anticipates financing the Line N Expansion Projects, the Lamont Projects, the
Northern Access expansion project, the W2E Overbeck to Leidy project, the storage expansion
project, the Appalachian Lateral 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.
The Company had $458.8 million in Cash and Temporary Cash Investments at June 30, 2010, as shown on
the Companys Consolidated Balance Sheet. The Company expects to use cash from operations as the
first means of financing these projects, with short-term and long-term debt being used at a later
time. Short-term debt may be used during 2010, but the Company does not expect to issue any
long-term debt in conjunction with these projects until 2011.
For fiscal 2011, the Company expects to spend $128 million on Pipeline and Storage
segment capital expenditures. Previously reported fiscal 2011 estimated capital
expenditures for the Pipeline and Storage segment were $227 million. The decrease is
attributable to the delay in the in-service date for the W2E pipeline project. The in-service date for the first facilities was moved from late 2012 to late 2013.
Exploration and Production
The Exploration and Production segment capital expenditures for the nine months ended June 30,
2010 were primarily well drilling and completion expenditures and included approximately $12.0
million for the Gulf Coast region, the majority of which was for the off-shore program in the
shallow waters of the Gulf of Mexico, $21.2 million for the West Coast region and $240.6 million
for the Appalachian region (including $217.6 million in the Marcellus Shale area). These amounts
included approximately $23.4 million spent to develop proved undeveloped reserves. The capital
expenditures in the Appalachian region include the Companys acquisition of two tracts of leasehold
acreage for approximately $71.8 million. The Company acquired these tracts in order to expand its
Marcellus Shale acreage holdings. These tracts, consisting of approximately 18,000 net acres in
Tioga and Potter Counties in Pennsylvania, are geographically similar to the Companys existing
Marcellus Shale acreage in the area, and will help the Company continue its developmental drilling
program. The transaction closed on March 12, 2010. The Company funded this transaction with cash
from operations. It is anticipated that future capital expenditures during 2010 will be funded
with cash from operations or short-term debt. Natural gas and crude oil prices combined with
production from existing wells will be a significant factor in determining how much of the capital
expenditures are funded from cash from operations.
The Exploration and Production segment capital expenditures for the nine months ended June 30,
2009 were primarily well drilling and completion expenditures and included approximately $16.9
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, $28.8 million for the West Coast region and $106.0 million
for the Appalachian region. These amounts included approximately $22.0 million spent to develop
proved undeveloped reserves.
For fiscal 2011, the Company expects to spend $460 million on Exploration and Production
segment capital expenditures. Previously reported fiscal 2011 estimated capital expenditures for
the Exploration and Production segment were $488 million. Estimated capital expenditures in the
West Coast region have increased from $28.0 million to $40.0 million. In the Appalachian
region, estimated capital expenditures
-48-
Item 2. Managements Discussion and Analysis of Financial Condition and Results of Operations
(Cont.)
have decreased from $450.0 million to $410.0 million. Estimated capital expenditures in the Gulf
Coast region have remained at the previously reported $10.0 million. The increase in the West
Coast estimated capital expenditures is due to increased opportunities on California oil
properties. The decrease in the Appalachian region estimated capital expenditures is due to a
reduction in drilling plans for the Exploration and Production segments shallow Upper Devonian
program related to a decrease in natural gas prices.
All Other
The majority of the All Other categorys capital expenditures for the nine months ended June
30, 2010 and June 30, 2009 were for the construction of Midstream Corporations Covington Gathering
System, as discussed below.
NFG Midstream Covington, LLC, a wholly owned subsidiary of Midstream Corporation, constructed
a gathering system in Tioga County, Pennsylvania. The project, called the Covington Gathering
System, was constructed in two phases. The first phase was completed and placed in service in
November 2009. The second phase was placed in service in May 2010. The system consists of
approximately 10 miles of gathering system at a cost of $13.7 million. During the nine months ended
June 30, 2010 and June 30, 2009, Midstream Corporation spent $5.6 million and $2.8 million,
respectively, related to this project.
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, 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 June 30, 2010. 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, which commitment extends through
September 30, 2010. The Company has received commitments for a new three-year, syndicated
committed credit facility totaling $300.0 million. The Company is negotiating the terms of the
facility and expects to enter into the facility during the quarter ending September 30, 2010.
Under the Companys current 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 June 30, 2010, the Companys debt to capitalization ratio (as calculated under the
facility) was .42. The constraints specified in the committed credit facility would permit an
additional $1.98 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 June 30, 2010, the Companys
-49-
Item 2. Managements Discussion and Analysis of Financial Condition and Results of Operations
(Cont.)
long-term debt ratings were: BBB (S&P), Baa1 (Moodys Investor Service), and BBB+ (Fitch Ratings
Service). In March 2010, Fitch Ratings Service decreased the Companys long-term debt rating from
A- to BBB+. The Company does not believe that this ratings action will impact its access to the
commercial paper markets. At June 30, 2010, 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 June 30, 2010, the Company would have
been permitted to issue up to a maximum of $1.3 billion in additional long-term unsecured
indebtedness at then current market interest rates in addition to being able to issue new
indebtedness to replace maturing debt. The Companys present liquidity position is believed to be
adequate to satisfy known demands. 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 June 30, 2010) 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 June 30, 2010, the Company had no
debt outstanding under the committed credit facility.
The Companys embedded cost of long-term debt was 6.95% at June 30, 2010 and June 30, 2009.
If the Company were to issue long-term debt today, its borrowing costs might be expected to be in
the range of 5.5% to 6.5% depending on the maturity date.
Current Portion of Long-Term Debt at June 30, 2010 consists of $200 million of 7.50%
medium-term notes that mature in November 2010. Currently, the Company expects to refund these
medium-term notes in November 2010 with cash on hand and/or short-term borrowings.
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 $22.9 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.
-50-
Item 2. Managements Discussion and Analysis of Financial Condition and Results of Operations
(Cont.)
OTHER MATTERS
In addition to the legal proceedings disclosed in Part II, Item 1 of this report, the Company
is involved in other litigation and regulatory matters arising in the normal course of business.
These other matters may include, for example, negligence claims and tax, regulatory or other
governmental audits, inspections, investigations or other proceedings. These matters may involve
state and federal taxes, safety, compliance with regulations, rate base, cost of service and
purchased gas cost issues, among other things. While these normal-course matters could have a
material effect on earnings and cash flows in the 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.
During the nine months ended June 30, 2010, the Company contributed $20.2 million to its
Retirement Plan and $21.4 million to its VEBA trusts and 401(h) accounts for its other
post-retirement benefits. In the remainder of 2010, the Company does not expect to contribute to
the Retirement Plan. It is likely that the Company will have to fund larger amounts to the
Retirement Plan subsequent to fiscal 2010 in order to be in compliance with the Pension Protection
Act of 2006. In the remainder of 2010, the Company expects to contribute $4.1 million to its VEBA
trusts and 401(h) accounts.
Market Risk Sensitive Instruments
On July 21, 2010, the Wall Street Reform and Consumer Protection Act (H.R. 4173) was signed
into law. The law includes provisions related to the swaps and over-the-counter derivatives
markets. Under the law, the Company expects to be exempt from mandatory clearing and exchange
trading requirements for most or all of its commodity hedges. Capital and margin
requirements for these hedges
are expected to be determined over the next year as regulators write more detailed rules and
requirements. While the Company is currently reviewing the provisions of H.R. 4173, it will not be
able to determine the impact to its financial condition until the final regulations are issued.
In accordance with the authoritative guidance for fair value measurements, the Company has
identified certain inputs used to recognize fair value as Level 3 (unobservable inputs). The Level
3 derivative assets and liabilities 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 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 Net Derivative Liabilities (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 Level 3 Net Liabilities amount to $0.1 million
at June 30, 2010 or less than 0.1% of the Total Net Assets shown in Part I, Item 1 at Note 2
Fair Value Measurements at June 30, 2010.
The decrease in the net fair value of the Level 3 positions from September 30, 2009 to June
30, 2010, as shown in Part I, Item 1 at Note 2, was attributable to an increase in the commodity
price of crude oil relative to the swap price 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 June 30, 2010.
The fair value of all the Companys Net Derivative Assets was reduced by $0.7 million based on
the Companys assessment of credit risk. The Company applied default probabilities to the
anticipated cash flows that it was expecting from its counterparties to calculate the credit
reserve.
For a complete discussion of market risk sensitive instruments, refer to Market Risk
Sensitive Instruments in Item 7 of the Companys 2009 Form 10-K. There have been no subsequent
material changes to the Companys exposure to market risk sensitive instruments.
-51-
Item 2. Managements Discussion and Analysis of Financial Condition and Results of Operations
(Cont.)
Rate and Regulatory Matters
Utility Operation
Base rate adjustments in both the New York and Pennsylvania rate 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 annually, together with a surcharge to 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 approved a 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 31st, 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 contended that portions of the rate order were invalid
because they failed to meet the applicable legal standard for agency decisions. Among the issues
challenged by the Company was the reasonableness of the NYPSCs disallowance of expense items and
the methodology used for calculating rate of return, which the appeal contended understated the
Companys cost of equity. Because of the issues appealed, the case was later transferred to the
Appellate Division, New York States second-highest court. On December 31, 2009, the Appellate
Division issued its Opinion and Judgment. The court upheld the NYPSCs determination relating to
the authorized rate of return but also supported the Companys argument that the NYPSC improperly
disallowed recovery of certain environmental clean-up costs. On February 1, 2010, the NYPSC filed a
motion with the Court of Appeals, New York States highest court, seeking permission to appeal the
Appellate Divisions annulment of that part of the rate order relating to disallowance of
environmental clean up costs. On May 4, 2010, the NYPSCs motion was granted, and the matter will
be heard by the Court of Appeals. The Briefing schedule began on July 28, 2010 and is followed by
oral argument. The Company cannot predict the outcome of the appeal proceedings at this time.
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 following three years of actual operation, in conjunction
with which Empire will either justify Empires existing recourse rates or propose alternative
rates.
-52-
Item 2. Managements Discussion and Analysis of Financial Condition and Results of Operations
(Cont.)
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.
The Company has agreed with the NYDEC to remediate a 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
$14.8 million.
At June 30, 2010, the Company has estimated its remaining clean-up costs related to former
manufactured gas plant sites and third party waste disposal sites (including the former
manufactured gas plant site discussed above) will be in the range of $17.5 million to $21.7
million. The minimum estimated liability of $17.5 million, which includes the $14.8 million
discussed above, has been recorded on the Consolidated Balance Sheet at June 30, 2010. The Company
expects to recover these environmental clean-up costs through rate recovery.
Legislative and regulatory measures to address climate change and greenhouse gas emissions are
in various phases of discussion or implementation. The EPA has determined that stationary sources
of significant greenhouse gas emissions will be required under the federal Clean Air Act to obtain
permits covering such emissions beginning in January 2011. In addition, the U.S. Congress has been
considering bills that would establish a cap-and-trade program to reduce emissions of greenhouse
gases. 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. Climate change and greenhouse gas
measures could also delay or otherwise negatively affect efforts to obtain permits and other
regulatory approvals with regard to existing and new facilities, or impose additional monitoring
and reporting requirements. 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.
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.
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. The FASBs authoritative guidance for using fair value to measure nonfinancial
assets and nonfinancial liabilities on a nonrecurring basis became effective during the quarter
ended December 31, 2009. The Companys nonfinancial assets and nonfinancial liabilities were not
impacted by this guidance during the nine months ended June 30, 2010. The Company has identified
Goodwill as being the major nonfinancial asset that may be impacted by the adoption of this
guidance. The impact of this guidance will be known when the Company performs its annual test for
goodwill impairment at the end of the fiscal year; however, at this time, it is not expected to be
material. The Company has identified Asset Retirement Obligations as a nonfinancial liability that
may be impacted by the adoption of the guidance. The impact of this guidance will be known when
the Company recognizes new asset retirement obligations. However, at this time, the Company
believes the impact of the guidance will be
-53-
Item 2. Managements Discussion and Analysis of Financial Condition and Results of Operations
(Cont.)
immaterial. Additionally, in February 2010, the FASB issued updated guidance that includes
additional requirements and disclosures regarding fair value measurements. The guidance now
requires the gross presentation of activity within the Level 3 roll forward and requires disclosure
of details on transfers in and out of Level 1 and 2 fair value measurements. It also provides
further clarification on the level of disaggregation of fair value measurements and disclosures on
inputs and valuation techniques. The Company has updated its disclosures to reflect the new
requirements in Part I, Item 1 at Note 2 Fair Value Measurements, except for the Level 3 roll
forward gross presentation, which will be effective as of the Companys first quarter of fiscal
2012.
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 used to value oil and gas
reserves with 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. Additionally, on January 6, 2010, the
FASB amended the oil and gas accounting standards to conform to the SEC final rule on Modernization
of Oil and Gas Reporting. The revised reporting and disclosure requirements will be 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.
In June 2009, the FASB issued amended authoritative guidance to improve and clarify financial
reporting requirements by companies involved with variable interest entities. The new guidance
requires a company to perform an analysis to determine whether the companys variable interest or
interests give it a controlling financial interest in a variable interest entity. The analysis also
assists in identifying the primary beneficiary of a variable interest entity. This authoritative
guidance will be effective as of the Companys first quarter of fiscal 2011. Given the current
organizational structure of the Company, the Company does not believe this authoritative guidance
will have any impact on its consolidated financial statements.
Safe Harbor for Forward-Looking Statements
The Company is including the following cautionary statement in this Form 10-Q 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
-54-
Item 2. Managements Discussion and Analysis
of Financial Condition and Results of Operations (Cont.)
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; |
|
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 demographic patterns and weather conditions; |
|
7. |
|
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; |
|
8. |
|
Impairments under the SECs full cost ceiling test for natural gas and oil reserves; |
|
9. |
|
Uncertainty of oil and gas reserve estimates; |
|
10. |
|
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, insufficient gathering, processing and
transportation capacity, and the need to obtain governmental approvals and permits and comply
with environmental laws and regulations; |
|
11. |
|
Significant differences between the Companys projected and actual production levels for
natural gas or oil; |
|
12. |
|
Changes in the availability and/or price of derivative financial instruments; |
|
13. |
|
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; |
|
14. |
|
Changes in laws and regulations to which the Company is subject, including those involving
derivatives, taxes, safety, employment, climate change, other environmental matters, and
exploration and production activities such as hydraulic fracturing; |
-55-
Item 2. Managements Discussion and Analysis of Financial Condition and Results of Operations
(Concl.)
15. |
|
The nature and projected profitability of pending and potential projects and other
investments, and the ability to obtain necessary governmental approvals and permits; |
|
16. |
|
Significant differences between the Companys projected and actual capital expenditures and
operating expenses, and unanticipated project delays or changes in project costs or plans; |
|
17. |
|
Inability to obtain new customers or retain existing ones; |
|
18. |
|
Significant changes in competitive factors affecting the Company; |
|
19. |
|
Governmental/regulatory actions, initiatives and proceedings, including those involving
derivatives, 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; |
|
20. |
|
Unanticipated impacts of restructuring initiatives in the natural gas and electric
industries; |
|
21. |
|
Ability to successfully identify and finance acquisitions or other investments and ability to
operate and integrate existing and any subsequently acquired business or properties; |
|
22. |
|
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; |
|
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.
Industry and Market Information
The industry and market data used or referenced in this report are based on independent
industry publications, government publications, reports by market research firms or other published
independent sources. Some industry and market data may also be based on good faith estimates, which
are derived from the Companys review of internal information, as well as the independent sources
listed above. Independent industry publications and surveys generally state that they have obtained
information from sources believed to be reliable, but do not guarantee the accuracy and
completeness of such information. While the Company believes that each of these studies and
publications is reliable, the Company has not independently verified such data and makes no
representation as to the accuracy of such information. Forecasts in particular may prove to be
inaccurate, especially over long periods of time. Similarly, while the Company believes its
internal information is reliable, such information has not been verified by any independent
sources, and the Company makes no assurances that any predictions contained herein will prove to be
accurate.
-56-
Item 3. Quantitative and Qualitative Disclosures About Market Risk
Refer to the Market Risk Sensitive Instruments section in Item 2 MD&A.
Item 4. 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 June 30, 2010.
Changes in Internal Controls Over Financial Reporting
There were no changes in the Companys internal control over financial reporting that occurred
during the quarter ended June 30, 2010 that have materially affected, or are reasonably likely to
materially affect, the Companys internal control over financial reporting.
Part II. Other Information
Item 1. Legal Proceedings
For a discussion of various environmental and other matters, refer to Part I, Item 1 at Note 6
Commitments and Contingencies, and Part I, Item 2 MD&A of this report under the heading
Other Matters Environmental Matters.
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 1A. Risk Factors
The risk factors in Item 1A of the Companys 2009 Form 10-K, as amended by Item 1A of the
Companys Forms 10-Q for the quarters ended December 31, 2009 and March 31, 2010, have not
materially changed.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
On April 1, 2010, the Company issued a total of 3,600 unregistered shares of Company common
stock to the nine non-employee directors of the Company then serving on the Board of Directors of
the Company, 400 shares to each such director. All of these unregistered shares were issued under
the Companys Retainer Policy for Non-Employee Directors as partial consideration for such
directors services during the quarter ended June 30, 2010. These transactions were exempt from
registration under Section 4(2) of the Securities Act of 1933, as transactions not involving a
public offering.
-57-
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds (Concl.)
Issuer Purchases of Equity Securities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Number of |
|
Maximum Number |
|
|
|
|
|
|
|
|
|
|
Shares Purchased |
|
of Shares that May |
|
|
|
|
|
|
|
|
|
|
as Part of Publicly |
|
Yet Be Purchased |
|
|
Total Number of |
|
|
|
|
|
Announced Share |
|
Under Share |
|
|
Shares |
|
Average Price |
|
Repurchase Plans |
|
Repurchase Plans |
Period |
|
Purchased(a) |
|
Paid per Share |
|
or Programs |
|
or Programs (b) |
Apr. 1 - 30, 2010 |
|
|
7,747 |
|
|
$ |
52.37 |
|
|
|
|
|
|
|
6,971,019 |
|
May 1 - 31, 2010 |
|
|
8,298 |
|
|
$ |
49.81 |
|
|
|
|
|
|
|
6,971,019 |
|
June 1 - 30, 2010 |
|
|
11,261 |
|
|
$ |
48.66 |
|
|
|
|
|
|
|
6,971,019 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
27,306 |
|
|
$ |
50.06 |
|
|
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6,971,019 |
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(a) |
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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 June 30, 2010, the Company did not
purchase any shares of its common stock pursuant to its publicly announced share repurchase
program. Of the 27,306 shares purchased other than through a publicly announced share
repurchase program, 24,154 were purchased for the Companys 401(k) plans and 3,152 were
purchased as a result of shares tendered to the Company by holders of stock options or shares
of restricted stock. |
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(b) |
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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. |
Item 6. Exhibits
(a) Exhibits
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Exhibit |
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Number |
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Description of Exhibit |
10.1
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Amendment to National Fuel Gas Company and Participating Subsidiaries
Executive Retirement Plan, dated June 1, 2010 |
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12
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Statements regarding Computation of Ratios: |
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Ratio of Earnings to Fixed Charges for the Twelve Months Ended June
30, 2010 and the Fiscal Years Ended September 30, 2006 through 2009. |
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31.1
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Written statements of Chief Executive Officer pursuant to Rule
13a-14(a) or Rule 15d-14(a) under the Securities Exchange Act of 1934. |
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31.2
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Written statements of Principal Financial Officer pursuant to
Rule 13a-14(a) or Rule 15d-14(a) under the Securities Exchange Act of 1934. |
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32
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Certification Pursuant to Section 906 of the Sarbanes-Oxley Act
of 2002. |
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99
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National Fuel Gas Company Consolidated Statements of Income for
the Twelve Months Ended June 30, 2010 and 2009. |
-58-
Item 6. Exhibits (Concl.)
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101 |
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Interactive data files pursuant to Regulation S-T: (i) the
Consolidated Statements of Income and Earnings Reinvested in the Business for
the three and nine months ended June 30, 2010 and 2009, (ii) the Consolidated
Balance Sheets at June 30, 2010 and September 30, 2009, (iii) the Consolidated
Statement of Cash Flows for the nine months ended June 30, 2010 and 2009, (iv)
the Consolidated Statements of Comprehensive Income for the three and nine
months ended June 30, 2010 and 2009 and (v) the Notes to Condensed Consolidated
Financial Statements. |
-59-
SIGNATURES
Pursuant to the requirements 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.
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NATIONAL FUEL GAS COMPANY |
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(Registrant)
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/s/ D. P. Bauer
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D. P. Bauer |
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Treasurer and Principal Financial Officer |
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/s/ K. M. Camiolo
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K. M. Camiolo |
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Controller and Principal Accounting Officer |
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Date: August 6, 2010
-60-