e10vq
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
FORM 10-Q
þ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended March 31, 2011
OR
o 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
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(I.R.S. Employer |
incorporation or organization)
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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 April 30, 2011: 82,690,940 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 |
Distribution Corporation
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National Fuel Gas Distribution Corporation |
Empire
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|
Empire Pipeline, Inc. |
ESNE
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Energy Systems North East, LLC |
Highland
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Highland Forest Resources, Inc. |
Horizon
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Horizon Energy Development, Inc. |
Horizon B.V.
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Horizon Energy Development B.V. |
Horizon LFG
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Horizon LFG, Inc. |
Horizon Power
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|
Horizon Power, Inc. |
Midstream Corporation
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National Fuel Gas Midstream Corporation |
Model City
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Model City Energy, LLC |
National Fuel
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National Fuel Gas Company |
NFR
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National Fuel Resources, Inc. |
Registrant
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National Fuel Gas Company |
Seneca
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Seneca Resources Corporation |
Seneca Energy
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Seneca Energy II, LLC |
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 |
FASB
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Financial Accounting Standards Board |
FERC
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Federal Energy Regulatory Commission |
NYDEC
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New York State Department of Environmental Conservation |
NYPSC
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State of New York Public Service Commission |
PaPUC
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Pennsylvania Public Utility Commission |
SEC
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Securities and Exchange Commission |
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Other |
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2010 Form 10-K
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The Companys Annual Report on Form 10-K for the year ended
September 30, 2010 |
Bbl
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|
Barrel (of oil) |
Bcf
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|
Billion cubic feet (of natural gas) |
Bcfe (or Mcfe) represents
Bcf (or Mcf) Equivalent
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|
The total heat value (Btu) of natural gas and oil expressed as a volume of
natural gas. The Company uses a conversion formula of 1 barrel of
oil = 6 Mcf of natural gas. |
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. |
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. |
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. |
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. |
Development costs
|
|
Costs incurred to obtain access to proved reserves and to provide
facilities for extracting, treating, gathering and storing the oil and gas. |
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. |
-2-
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GLOSSARY OF TERMS (Cont.) |
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Exchange Act
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Securities Exchange Act of 1934, as amended |
Expenditures for
long-lived assets
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Includes capital expenditures, stock acquisitions and/or investments in
partnerships. |
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. |
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. |
GAAP
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Accounting principles generally accepted in the United States of America |
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. |
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. |
Hub
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Location where pipelines intersect enabling the trading, transportation,
storage, exchange, lending and borrowing of natural gas. |
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. |
LIBOR
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London Interbank Offered Rate |
LIFO
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Last-in, first-out |
Marcellus Shale
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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. |
Mbbl
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Thousand barrels (of oil) |
Mcf
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|
Thousand cubic feet (of natural gas) |
MD&A
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|
Managements Discussion and Analysis of Financial Condition and
Results of Operations |
MDth
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|
Thousand decatherms (of natural gas) |
MMBtu
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|
Million British thermal units |
MMcf
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|
Million cubic feet (of natural gas) |
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. |
NYMEX
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|
New York Mercantile Exchange. An exchange which maintains a futures
market for crude oil and natural gas. |
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. |
PCB
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Polychlorinated Biphenyl |
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. |
Proved developed reserves
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Reserves that can be expected to be recovered through existing wells
with existing equipment and operating methods. |
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. |
Reserves
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The unproduced but recoverable oil and/or gas in place in a formation
which has been proven by production. |
-3-
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GLOSSARY OF TERMS (Concl.) |
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Restructuring
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Generally referring to partial deregulation of the pipeline and/or utility
industry by statutory or regulatory process. Restructuring of federally
regulated natural gas pipelines resulted in the separation (or
unbundling) of gas commodity service from transportation service for
wholesale and large-volume retail markets. State restructuring
programs attempt to extend the same process to retail mass markets. |
Revenue decoupling mechanism
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A rate mechanism which adjusts customer rates to render a utility
financially indifferent to throughput decreases resulting from
conservation. |
S&P
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Standard & Poors Rating Service |
SAR
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Stock appreciation right |
Stock acquisitions
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Investments in corporations. |
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. |
VEBA
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Voluntary Employees Beneficiary Association |
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
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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, estimates of oil and gas quantities, 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
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Item 1. |
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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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March 31, |
(Thousands of Dollars, Except Per Common Share Amounts) |
|
2011 |
|
2010 |
INCOME |
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|
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|
Operating Revenues |
|
$ |
660,881 |
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|
$ |
667,980 |
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Operating Expenses |
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Purchased Gas |
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306,595 |
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|
332,923 |
|
Operation and Maintenance |
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|
116,721 |
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|
116,261 |
|
Property, Franchise and Other Taxes |
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|
23,798 |
|
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|
20,440 |
|
Depreciation, Depletion and Amortization |
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|
60,011 |
|
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|
46,725 |
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|
|
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|
507,125 |
|
|
|
516,349 |
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|
Operating Income |
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|
153,756 |
|
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|
151,631 |
|
Other Income (Expense): |
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|
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|
Income from Unconsolidated Subsidiaries |
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479 |
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|
672 |
|
Gain on Sale of Unconsolidated Subsidiaries |
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50,879 |
|
|
|
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|
Interest Income |
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|
68 |
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|
326 |
|
Other Income |
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|
1,945 |
|
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|
1,266 |
|
Interest Expense on Long-Term Debt |
|
|
(17,926 |
) |
|
|
(22,061 |
) |
Other Interest Expense |
|
|
(1,454 |
) |
|
|
(2,002 |
) |
|
Income from Continuing Operations Before Income Taxes |
|
|
187,747 |
|
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|
129,832 |
|
Income Tax Expense |
|
|
72,136 |
|
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|
49,958 |
|
|
|
|
|
|
|
|
|
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|
Income from Continuing Operations |
|
|
115,611 |
|
|
|
79,874 |
|
|
|
|
|
|
|
|
|
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|
Income from Discontinued Operations, Net of Tax |
|
|
|
|
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|
554 |
|
|
|
|
|
|
|
|
|
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|
Net Income Available for Common Stock |
|
|
115,611 |
|
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|
80,428 |
|
|
|
|
|
|
|
|
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|
EARNINGS REINVESTED IN THE BUSINESS |
|
|
|
|
|
|
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|
Balance at January 1 |
|
|
1,093,398 |
|
|
|
985,663 |
|
|
|
|
|
1,209,009 |
|
|
|
1,066,091 |
|
Dividends on Common Stock
(2011 - $0.345 per share; 2010 - $0.335 per share) |
|
|
(28,478 |
) |
|
|
(27,222 |
) |
|
Balance at March 31 |
|
$ |
1,180,531 |
|
|
$ |
1,038,869 |
|
|
|
|
|
|
|
|
|
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|
Earnings Per Common Share: |
|
|
|
|
|
|
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|
Basic: |
|
|
|
|
|
|
|
|
Income from Continuing Operations |
|
$ |
1.40 |
|
|
$ |
0.98 |
|
Income from Discontinued Operations |
|
|
|
|
|
|
0.01 |
|
|
Net Income Available for Common Stock |
|
$ |
1.40 |
|
|
$ |
0.99 |
|
|
Diluted: |
|
|
|
|
|
|
|
|
Income from Continuing Operations |
|
$ |
1.38 |
|
|
$ |
0.96 |
|
Income from Discontinued Operations |
|
|
|
|
|
|
0.01 |
|
|
Net Income Available for Common Stock |
|
$ |
1.38 |
|
|
$ |
0.97 |
|
|
Weighted Average Common Shares Outstanding: |
|
|
|
|
|
|
|
|
Used in Basic Calculation |
|
|
82,400,851 |
|
|
|
81,175,261 |
|
|
Used in Diluted Calculation |
|
|
83,673,977 |
|
|
|
82,569,323 |
|
|
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)
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended |
|
|
March 31, |
(Thousands of Dollars, Except Per Common Share Amounts) |
|
2011 |
|
2010 |
INCOME |
|
|
|
|
|
|
|
|
Operating Revenues |
|
$ |
1,111,829 |
|
|
$ |
1,122,115 |
|
|
|
|
|
|
|
|
|
|
|
Operating Expenses |
|
|
|
|
|
|
|
|
Purchased Gas |
|
|
469,633 |
|
|
|
504,213 |
|
Operation and Maintenance |
|
|
214,171 |
|
|
|
210,031 |
|
Property, Franchise and Other Taxes |
|
|
43,534 |
|
|
|
39,090 |
|
Depreciation, Depletion and Amortization |
|
|
113,324 |
|
|
|
91,513 |
|
|
|
|
|
840,662 |
|
|
|
844,847 |
|
|
Operating Income |
|
|
271,167 |
|
|
|
277,268 |
|
Other Income (Expense): |
|
|
|
|
|
|
|
|
Income (Loss) from Unconsolidated Subsidiaries |
|
|
(621 |
) |
|
|
1,073 |
|
Gain on Sale of Unconsolidated Subsidiaries |
|
|
50,879 |
|
|
|
|
|
Interest Income |
|
|
951 |
|
|
|
1,480 |
|
Other Income |
|
|
2,938 |
|
|
|
1,622 |
|
Interest Expense on Long-Term Debt |
|
|
(38,118 |
) |
|
|
(44,124 |
) |
Other Interest Expense |
|
|
(2,855 |
) |
|
|
(3,379 |
) |
|
Income from Continuing Operations Before Income Taxes |
|
|
284,341 |
|
|
|
233,940 |
|
Income Tax Expense |
|
|
110,187 |
|
|
|
89,841 |
|
|
|
|
|
|
|
|
|
|
|
Income from Continuing Operations |
|
|
174,154 |
|
|
|
144,099 |
|
|
|
|
|
|
|
|
|
|
|
Income from Discontinued Operations, Net of Tax |
|
|
|
|
|
|
828 |
|
|
|
|
|
|
|
|
|
|
|
Net Income Available for Common Stock |
|
|
174,154 |
|
|
|
144,927 |
|
|
|
|
|
|
|
|
|
|
|
EARNINGS REINVESTED IN THE BUSINESS |
|
|
|
|
|
|
|
|
Balance at October 1 |
|
|
1,063,262 |
|
|
|
948,293 |
|
|
|
|
|
1,237,416 |
|
|
|
1,093,220 |
|
Dividends on Common Stock
(2011 - $0.69 per share; 2010 - $0.67 per share) |
|
|
(56,885 |
) |
|
|
(54,351 |
) |
|
Balance at March 31 |
|
$ |
1,180,531 |
|
|
$ |
1,038,869 |
|
|
|
|
|
|
|
|
|
|
|
Earnings Per Common Share: |
|
|
|
|
|
|
|
|
Basic: |
|
|
|
|
|
|
|
|
Income from Continuing Operations |
|
$ |
2.12 |
|
|
$ |
1.78 |
|
Income from Discontinued Operations |
|
|
|
|
|
|
0.01 |
|
|
Net Income Available for Common Stock |
|
$ |
2.12 |
|
|
$ |
1.79 |
|
|
Diluted: |
|
|
|
|
|
|
|
|
Income from Continuing Operations |
|
$ |
2.08 |
|
|
$ |
1.75 |
|
Income from Discontinued Operations |
|
|
|
|
|
|
0.01 |
|
|
Net Income Available for Common Stock |
|
$ |
2.08 |
|
|
$ |
1.76 |
|
|
Weighted Average Common Shares Outstanding: |
|
|
|
|
|
|
|
|
Used in Basic Calculation |
|
|
82,311,162 |
|
|
|
80,866,311 |
|
|
Used in Diluted Calculation |
|
|
83,561,775 |
|
|
|
82,347,254 |
|
|
|
|
|
|
|
|
|
|
|
See Notes to Condensed Consolidated Financial Statements
-7-
|
|
|
Item 1. |
|
Financial Statements (Cont.) |
National Fuel Gas Company
Consolidated Balance Sheets
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
March 31, |
|
September 30, |
(Thousands of Dollars) |
|
2011 |
|
2010 |
ASSETS |
|
|
|
|
|
|
|
|
Property, Plant and Equipment |
|
$ |
6,019,453 |
|
|
$ |
5,637,498 |
|
Less Accumulated Depreciation, Depletion
and Amortization |
|
|
2,285,313 |
|
|
|
2,187,269 |
|
|
|
|
|
3,734,140 |
|
|
|
3,450,229 |
|
|
Current Assets |
|
|
|
|
|
|
|
|
Cash and Temporary Cash Investments |
|
|
144,767 |
|
|
|
397,171 |
|
Hedging Collateral Deposits |
|
|
61,826 |
|
|
|
11,134 |
|
Receivables Net of Allowance for
Uncollectible Accounts of
$44,132 and $30,961, Respectively |
|
|
227,898 |
|
|
|
132,136 |
|
Unbilled Utility Revenue |
|
|
48,551 |
|
|
|
20,920 |
|
Gas Stored Underground |
|
|
11,927 |
|
|
|
48,584 |
|
Materials and Supplies at average cost |
|
|
31,707 |
|
|
|
24,987 |
|
Other Current Assets |
|
|
58,522 |
|
|
|
115,969 |
|
Deferred Income Taxes |
|
|
34,917 |
|
|
|
24,476 |
|
|
|
|
|
620,115 |
|
|
|
775,377 |
|
|
|
|
|
|
|
|
|
|
|
Other Assets |
|
|
|
|
|
|
|
|
Recoverable Future Taxes |
|
|
152,017 |
|
|
|
149,712 |
|
Unamortized Debt Expense |
|
|
11,547 |
|
|
|
12,550 |
|
Other Regulatory Assets |
|
|
529,420 |
|
|
|
542,801 |
|
Deferred Charges |
|
|
5,960 |
|
|
|
9,646 |
|
Other Investments |
|
|
83,744 |
|
|
|
77,839 |
|
Investments in Unconsolidated Subsidiaries |
|
|
1,443 |
|
|
|
14,828 |
|
Goodwill |
|
|
5,476 |
|
|
|
5,476 |
|
Fair Value of Derivative Financial Instruments |
|
|
37,708 |
|
|
|
65,184 |
|
Other |
|
|
1,747 |
|
|
|
1,983 |
|
|
|
|
|
829,062 |
|
|
|
880,019 |
|
|
|
|
|
|
|
|
|
|
|
Total Assets |
|
$ |
5,183,317 |
|
|
$ |
5,105,625 |
|
|
See Notes to Condensed Consolidated Financial Statements
-8-
|
|
|
Item 1. |
|
Financial Statements (Cont.) |
National Fuel Gas Company
Consolidated Balance Sheets
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
March 31, |
|
September 30, |
(Thousands of Dollars) |
|
2011 |
|
2010 |
CAPITALIZATION AND LIABILITIES |
|
|
|
|
|
|
|
|
Capitalization: |
|
|
|
|
|
|
|
|
Comprehensive Shareholders Equity |
|
|
|
|
|
|
|
|
Common Stock, $1 Par Value
Authorized - 200,000,000 Shares; Issued
And Outstanding 82,544,193 Shares and
82,075,470 Shares, Respectively |
|
$ |
82,544 |
|
|
$ |
82,075 |
|
Paid in Capital |
|
|
645,961 |
|
|
|
645,619 |
|
Earnings Reinvested in the Business |
|
|
1,180,531 |
|
|
|
1,063,262 |
|
|
Total Common Shareholder Equity Before
Items of Other Comprehensive Loss |
|
|
1,909,036 |
|
|
|
1,790,956 |
|
Accumulated Other Comprehensive Loss |
|
|
(92,521 |
) |
|
|
(44,985 |
) |
|
Total Comprehensive Shareholders Equity |
|
|
1,816,515 |
|
|
|
1,745,971 |
|
Long-Term Debt, Net of Current Portion |
|
|
899,000 |
|
|
|
1,049,000 |
|
|
Total Capitalization |
|
|
2,715,515 |
|
|
|
2,794,971 |
|
|
|
|
|
|
|
|
|
|
|
Current and Accrued Liabilities |
|
|
|
|
|
|
|
|
Notes Payable to Banks and Commercial Paper |
|
|
|
|
|
|
|
|
Current Portion of Long-Term Debt |
|
|
150,000 |
|
|
|
200,000 |
|
Accounts Payable |
|
|
122,911 |
|
|
|
89,677 |
|
Amounts Payable to Customers |
|
|
25,475 |
|
|
|
38,109 |
|
Dividends Payable |
|
|
28,478 |
|
|
|
28,316 |
|
Interest Payable on Long-Term Debt |
|
|
25,512 |
|
|
|
30,512 |
|
Customer Advances |
|
|
2,700 |
|
|
|
27,638 |
|
Customer Security Deposits |
|
|
18,064 |
|
|
|
18,320 |
|
Other Accruals and Current Liabilities |
|
|
160,363 |
|
|
|
71,592 |
|
Fair Value of Derivative Financial Instruments |
|
|
70,115 |
|
|
|
20,160 |
|
|
|
|
|
603,618 |
|
|
|
524,324 |
|
|
|
|
|
|
|
|
|
|
|
Deferred Credits |
|
|
|
|
|
|
|
|
Deferred Income Taxes |
|
|
886,824 |
|
|
|
800,758 |
|
Taxes Refundable to Customers |
|
|
69,592 |
|
|
|
69,585 |
|
Unamortized Investment Tax Credit |
|
|
2,937 |
|
|
|
3,288 |
|
Cost of Removal Regulatory Liability |
|
|
131,958 |
|
|
|
124,032 |
|
Other Regulatory Liabilities |
|
|
88,825 |
|
|
|
89,334 |
|
Pension and Other Post-Retirement Liabilities |
|
|
434,488 |
|
|
|
446,082 |
|
Asset Retirement Obligations |
|
|
102,094 |
|
|
|
101,618 |
|
Other Deferred Credits |
|
|
147,466 |
|
|
|
151,633 |
|
|
|
|
|
1,864,184 |
|
|
|
1,786,330 |
|
|
Commitments and Contingencies |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Capitalization and Liabilities |
|
$ |
5,183,317 |
|
|
$ |
5,105,625 |
|
|
See Notes to Condensed Consolidated Financial Statements
-9-
|
|
|
Item 1. |
|
Financial Statements (Cont.) |
National Fuel Gas Company
Consolidated Statements of Cash Flows
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended |
|
|
March 31, |
(Thousands of Dollars) |
|
2011 |
|
2010 |
OPERATING ACTIVITIES |
|
|
|
|
|
|
|
|
Net Income Available for Common Stock |
|
$ |
174,154 |
|
|
$ |
144,927 |
|
Adjustments to Reconcile Net Income to Net Cash |
|
|
|
|
|
|
|
|
Provided by Operating Activities: |
|
|
|
|
|
|
|
|
Gain on Sale of Unconsolidated Subsidiaries |
|
|
(50,879 |
) |
|
|
|
|
Depreciation, Depletion and Amortization |
|
|
113,324 |
|
|
|
91,846 |
|
Deferred Income Taxes |
|
|
106,510 |
|
|
|
41,795 |
|
(Income) Loss from Unconsolidated Subsidiaries, Net of
Cash Distributions |
|
|
4,899 |
|
|
|
1,228 |
|
Excess Tax Benefits Associated with Stock-Based
Compensation Awards |
|
|
|
|
|
|
(13,437 |
) |
Other |
|
|
804 |
|
|
|
6,271 |
|
Change in: |
|
|
|
|
|
|
|
|
Hedging Collateral Deposits |
|
|
(50,692 |
) |
|
|
(12,809 |
) |
Receivables and Unbilled Utility Revenue |
|
|
(123,393 |
) |
|
|
(101,881 |
) |
Gas Stored Underground and Materials and Supplies |
|
|
30,144 |
|
|
|
37,932 |
|
Prepayments and Other Current Assets |
|
|
57,447 |
|
|
|
31,318 |
|
Accounts Payable |
|
|
33,234 |
|
|
|
12,178 |
|
Amounts Payable to Customers |
|
|
(12,634 |
) |
|
|
(41,442 |
) |
Customer Advances |
|
|
(24,938 |
) |
|
|
(21,840 |
) |
Customer Security Deposits |
|
|
(256 |
) |
|
|
1,996 |
|
Other Accruals and Current Liabilities |
|
|
93,473 |
|
|
|
90,499 |
|
Other Assets |
|
|
15,710 |
|
|
|
11,285 |
|
Other Liabilities |
|
|
(23,685 |
) |
|
|
(535 |
) |
|
Net Cash Provided by Operating Activities |
|
|
343,222 |
|
|
|
279,331 |
|
|
|
|
|
|
|
|
|
|
|
INVESTING ACTIVITIES |
|
|
|
|
|
|
|
|
Capital Expenditures |
|
|
(392,338 |
) |
|
|
(230,530 |
) |
Net Proceeds from Sale of Unconsolidated Subsidiaries |
|
|
59,365 |
|
|
|
|
|
Other |
|
|
(3,097 |
) |
|
|
(115 |
) |
|
Net Cash Used in Investing Activities |
|
|
(336,070 |
) |
|
|
(230,645 |
) |
|
|
|
|
|
|
|
|
|
|
FINANCING ACTIVITIES |
|
|
|
|
|
|
|
|
Excess Tax Benefits Associated with Stock-Based
Compensation Awards |
|
|
|
|
|
|
13,437 |
|
Reduction of Long-Term Debt |
|
|
(200,000 |
) |
|
|
|
|
Dividends Paid on Common Stock |
|
|
(56,723 |
) |
|
|
(54,096 |
) |
Net Proceeds from Issuance (Repurchase) of Common Stock |
|
|
(2,833 |
) |
|
|
10,724 |
|
|
Net Cash Used in Financing Activities |
|
|
(259,556 |
) |
|
|
(29,935 |
) |
|
Net Increase (Decrease) in Cash and Temporary Cash
Investments |
|
|
(252,404 |
) |
|
|
18,751 |
|
|
|
|
|
|
|
|
|
|
Cash and Temporary Cash Investments at October 1 |
|
|
397,171 |
|
|
|
410,053 |
|
|
|
|
|
|
|
|
|
|
|
Cash and Temporary Cash Investments at March 31 |
|
$ |
144,767 |
|
|
$ |
428,804 |
|
|
See Notes to Condensed Consolidated Financial Statements
-10-
|
|
|
Item 1. |
|
Financial Statements (Cont.) |
National Fuel Gas Company
Consolidated Statements of Comprehensive Income
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
March 31, |
(Thousands of Dollars) |
|
2011 |
|
2010 |
Net Income Available for Common Stock |
|
$ |
115,611 |
|
|
$ |
80,428 |
|
|
Other Comprehensive Income (Loss), Before Tax: |
|
|
|
|
|
|
|
|
Foreign Currency Translation Adjustment |
|
|
|
|
|
|
47 |
|
Unrealized Gain on Securities Available for Sale Arising
During the Period |
|
|
897 |
|
|
|
1,158 |
|
Unrealized Gain (Loss) on Derivative Financial Instruments
Arising During the Period |
|
|
(40,844 |
) |
|
|
27,633 |
|
Reclassification Adjustment for Realized Gains on
Derivative Financial Instruments in Net Income |
|
|
(7,212 |
) |
|
|
(5,590 |
) |
|
Other Comprehensive Income (Loss), Before Tax |
|
|
(47,159 |
) |
|
|
23,248 |
|
|
Income Tax Expense Related to Unrealized Gain on
Securities Available for Sale Arising During the Period |
|
|
337 |
|
|
|
438 |
|
Income Tax Expense (Benefit) Related to Unrealized Gain (Loss)
on Derivative Financial Instruments Arising During the Period |
|
|
(16,778 |
) |
|
|
11,310 |
|
Reclassification Adjustment for Income Tax Expense on
Realized Gains from Derivative Financial Instruments
In Net Income |
|
|
(2,847 |
) |
|
|
(2,300 |
) |
|
Income Taxes Net |
|
|
(19,288 |
) |
|
|
9,448 |
|
|
Other Comprehensive Income (Loss) |
|
|
(27,871 |
) |
|
|
13,800 |
|
|
Comprehensive Income |
|
$ |
87,740 |
|
|
$ |
94,228 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended |
|
|
March 31, |
(Thousands of Dollars) |
|
2011 |
|
2010 |
Net Income Available for Common Stock |
|
$ |
174,154 |
|
|
$ |
144,927 |
|
|
Other Comprehensive Income (Loss), Before Tax: |
|
|
|
|
|
|
|
|
Foreign Currency Translation Adjustment |
|
|
17 |
|
|
|
64 |
|
Reclassification Adjustment for Realized Foreign Currency
Transaction Loss in Net Income |
|
|
34 |
|
|
|
|
|
Unrealized Gain on Securities Available for Sale Arising
During the Period |
|
|
3,438 |
|
|
|
445 |
|
Unrealized Gain (Loss) on Derivative Financial Instruments
Arising During the Period |
|
|
(67,980 |
) |
|
|
22,780 |
|
Reclassification Adjustment for Realized Gains on
Derivative Financial Instruments in Net Income |
|
|
(16,265 |
) |
|
|
(17,643 |
) |
|
Other Comprehensive Income (Loss), Before Tax |
|
|
(80,756 |
) |
|
|
5,646 |
|
|
Income Tax Expense Related to Unrealized Gain on
Securities Available for Sale Arising During the Period |
|
|
1,298 |
|
|
|
167 |
|
Income Tax Expense (Benefit) Related to Unrealized Gain (Loss)
on Derivative Financial Instruments Arising During the Period |
|
|
(27,946 |
) |
|
|
9,247 |
|
Reclassification Adjustment for Income Tax Expense on
Realized Gains from Derivative Financial Instruments
In Net Income |
|
|
(6,572 |
) |
|
|
(7,262 |
) |
|
Income Taxes Net |
|
|
(33,220 |
) |
|
|
2,152 |
|
|
Other Comprehensive Income (Loss) |
|
|
(47,536 |
) |
|
|
3,494 |
|
|
Comprehensive Income |
|
$ |
126,618 |
|
|
$ |
148,421 |
|
|
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. This includes the reclassification of accrued capital expenditures of $55.5 million
from Accounts Payable to Other Accruals and Current Liabilities on the Consolidated Balance Sheet
at September 30, 2010. This reclassification did not impact the
Consolidated Statement of Income or the Consolidated Statement of
Cash Flows for any of the periods presented.
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, 2010, 2009 and 2008 that
are included in the Companys 2010 Form 10-K. The consolidated financial statements for the year
ended September 30, 2011 will be audited by the Companys independent registered public accounting
firm after the end of the fiscal year.
The earnings for the six months ended March 31, 2011 should not be taken as a prediction of
earnings for the entire fiscal year ending September 30, 2011. 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 8 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 March 31, 2011, the Company accrued $43.9 million of capital expenditures in the
Exploration and Production segment, the majority of which was in the Appalachian region. The
Company also accrued $2.0 million of capital expenditures in the Pipeline and Storage segment at
March 31, 2011. These amounts were excluded from the Consolidated Statement of Cash Flows at March
31, 2011 since they represent non-cash investing activities at that date. Accrued capital
expenditures at March 31, 2011 are included in Other Accruals and Current Liabilities on the
Consolidated Balance Sheet.
At September 30, 2010, the Company accrued $55.5 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 September 30, 2010 since it
represented a non-cash investing activity at that date. These capital expenditures were paid during
the quarter ended December 31, 2010 and have been included in the Consolidated Statement of Cash
Flows for the six months ended March 31, 2011. Accrued capital expenditures at September 30, 2010
are included in Other Accruals and Current Liabilities on the Consolidated Balance Sheet.
-12-
|
|
|
Item 1. |
|
Financial Statements (Cont.) |
At March 31, 2010, the Company accrued $15.3 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 March 31, 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 six
months ended March 31, 2010.
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 March 31, 2011, the Company had
hedging collateral deposits of $6.9 million related to its exchange-traded futures contracts and
$54.9 million related to its over-the-counter crude oil swap agreements. At September 30, 2010,
the Company had hedging collateral deposits of $10.1 million related to its exchange-traded futures
contracts and $1.0 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 instruments liability or asset balances.
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 $88.6 million at March 31, 2011, 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 $180.8 million and $151.2 million at March 31, 2011 and September
30, 2010, respectively. 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 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. In accordance with the SEC final rule on Modernization of Oil
and Gas Reporting, the natural gas and oil prices used to calculate the full cost ceiling (as of
March 31, 2011) are based on an unweighted arithmetic average of the first day of the month oil and
gas prices for each month within the twelve-month period prior to the end of the
reporting period. If
-13-
|
|
|
Item 1. |
|
Financial Statements (Cont.) |
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. At March 31, 2011, 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 March 31, 2011.
Accumulated Other Comprehensive Loss. The components of Accumulated Other Comprehensive Loss, net
of related tax effect, are as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
At March 31, 2011 |
|
|
At September 30, 2010 |
|
Funded Status of the Pension and
Other Post-Retirement Benefit Plans |
|
$ |
(79,465 |
) |
|
$ |
(79,465 |
) |
Cumulative Foreign Currency
Translation Adjustment |
|
|
|
|
|
|
(51 |
) |
Net Unrealized Gain (Loss) on Derivative
Financial Instruments |
|
|
(16,851 |
) |
|
|
32,876 |
|
Net Unrealized Gain on Securities
Available for Sale |
|
|
3,795 |
|
|
|
1,655 |
|
|
|
|
|
|
|
|
Accumulated Other Comprehensive
Loss |
|
$ |
(92,521 |
) |
|
$ |
(44,985 |
) |
|
|
|
|
|
|
|
Other Current Assets. The components of the Companys Other Current Assets are as follows (in
thousands):
|
|
|
|
|
|
|
|
|
|
|
At March 31, 2011 |
|
|
At September 30, 2010 |
|
Prepayments |
|
$ |
6,779 |
|
|
$ |
13,884 |
|
Prepaid Property and Other Taxes |
|
|
20,507 |
|
|
|
12,413 |
|
Federal Income Taxes Receivable |
|
|
16,399 |
|
|
|
56,334 |
|
State Income Taxes Receivable |
|
|
9,290 |
|
|
|
18,007 |
|
Fair Values of Firm Commitments |
|
|
5,547 |
|
|
|
15,331 |
|
|
|
|
|
|
|
|
|
|
$ |
58,522 |
|
|
$ |
115,969 |
|
|
|
|
|
|
|
|
Earnings Per Common Share. Basic earnings per common share is computed by dividing net 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, SARs and restricted stock units. The diluted weighted
average shares outstanding shown on the Consolidated Statements of Income reflects the potential
dilution as a result of these securities as determined using the Treasury Stock Method. Stock
options, SARs and restricted stock units that are antidilutive are excluded from the calculation of
diluted earnings per common share. There were 10,959 and 140 SARs excluded as being antidilutive
for the quarter and six months ended March 31, 2011, respectively. For both the quarters and six
months ended March 31, 2011 and March 31, 2010, there were no stock options or restricted stock
units excluded as being antidilutive. There were 145,450 and 84,058 SARs excluded as being
antidilutive for the quarter and six months ended March 31, 2010, respectively.
Stock-Based Compensation. During the six months ended March 31, 2011, the Company granted 180,000
non-performance based SARs having a weighted average exercise price of $63.87 per share. The
weighted average grant date fair value of these SARs was $15.33 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 March 31, 2011. The non-performance based SARs granted during the six months
ended March 31, 2011 vest and become
-14-
|
|
|
Item 1. |
|
Financial Statements (Cont.) |
exercisable annually in one-third increments. The weighted average grant date fair value of these
non-performance based SARs granted during the six months ended March 31, 2011 was estimated on the
date of grant using the same accounting treatment that is applied for stock options.
There were no stock options granted during the quarter or six months ended March 31, 2011.
The Company did not recognize a tax benefit related to the exercise of stock options for the
calendar year ended December 31, 2010 due to tax loss carryforwards. The Company expects to
recognize a tax benefit of $18.1 million in Paid in Capital related to calendar 2010 stock option
exercises in future years as the tax loss carryforward is utilized.
The Company granted 47,250 restricted share awards (non-vested stock as defined by the current
accounting literature) during the six months ended March 31, 2011. The weighted average fair value
of such restricted shares was $63.98 per share. In addition, the Company granted 28,900 restricted
stock units during the six months ended March 31, 2011. The weighted average fair value of such
restricted stock units was $58.23 per share. Restricted stock units represent the right to receive
shares of common stock of the Company (or the equivalent value in cash or a combination of cash and
shares of common stock of the Company, as determined by the Company) at the end of a specified time
period. These restricted stock units do not entitle the participant to receive dividends during the
vesting period. The accounting for these restricted stock units is the same as the accounting for
restricted share awards, except that the fair value at the date of grant of the restricted stock
units must be reduced by the present value of forgone dividends over the vesting term of the award.
There were no restricted share awards or restricted stock units granted during the quarter ended
March 31, 2011.
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 March 31, 2011 and September 30, 2010. Financial assets and liabilities are
classified in their entirety based on the lowest level of input that is significant to the fair
value measurement.
-15-
|
|
|
Item 1. |
|
Financial Statements (Cont.) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Recurring Fair Value Measures |
|
At fair value as of March 31, 2011 |
(Thousands of Dollars) |
|
Level 1 |
|
Level 2 |
|
Level 3 |
|
Total |
|
Assets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash Equivalents Money Market Mutual Funds |
|
$ |
115,924 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
115,924 |
|
Derivative Financial Instruments: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Over the Counter Swaps Oil |
|
|
|
|
|
|
(777 |
) |
|
|
|
|
|
|
(777 |
) |
Over the Counter Swaps Gas |
|
|
|
|
|
|
38,485 |
|
|
|
|
|
|
|
38,485 |
|
Other Investments: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balanced Equity Mutual Fund |
|
|
21,786 |
|
|
|
|
|
|
|
|
|
|
|
21,786 |
|
Common Stock Financial Services Industry |
|
|
6,991 |
|
|
|
|
|
|
|
|
|
|
|
6,991 |
|
Other Common Stock |
|
|
247 |
|
|
|
|
|
|
|
|
|
|
|
247 |
|
Hedging Collateral Deposits |
|
|
61,826 |
|
|
|
|
|
|
|
|
|
|
|
61,826 |
|
|
|
|
Total |
|
$ |
206,774 |
|
|
$ |
37,708 |
|
|
$ |
|
|
|
$ |
244,482 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative Financial Instruments: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity Futures Contracts Gas |
|
$ |
2,846 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
2,846 |
|
Over the Counter Swaps Oil |
|
|
|
|
|
|
|
|
|
|
71,913 |
|
|
|
71,913 |
|
Over the Counter Swaps Gas |
|
|
|
|
|
|
(4,644 |
) |
|
|
|
|
|
|
(4,644 |
) |
|
|
|
Total |
|
$ |
2,846 |
|
|
$ |
(4,644 |
) |
|
$ |
71,913 |
|
|
$ |
70,115 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Net Assets/(Liabilities) |
|
$ |
203,928 |
|
|
$ |
42,352 |
|
|
$ |
(71,913 |
) |
|
$ |
174,367 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Recurring Fair Value Measures |
|
At fair value as of September 30, 2010 |
(Thousands of Dollars) |
|
Level 1 |
|
Level 2 |
|
Level 3 |
|
Total |
|
Assets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash Equivalents Money Market Mutual Funds |
|
$ |
277,423 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
277,423 |
|
Derivative Financial Instruments: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Over the Counter Swaps Gas |
|
|
|
|
|
|
67,387 |
|
|
|
|
|
|
|
67,387 |
|
Over the Counter Swaps Oil |
|
|
|
|
|
|
|
|
|
|
(2,203 |
) |
|
|
(2,203 |
) |
Other Investments: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balanced Equity Mutual Fund |
|
|
17,256 |
|
|
|
|
|
|
|
|
|
|
|
17,256 |
|
Common Stock Financial Services Industry |
|
|
4,991 |
|
|
|
|
|
|
|
|
|
|
|
4,991 |
|
Other Common Stock |
|
|
241 |
|
|
|
|
|
|
|
|
|
|
|
241 |
|
Hedging Collateral Deposits |
|
|
11,134 |
|
|
|
|
|
|
|
|
|
|
|
11,134 |
|
|
|
|
Total |
|
$ |
311,045 |
|
|
$ |
67,387 |
|
|
$ |
(2,203 |
) |
|
$ |
376,229 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative Financial Instruments: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity Futures Contracts Gas |
|
$ |
5,840 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
5,840 |
|
Over the Counter Swaps Oil |
|
|
|
|
|
|
|
|
|
|
14,280 |
|
|
|
14,280 |
|
Over the Counter Swaps Gas |
|
|
|
|
|
|
40 |
|
|
|
|
|
|
|
40 |
|
|
|
|
Total |
|
$ |
5,840 |
|
|
$ |
40 |
|
|
$ |
14,280 |
|
|
$ |
20,160 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Net Assets/(Liabilities) |
|
$ |
305,205 |
|
|
$ |
67,347 |
|
|
$ |
(16,483 |
) |
|
$ |
356,069 |
|
|
|
|
Derivative Financial Instruments
At March 31, 2011 and September 30, 2010, the derivative financial instruments reported in
Level 1 consist of natural gas NYMEX futures contracts used in the Companys Energy Marketing and
Pipeline and Storage segments. Hedging collateral deposits of $6.9 million (at March 31, 2011) and
$10.1 million (at September 30, 2010), which are associated with these futures contracts have
been reported in Level 1 as
-16-
|
|
|
Item 1. |
|
Financial Statements (Cont.) |
well. The derivative financial instruments reported in Level 2 at March 31, 2011 consist of crude
oil and natural gas price swap agreements used in the Companys Exploration and Production and
Energy Marketing segments. At September 30, 2010, the derivative financial instruments reported in
Level 2 consist of natural gas price swap agreements used in the Companys Exploration and
Production and Energy Marketing segments. The fair value of these price 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 and crude oil
trading markets). The derivative financial instruments reported in Level 3 consist of the majority
of the Companys Exploration and Production segments crude oil price swap agreements at March 31,
2011 and all of its crude oil price swap agreements at September 30, 2010. Hedging collateral
deposits of $54.9 million and $1.0 million associated with these crude oil price swap agreements
have been reported in Level 1 at March 31, 2011 and September 30, 2010, respectively. The fair
value of the crude oil price 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 assets have been reduced by $0.2 million and $1.0 million at March 31, 2011 and
September 30, 2010, respectively. Based on an assessment of the Companys credit risk, the fair
market value of the price swap agreements reported as Level 2 and Level 3 liabilities have been
reduced by less than $0.1 million and $0.3 million at March 31, 2011 and September 30, 2010,
respectively. 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 quarters and six
months ended March 31, 2011 and 2010, respectively. For the quarters and six months ended March 31,
2011 and March 31, 2010, no transfers in or out of Level 1 or Level 2 occurred. There were no
purchases or sales of derivative financial instruments during the periods presented in the tables
below. All settlements of the derivative financial instruments are reflected in the Gains/Losses
Realized and Included in Earnings column of the tables below.
Fair Value Measurements Using Unobservable Inputs (Level 3)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Gains/Losses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gains/Losses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized and |
|
|
|
|
|
|
|
|
|
|
Gains/Losses |
|
Included in |
|
|
|
|
|
|
|
|
|
|
Realized and |
|
Other |
|
Transfer |
|
|
|
|
January 1, |
|
Included in |
|
Comprehensive |
|
In/Out of |
|
March 31, |
(Thousands of Dollars) |
|
2011 |
|
Earnings |
|
Income (Loss) |
|
Level 3 |
|
2011 |
|
Derivative Financial Instruments(2) |
|
$ |
(37,407 |
) |
|
$ |
(13,189 |
)(1) |
|
$ |
(21,317 |
) |
|
$ |
|
|
|
$ |
(71,913 |
) |
|
|
|
(1) |
|
Amounts are reported in Operating Revenues in the Consolidated Statement of
Income for the three months ended March 31, 2011. |
|
(2) |
|
Derivative Financial Instruments are shown on a net basis. |
Fair Value Measurements Using Unobservable Inputs (Level 3)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Gains/Losses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gains/Losses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized and |
|
|
|
|
|
|
|
|
|
|
Gains/Losses |
|
Included in |
|
|
|
|
|
|
|
|
|
|
Realized and |
|
Other |
|
Transfer |
|
|
|
|
October 1, |
|
Included in |
|
Comprehensive |
|
In/Out of |
|
March 31, |
(Thousands of Dollars) |
|
2010 |
|
Earnings |
|
Income (Loss) |
|
Level 3 |
|
2011 |
|
Derivative Financial Instruments(2) |
|
$ |
(16,483 |
) |
|
$ |
(15,992 |
)(1) |
|
$ |
(39,438 |
) |
|
$ |
|
|
|
$ |
(71,913 |
) |
|
|
|
(1) |
|
Amounts are reported in Operating Revenues in the Consolidated Statement of
Income for the six months ended March 31, 2011. |
|
(2) |
|
Derivative Financial Instruments are shown on a net basis. |
-17-
|
|
|
Item 1. |
|
Financial Statements (Cont.) |
Fair Value Measurements Using Unobservable Inputs (Level 3)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Gains/Losses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gains/Losses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized and |
|
|
|
|
|
|
|
|
|
|
Gains/Losses |
|
Included in |
|
|
|
|
|
|
|
|
|
|
Realized and |
|
Other |
|
Transfer |
|
|
|
|
January 1, |
|
Included in |
|
Comprehensive |
|
In/Out of |
|
March 31, |
(Thousands of Dollars) |
|
2010 |
|
Earnings |
|
Income (Loss) |
|
Level 3 |
|
2010 |
|
Derivative Financial Instruments(2) |
|
$ |
(149 |
) |
|
$ |
(1,662 |
)(1) |
|
$ |
(12,289 |
) |
|
$ |
|
|
|
$ |
(14,100 |
) |
|
|
|
(1) |
|
Amounts are reported in Operating Revenues in the Consolidated Statement of
Income for the three months ended March 31, 2010. |
|
(2) |
|
Derivative Financial Instruments are shown on a net basis. |
Fair Value Measurements Using Unobservable Inputs (Level 3)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Gains/Losses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gains/Losses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized and |
|
|
|
|
|
|
|
|
|
|
Gains/Losses |
|
Included in |
|
|
|
|
|
|
|
|
|
|
Realized and |
|
Other |
|
Transfer |
|
|
|
|
October 1, |
|
Included in |
|
Comprehensive |
|
In/Out of |
|
March 31, |
(Thousands of Dollars) |
|
2009 |
|
Earnings |
|
Income (Loss) |
|
Level 3 |
|
2010 |
|
Derivative Financial Instruments(2) |
|
$ |
26,969 |
|
|
$ |
(4,797 |
)(1) |
|
$ |
(36,272 |
) |
|
$ |
|
|
|
$ |
(14,100 |
) |
|
|
|
(1) |
|
Amounts are reported in Operating Revenues in the Consolidated Statement of
Income for the six months ended March 31, 2010. |
|
(2) |
|
Derivative Financial Instruments are shown on a net basis. |
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 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March 31, 2011 |
|
September 30, 2010 |
|
|
Carrying |
|
|
|
|
|
Carrying |
|
|
|
|
Amount |
|
Fair Value |
|
Amount |
|
Fair Value |
Long-Term Debt |
|
$ |
1,049,000 |
|
|
$ |
1,190,130 |
|
|
$ |
1,249,000 |
|
|
$ |
1,423,349 |
|
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 $54.7 million at March 31, 2011 and $55.4 million at
September 30, 2010. The fair value of the equity mutual fund was $21.8 million at March 31, 2011
and $17.3 million at September 30, 2010. The gross unrealized gain on this equity mutual fund was
$1.4 million at March 31, 2011. The unrealized gain on the equity mutual fund at September 30,
2010 was negligible as the fair value was approximately equal to the cost basis. The fair value of
the stock of an insurance company was $7.0 million at March 31, 2011 and $5.0 million at September
30, 2010. The gross unrealized gain on this stock was $4.6 million at March 31, 2011 and $2.6
million at September 30, 2010. The insurance contracts and marketable equity securities are
primarily informal funding mechanisms for various benefit obligations the Company has to certain
employees.
-18-
|
|
|
Item 1. |
|
Financial Statements (Cont.) |
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 March 31, 2011 and September 30, 2010 as shown in the table below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Values of Derivative Instruments |
|
|
(Dollar Amounts in Thousands) |
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 |
|
|
|
|
March 31, |
|
Financial |
|
|
|
|
|
Financial |
|
|
|
|
2011 |
|
Instruments |
|
$ |
37,708 |
|
|
Instruments |
|
$ |
70,115 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value of |
|
|
|
|
|
Fair Value of |
|
|
|
|
Commodity |
|
Derivative |
|
|
|
|
|
Derivative |
|
|
|
|
Contracts at |
|
Financial |
|
|
|
|
|
Financial |
|
|
|
|
September 30, 2010 |
|
Instruments |
|
$ |
65,184 |
|
|
Instruments |
|
$ |
20,160 |
|
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 March 31,
2011 and September 30, 2010.
|
|
|
|
|
|
|
|
|
Derivatives |
|
Fair Values of Derivative Instruments |
Designated as |
|
(Dollar Amounts in Thousands) |
Hedging |
|
Gross Asset Derivatives |
|
Gross Liability Derivatives |
Instruments |
|
Fair Value |
|
Fair Value |
Commodity Contracts
at March 31,
2011 |
|
$ |
47,243 |
|
|
$ |
79,650 |
|
Commodity Contracts
at September 30,
2010 |
|
$ |
77,837 |
|
|
$ |
32,813 |
|
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.
-19-
|
|
|
Item 1. |
|
Financial Statements (Cont.) |
As of March 31, 2011, 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
|
|
55.6 Bcf (all short positions) |
Crude Oil
|
|
3,138,000 Bbls (all short positions) |
As of March 31, 2011, the Companys Energy Marketing segment had the following commodity
derivative contracts (futures contracts and swaps) outstanding to hedge forecasted sales (where the
Company uses short positions to mitigate the risk associated with natural gas price decreases and
its impact on decreasing revenues and earnings) and purchases (where the Company uses long
positions (i.e. positions that pay-off in the event of commodity price increases) to mitigate the
risk of increasing natural gas prices, which would lead to increased purchased gas expense and
decreased earnings):
|
|
|
Commodity |
|
Units |
Natural Gas
|
|
6.2 Bcf (3.5 Bcf short positions (forecasted storage
withdrawals) and 2.7 Bcf long positions (forecasted storage
injections)) |
As of March 31, 2011, the Companys Pipeline and Storage segment has 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
|
|
1.2 Bcf (all short positions) |
As of March 31, 2011, the Companys Exploration and Production segment had $30.2 million
($17.8 million after tax) of net hedging losses included in the accumulated other comprehensive
income (loss) balance. It is expected that $14.4 million ($8.5 million after tax) of these losses
will be reclassified into the Consolidated Statement of Income (Loss) 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 (loss) 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).
As of March 31, 2011, the Companys Energy Marketing segment had $1.8 million ($1.1 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 (Loss) 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
(loss) 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).
As of March 31, 2011, the Companys Pipeline and Storage segment had $0.2 million ($0.1
million after tax) of net hedging losses 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 (Loss) 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 (loss) 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).
-20-
|
|
|
Item 1. |
|
Financial Statements (Cont.) |
The Effect of Derivative Financial Instruments on the Statement of Financial Performance for the
Three Months Ended March 31, 2011 and 2010 (Thousands of Dollars)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Location of |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative Gain |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
or (Loss) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reclassified |
|
|
|
|
|
|
|
|
|
|
|
|
Amount of |
|
|
from |
|
|
Amount of Derivative |
|
|
|
|
|
|
|
|
|
Derivative Gain or |
|
|
Accumulated |
|
|
Gain or (Loss) |
|
|
Location of |
|
|
|
|
|
|
(Loss) Recognized |
|
|
Other |
|
|
Reclassified from |
|
|
Derivative Gain |
|
|
|
|
|
|
in Other |
|
|
Comprehensive |
|
|
Accumulated Other |
|
|
or (Loss) |
|
|
Derivative Gain or |
|
|
|
Comprehensive |
|
|
Income (Loss) |
|
|
Comprehensive |
|
|
Recognized in the |
|
|
(Loss) Recognized |
|
|
|
Income (Loss) on |
|
|
on the |
|
|
Income (Loss) on the |
|
|
Consolidated |
|
|
in the Consolidated |
|
|
|
the Consolidated |
|
|
Consolidated |
|
|
Consolidated Balance |
|
|
Statement of |
|
|
Statement of |
|
|
|
Statement of |
|
|
Balance Sheet |
|
|
Sheet into the |
|
|
Income |
|
|
Income (Ineffective |
|
|
|
Comprehensive |
|
|
into the |
|
|
Consolidated |
|
|
(Ineffective |
|
|
Portion and Amount |
|
|
|
Income (Loss) |
|
|
Consolidated |
|
|
Statement of Income |
|
|
Portion and |
|
|
Excluded from |
|
Derivatives in |
|
(Effective Portion) |
|
|
Statement of |
|
|
(Effective Portion) for |
|
|
Amount |
|
|
Effectiveness |
|
Cash Flow |
|
for the Three |
|
|
Income |
|
|
the Three Months |
|
|
Excluded from |
|
|
Testing) for the |
|
Hedging |
|
Months Ended |
|
|
(Effective |
|
|
Ended |
|
|
Effectiveness |
|
|
Three Months Ended |
|
Relationships |
|
March 31, |
|
|
Portion) |
|
|
March 31, |
|
|
Testing) |
|
|
March 31, |
|
|
|
2011 |
|
|
2010 |
|
|
|
|
|
2011 |
|
|
2010 |
|
|
|
|
|
2011 |
|
|
2010 |
|
Commodity Contracts
Exploration &
Production segment |
|
$ |
(41,586 |
) |
|
$ |
24,375 |
|
|
Operating
Revenue |
|
$ |
1,956 |
|
|
$ |
5,538 |
|
|
Operating
Revenue |
|
$ |
|
|
|
$ |
|
|
Commodity Contracts
Energy Marketing
segment |
|
$ |
872 |
|
|
$ |
2,278 |
|
|
Purchased
Gas |
|
$ |
5,256 |
|
|
$ |
(470 |
) |
|
Purchased
Gas |
|
$ |
|
|
|
$ |
|
|
Commodity Contracts
Pipeline &
Storage segment |
|
$ |
(130 |
) |
|
$ |
980 |
|
|
Operating
Revenue |
|
$ |
|
|
|
$ |
522 |
|
|
Operating
Revenue |
|
$ |
|
|
|
$ |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
(40,844 |
) |
|
$ |
27,633 |
|
|
|
|
|
|
$ |
7,212 |
|
|
$ |
5,590 |
|
|
|
|
|
|
$ |
|
|
|
$ |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
-21-
|
|
|
Item 1. |
|
Financial Statements (Cont.) |
The Effect of Derivative Financial Instruments on the Statement of Financial Performance for the
Six Months Ended March 31, 2011 and 2010 (Thousands of Dollars)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Location of |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative Gain |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
or (Loss) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reclassified |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
from |
|
|
|
|
|
|
|
|
|
|
Location of |
|
|
|
|
|
|
Amount of |
|
|
Accumulated |
|
|
Amount of Derivative |
|
|
Derivative Gain |
|
|
|
|
|
|
Derivative Gain or |
|
|
Other |
|
|
Gain or (Loss) |
|
|
or (Loss) |
|
|
|
|
|
|
(Loss) Recognized |
|
|
Comprehensive |
|
|
Reclassified from |
|
|
Recognized in |
|
|
Derivative Gain or |
|
|
|
in Other |
|
|
Income (Loss) |
|
|
Accumulated Other |
|
|
the |
|
|
(Loss) Recognized |
|
|
|
Comprehensive |
|
|
on the |
|
|
Comprehensive |
|
|
Consolidated |
|
|
in the Consolidated |
|
|
|
Income (Loss) on |
|
|
Consolidated |
|
|
Income (Loss) on the |
|
|
Statement of |
|
|
Statement of |
|
|
|
the Consolidated |
|
|
Balance Sheet |
|
|
Consolidated Balance |
|
|
Income |
|
|
Income (Ineffective |
|
|
|
Statement of |
|
|
into the |
|
|
Sheet into the |
|
|
(Ineffective |
|
|
Portion and Amount |
|
|
|
Comprehensive |
|
|
Consolidated |
|
|
Consolidated |
|
|
Portion and |
|
|
Excluded from |
|
Derivatives in |
|
Income (Loss) |
|
|
Statement of |
|
|
Statement of Income |
|
|
Amount |
|
|
Effectiveness |
|
Cash Flow |
|
(Effective Portion) |
|
|
Income |
|
|
(Effective Portion) for |
|
|
Excluded from |
|
|
Testing) for the Six |
|
Hedging |
|
for the Six Months Ended |
|
|
(Effective |
|
|
the Six Months Ended |
|
|
Effectiveness |
|
|
Months Ended |
|
Relationships |
|
March 31, |
|
|
Portion) |
|
|
March 31, |
|
|
Testing) |
|
|
March 31, |
|
|
|
2011 |
|
|
2010 |
|
|
|
|
|
2011 |
|
|
2010 |
|
|
|
|
|
2011 |
|
|
2010 |
|
Commodity Contracts
Exploration &
Production segment |
|
$ |
(68,368 |
) |
|
$ |
16,465 |
|
|
Operating
Revenue |
|
$ |
10,963 |
|
|
$ |
17,578 |
|
|
Operating
Revenue |
|
$ |
|
|
|
$ |
|
|
Commodity Contracts
Energy Marketing
segment |
|
$ |
603 |
|
|
$ |
5,303 |
|
|
Purchased
Gas |
|
$ |
5,302 |
|
|
$ |
(447 |
) |
|
Purchased
Gas |
|
$ |
|
|
|
$ |
|
|
Commodity Contracts
Pipeline &
Storage segment |
|
$ |
(215 |
) |
|
$ |
1,012 |
|
|
Operating
Revenue |
|
$ |
|
|
|
$ |
512 |
|
|
Operating
Revenue |
|
$ |
|
|
|
$ |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
(67,980 |
) |
|
$ |
22,780 |
|
|
|
|
|
|
$ |
16,265 |
|
|
$ |
17,643 |
|
|
|
|
|
|
$ |
|
|
|
$ |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 March 31,
2011, the Companys Energy Marketing segment had fair value hedges covering approximately 10.6 Bcf
(7.9 Bcf of fixed price sales commitments (all long positions) and 2.7 Bcf of fixed price purchase
commitments (all short positions)). For derivative instruments that are designated and qualify
-22-
|
|
|
Item 1. |
|
Financial Statements (Cont.) |
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 |
|
$ |
10,625,997 |
|
|
$ |
(10,625,997 |
) |
Purchased Gas |
|
$ |
(1,470,609 |
) |
|
$ |
1,470,609 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amount of Derivative Gain or (Loss) |
|
|
|
|
|
|
|
Recognized in the Consolidated |
|
Derivatives in |
|
Location of Derivative Gain or (Loss) |
|
|
Statement of Income for the Six |
|
Fair Value Hedging |
|
Recognized in the Consolidated |
|
|
Months Ended March 31, 2011 |
|
Relationships |
|
Statement of Income |
|
|
(In Thousands) |
|
Commodity Contracts
Energy Marketing
segment
(1) |
|
Operating Revenues |
|
$ |
10,626 |
|
Commodity Contracts
Energy Marketing
segment
(2) |
|
Purchased Gas |
|
$ |
(1,167 |
) |
Commodity Contracts
Energy Marketing
segment
(3) |
|
Purchased Gas |
|
$ |
(304 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
9,155 |
|
|
|
|
|
|
|
|
|
|
|
|
(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
twelve counterparties of which nine are in a net gain position. The Company had derivative
financial instruments that were in loss positions with the other three counterparties. On average,
the Company had $4.1 million of credit exposure per counterparty in a gain position at March 31,
2011. The maximum credit exposure per counterparty in a gain position at March 31, 2011 was $7.9
million. The Company had not received any collateral from these counterparties at March 31, 2011
since the Companys gain position on such derivative financial instruments had not exceeded the
established thresholds at which the counterparties would be required to post collateral.
As of March 31, 2011, nine of the twelve 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 (applicable debt ratings), 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 (or if the current
liability were larger) and/or the Companys credit rating declined, then additional hedging
collateral deposits would be required. At March 31, 2011, the fair market value of the derivative
financial instrument assets with a credit-risk related contingency feature was $21.9 million
according to the Companys internal model (discussed in Note 2 Fair Value Measurements). At
March 31, 2011, the fair market value of the derivative financial instrument liabilities with a
credit-risk related contingency feature was $67.2 million according to the Companys internal model
(discussed in Note 2 Fair Value Measurements). The liability with one counterparty was $54.8
million. For its over-the-counter crude oil swap agreements, which are in a liability position,
the Company was required to post $54.9 million in hedging collateral deposits at March 31, 2011.
This is discussed in Note 1 under Hedging Collateral Deposits.
-23-
|
|
|
Item 1. |
|
Financial Statements (Cont.) |
For its exchange traded futures contracts, which are in a liability position, the Company had
posted $6.9 million in hedging collateral as of March 31, 2011. 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):
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended |
|
|
|
March 31, |
|
|
|
2011 |
|
|
2010 |
|
|
|
|
Current Income Taxes |
|
|
|
|
|
|
|
|
Federal |
|
$ |
|
|
|
$ |
39,245 |
|
State |
|
|
3,677 |
|
|
|
9,394 |
|
|
|
|
|
|
|
|
|
|
Deferred Income Taxes |
|
|
|
|
|
|
|
|
Federal |
|
|
87,598 |
|
|
|
33,447 |
|
State |
|
|
18,912 |
|
|
|
8,348 |
|
|
|
|
|
|
|
110,187 |
|
|
|
90,434 |
|
Deferred Investment Tax Credit |
|
|
(348 |
) |
|
|
(348 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
Total Income Taxes |
|
$ |
109,839 |
|
|
$ |
90,086 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Presented as Follows: |
|
|
|
|
|
|
|
|
Other Income |
|
$ |
(348 |
) |
|
$ |
(348 |
) |
Income Tax Expense Continuing Operations |
|
|
110,187 |
|
|
|
89,841 |
|
Income from Discontinued Operations |
|
|
|
|
|
|
593 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Income Taxes |
|
$ |
109,839 |
|
|
$ |
90,086 |
|
|
|
|
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):
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended |
|
|
|
March 31, |
|
|
|
2011 |
|
|
2010 |
|
|
|
|
U.S. Income Before Income Taxes |
|
$ |
283,993 |
|
|
$ |
235,013 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Income Tax Expense, Computed at Federal
Statutory Rate of 35% |
|
$ |
99,398 |
|
|
$ |
82,255 |
|
|
|
|
|
|
|
|
|
|
Increase (Reduction) in Taxes Resulting from: |
|
|
|
|
|
|
|
|
State Income Taxes |
|
|
14,683 |
|
|
|
11,532 |
|
Miscellaneous |
|
|
(4,242 |
) |
|
|
(3,701 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
Total Income Taxes |
|
$ |
109,839 |
|
|
$ |
90,086 |
|
|
|
|
-24-
|
|
|
Item 1. |
|
Financial Statements (Cont.) |
Significant components of the Companys deferred tax liabilities and assets were as follows
(in thousands):
|
|
|
|
|
|
|
|
|
|
|
At March 31, 2011 |
|
|
At September 30, 2010 |
|
|
|
|
Deferred Tax Liabilities: |
|
|
|
|
|
|
|
|
Property, Plant and Equipment |
|
$ |
966,524 |
|
|
$ |
849,869 |
|
Pension and Other Post-Retirement Benefit
Costs |
|
|
179,360 |
|
|
|
177,853 |
|
Other |
|
|
37,109 |
|
|
|
63,671 |
|
|
|
|
Total Deferred Tax Liabilities |
|
|
1,182,993 |
|
|
|
1,091,393 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred Tax Assets: |
|
|
|
|
|
|
|
|
Pension and Other Post-Retirement Benefit
Costs |
|
|
(225,461 |
) |
|
|
(223,588 |
) |
Tax Loss Carryforwards |
|
|
(16,237 |
) |
|
|
(9,772 |
) |
Other |
|
|
(89,388 |
) |
|
|
(81,751 |
) |
|
|
|
Total Deferred Tax Assets |
|
|
(331,086 |
) |
|
|
(315,111 |
) |
|
|
|
Total Net Deferred Income Taxes |
|
$ |
851,907 |
|
|
$ |
776,282 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Presented as Follows: |
|
|
|
|
|
|
|
|
Net Deferred Tax Liability/(Asset) Current |
|
$ |
(34,917 |
) |
|
$ |
(24,476 |
) |
Net Deferred Tax Liability Non-Current |
|
|
886,824 |
|
|
|
800,758 |
|
|
|
|
Total Net Deferred Income Taxes |
|
$ |
851,907 |
|
|
$ |
776,282 |
|
|
|
|
As a result of certain realization requirements of the authoritative guidance on stock-based
compensation, the table of deferred tax liabilities and assets shown above does not include certain
deferred tax assets at March 31, 2011 that arose directly from excess tax deductions related to
stock-based compensation. A tax benefit of $18.1 million relating to the excess stock-based
compensation deductions will be recorded in Paid in Capital in future years when such tax benefit
is realized.
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 $69.6 million at both March 31, 2011 and September 30, 2010. 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 $152.0 million and
$149.7 million at March 31, 2011 and September 30, 2010, respectively.
The Company files U.S. federal and various state income tax returns. The Internal Revenue
Service (IRS) is currently conducting an examination of the Company for fiscal 2010 and 2011 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. During fiscal 2009, consent was received from
the IRS National Office approving the Companys application to change its tax method of accounting
for certain capitalized costs relating to its utility property. During fiscal 2010, local IRS
examiners proposed to disallow most of the accounting method change recorded by the Company in
fiscal 2009. The Company has filed a protest with the IRS Appeals Office disputing the local IRS
findings.
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.
-25-
|
|
|
Item 1. |
|
Financial Statements (Cont.) |
Note 5 Capitalization
Common Stock. During the six months ended March 31, 2011, the Company issued 786,929 original
issue shares of common stock as a result of stock option and SARs exercises and 47,250 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 7,200 original issue shares of
common stock to the non-employee directors of the Company who receive compensation under the
Companys 2009 Non-Employee Director Equity Compensation Plan, as partial consideration for the
directors services during the six months ended March 31, 2011. Holders of stock options, SARs 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 six months ended March 31, 2011,
372,656 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 March 31, 2011 consists of
$150 million of 6.70% medium-term notes that mature in November 2011. Current Portion of Long-Term
Debt at September 30, 2010 consisted of $200 million of 7.50% notes that matured 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
$14.6 million.
At March 31, 2011, 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 $17.1 million to $21.3
million. The minimum estimated liability of $17.1 million, which includes the $14.6 million
discussed above, has been recorded on the Consolidated Balance Sheet at March 31, 2011. The
Company expects to recover its environmental clean-up costs through rate recovery.
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.
-26-
|
|
|
Item 1. |
|
Financial Statements (Cont.) |
Note 7 Discontinued Operations
On September 1, 2010, the Company sold its landfill gas operations in the states of Ohio,
Michigan, Kentucky, Missouri, Maryland and Indiana. Those operations consisted of short distance
landfill gas pipeline companies engaged in the purchase, sale and transportation of landfill gas.
The Companys landfill gas operations were maintained under the Companys wholly-owned subsidiary,
Horizon LFG. The decision to sell was based on progressing the Companys strategy of divesting its
smaller, non-core assets in order to focus on its core businesses, including the development of the
Marcellus Shale and the construction of key pipeline infrastructure projects throughout the
Appalachian region. As a result of the decision to sell the landfill gas operations, the Company
began presenting these operations as discontinued operations during the fourth quarter of 2010.
The following is selected financial information of the discontinued operations for the sale of
the Companys landfill gas operations:
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Six Months Ended |
|
|
|
March 31, |
|
|
March 31, |
|
(Thousands) |
|
2010 |
|
|
2010 |
|
Operating Revenues |
|
$ |
3,400 |
|
|
$ |
6,277 |
|
Operating Expenses |
|
|
2,445 |
|
|
|
4,845 |
|
|
|
|
|
|
|
|
Operating Income |
|
|
955 |
|
|
|
1,432 |
|
Other Interest Expense |
|
|
(4 |
) |
|
|
(11 |
) |
|
|
|
|
|
|
|
Income before Income Taxes |
|
|
951 |
|
|
|
1,421 |
|
Income Tax Expense |
|
|
397 |
|
|
|
593 |
|
|
|
|
|
|
|
|
Income from Discontinued Operations |
|
$ |
554 |
|
|
$ |
828 |
|
|
|
|
|
|
|
|
Note 8 Business Segment Information
The Company reports financial results for four segments: Utility, Pipeline and Storage,
Exploration and Production and Energy Marketing. The division of the Companys operations into
reportable segments is based upon a combination of factors including differences in products and
services, regulatory environment and geographic factors.
The data presented in the tables below reflect financial information for the segments and
reconciliations to consolidated amounts. As stated in the 2010 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 2010 Form 10-K. There have been no material changes in the amount of assets for any
operating segment from the amounts disclosed in the 2010 Form 10-K.
Quarter Ended March 31, 2011 (Thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploration |
|
|
|
|
|
Total |
|
|
|
|
|
Corporate and |
|
|
|
|
|
|
|
|
Pipeline and |
|
and |
|
|
|
|
|
Reportable |
|
|
|
|
|
Intersegment |
|
Total |
|
|
Utility |
|
Storage |
|
Production |
|
Energy Marketing |
|
Segments |
|
All Other |
|
Eliminations |
|
Consolidated |
Revenue from
External Customers |
|
$ |
361,745 |
|
|
$ |
39,669 |
|
|
$ |
137,430 |
|
|
$ |
121,321 |
|
|
$ |
660,165 |
|
|
$ |
472 |
|
|
$ |
244 |
|
|
$ |
660,881 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Intersegment Revenues |
|
$ |
6,635 |
|
|
$ |
20,632 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
27,267 |
|
|
$ |
2,538 |
|
|
$ |
(29,805 |
) |
|
$ |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment Profit: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income (Loss) |
|
$ |
33,081 |
|
|
$ |
10,955 |
|
|
$ |
33,299 |
|
|
$ |
6,299 |
|
|
$ |
83,634 |
|
|
$ |
32,181 |
|
|
$ |
(204 |
) |
|
$ |
115,611 |
|
-27-
Item 1. Financial Statements (Cont.)
Six Months Ended March 31, 2011 (Thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploration |
|
|
|
|
|
Total |
|
|
|
|
|
Corporate and |
|
|
|
|
|
|
|
|
Pipeline and |
|
and |
|
Energy |
|
Reportable |
|
|
|
|
|
Intersegment |
|
Total |
|
|
Utility |
|
Storage |
|
Production |
|
Marketing |
|
Segments |
|
All Other |
|
Eliminations |
|
Consolidated |
|
Revenue from
External Customers |
|
$ |
604,587 |
|
|
$ |
73,182 |
|
|
$ |
257,598 |
|
|
$ |
174,973 |
|
|
$ |
1,110,340 |
|
|
$ |
1,021 |
|
|
$ |
468 |
|
|
$ |
1,111,829 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Intersegment Revenues |
|
$ |
11,205 |
|
|
$ |
40,514 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
51,719 |
|
|
$ |
4,216 |
|
|
$ |
(55,935 |
) |
|
$ |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment Profit: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income (Loss) |
|
$ |
56,071 |
|
|
$ |
19,533 |
|
|
$ |
60,672 |
|
|
$ |
7,231 |
|
|
$ |
143,507 |
|
|
$ |
31,606 |
|
|
$ |
(959 |
) |
|
$ |
174,154 |
|
Quarter Ended March 31, 2010 (Thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploration |
|
|
|
|
|
Total |
|
|
|
|
|
Corporate and |
|
|
|
|
|
|
|
|
Pipeline and |
|
and |
|
Energy |
|
Reportable |
|
|
|
|
|
Intersegment |
|
Total |
|
|
Utility |
|
Storage |
|
Production |
|
Marketing |
|
Segments |
|
All Other |
|
Eliminations |
|
Consolidated |
|
Revenue from
External Customers |
|
$ |
348,593 |
|
|
$ |
40,971 |
|
|
$ |
109,158 |
|
|
$ |
158,537 |
|
|
$ |
657,259 |
|
|
$ |
10,503 |
|
|
$ |
218 |
|
|
$ |
667,980 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Intersegment Revenues |
|
$ |
6,149 |
|
|
$ |
20,565 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
26,714 |
|
|
$ |
|
|
|
$ |
(26,714 |
) |
|
$ |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment Profit: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (Loss) from
Continuing
Operations |
|
$ |
33,273 |
|
|
$ |
12,448 |
|
|
$ |
27,383 |
|
|
$ |
5,969 |
|
|
$ |
79,073 |
|
|
$ |
1,020 |
|
|
$ |
(219 |
) |
|
$ |
79,874 |
|
Six Months Ended March 31, 2010 (Thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploration |
|
|
|
|
|
Total |
|
|
|
|
|
Corporate and |
|
|
|
|
|
|
|
|
Pipeline and |
|
and |
|
Energy |
|
Reportable |
|
|
|
|
|
Intersegment |
|
Total |
|
|
Utility |
|
Storage |
|
Production |
|
Marketing |
|
Segments |
|
All Other |
|
Eliminations |
|
Consolidated |
|
Revenue from
External Customers |
|
$ |
580,997 |
|
|
$ |
75,475 |
|
|
$ |
215,511 |
|
|
$ |
230,273 |
|
|
$ |
1,102,256 |
|
|
$ |
19,430 |
|
|
$ |
429 |
|
|
$ |
1,122,115 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Intersegment Revenues |
|
$ |
10,662 |
|
|
$ |
40,822 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
51,484 |
|
|
$ |
|
|
|
$ |
(51,484 |
) |
|
$ |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment Profit: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (Loss) from
Continuing
Operations |
|
$ |
56,286 |
|
|
$ |
22,802 |
|
|
$ |
57,163 |
|
|
$ |
7,061 |
|
|
$ |
143,312 |
|
|
$ |
1,910 |
|
|
$ |
(1,123 |
) |
|
$ |
144,099 |
|
Note 9 Investments in Unconsolidated Subsidiaries
At March 31, 2011, the Company owns a 50% interest in ESNE. ESNE is an 80-megawatt, combined
cycle, natural gas-fired turbine power plant in North East, Pennsylvania that is in the process of
being dismantled. The Company expects to recover its investment in ESNE through the sale of ESNEs
major assets, such as the power turbines.
During the quarter ended March 31, 2011, the Company sold its 50% equity method investments in
Seneca Energy and Model City for $59.4 million, resulting in a gain of $50.9 million. Seneca
Energy and Model City generate and sell electricity using methane gas obtained from landfills owned
by outside parties.
-28-
Item 1. Financial Statements (Cont.)
A summary of the Companys investments in unconsolidated subsidiaries at March 31, 2011 and
September 30, 2010 is as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
At March 31, 2011 |
|
|
At September 30, 2010 |
|
Seneca Energy |
|
$ |
|
|
|
$ |
11,007 |
|
Model City |
|
|
|
|
|
|
2,017 |
|
ESNE |
|
|
1,443 |
|
|
|
1,804 |
|
|
|
|
|
|
|
|
|
|
$ |
1,443 |
|
|
$ |
14,828 |
|
|
|
|
|
|
|
|
Note 10 Retirement Plan and Other Post-Retirement Benefits
Components of Net Periodic Benefit Cost (in thousands):
Three months ended March 31,
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Retirement Plan |
|
Other Post-Retirement Benefits |
|
|
2011 |
|
2010 |
|
2011 |
|
2010 |
Service Cost |
|
$ |
3,693 |
|
|
$ |
3,249 |
|
|
$ |
1,069 |
|
|
$ |
1,075 |
|
Interest Cost |
|
|
10,669 |
|
|
|
11,077 |
|
|
|
5,471 |
|
|
|
6,254 |
|
Expected Return on Plan Assets |
|
|
(14,776 |
) |
|
|
(14,585 |
) |
|
|
(7,291 |
) |
|
|
(6,584 |
) |
Amortization of Prior Service Cost |
|
|
147 |
|
|
|
164 |
|
|
|
(427 |
) |
|
|
(427 |
) |
Amortization of Transition Amount |
|
|
|
|
|
|
|
|
|
|
135 |
|
|
|
135 |
|
Amortization of Losses |
|
|
8,718 |
|
|
|
5,410 |
|
|
|
5,948 |
|
|
|
6,470 |
|
Net Amortization and Deferral for |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Regulatory Purposes (Including |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volumetric Adjustments) (1) |
|
|
3,556 |
|
|
|
3,858 |
|
|
|
6,042 |
|
|
|
3,588 |
|
|
|
|
|
|
Net Periodic Benefit Cost |
|
$ |
12,007 |
|
|
$ |
9,173 |
|
|
$ |
10,947 |
|
|
$ |
10,511 |
|
|
|
|
|
|
Six months ended March 31,
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Retirement Plan |
|
Other Post-Retirement Benefits |
|
|
2011 |
|
2010 |
|
2011 |
|
2010 |
Service Cost |
|
$ |
7,386 |
|
|
$ |
6,498 |
|
|
$ |
2,138 |
|
|
$ |
2,149 |
|
Interest Cost |
|
|
21,338 |
|
|
|
22,154 |
|
|
|
10,942 |
|
|
|
12,508 |
|
Expected Return on Plan Assets |
|
|
(29,552 |
) |
|
|
(29,170 |
) |
|
|
(14,582 |
) |
|
|
(13,167 |
) |
Amortization of Prior Service Cost |
|
|
294 |
|
|
|
328 |
|
|
|
(854 |
) |
|
|
(854 |
) |
Amortization of Transition Amount |
|
|
|
|
|
|
|
|
|
|
270 |
|
|
|
270 |
|
Amortization of Losses |
|
|
17,437 |
|
|
|
10,820 |
|
|
|
11,896 |
|
|
|
12,941 |
|
Net Amortization and Deferral for |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Regulatory Purposes (Including |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volumetric Adjustments) (1) |
|
|
1,762 |
|
|
|
3,816 |
|
|
|
7,963 |
|
|
|
3,487 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Periodic Benefit Cost |
|
$ |
18,665 |
|
|
$ |
14,446 |
|
|
$ |
17,773 |
|
|
$ |
17,334 |
|
|
|
|
|
|
|
|
|
(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. |
-29-
Item 1. Financial Statements (Concl.)
Employer Contributions. During the six months ended March 31, 2011, the Company contributed $32.4
million to its tax-qualified, noncontributory defined-benefit retirement plan (Retirement Plan) and
$16.0 million to its VEBA trusts and 401(h) accounts for its other post-retirement benefits. In the
remainder of 2011, the Company expects to contribute at a minimum in the range of $7.0 million to
$15.0 million to the Retirement Plan. Changes in the discount rate, other actuarial assumptions,
and asset performance could ultimately cause the Company to fund larger amounts to the Retirement
Plan in fiscal 2011 in order to be in compliance with the Pension Protection Act of 2006. In the
remainder of 2011, the Company expects to contribute in the range of $9.0 million to $14.0 million
to its VEBA trusts and 401(h) accounts.
Note 11 Subsequent Event
In March 2011, the Company entered into a purchase and sale agreement to sell its off-shore
oil and natural gas properties in the Gulf of Mexico effective as of January 1, 2011 for
approximately $70 million and received a deposit of $7.0 million from the purchaser. The Company
completed the sale in April 2011, receiving an additional $54.8 million. The difference between
the total proceeds received of $61.8 million and the sale price of $70.0 million represents a
purchase price adjustment for the operating cash flow that the Company recorded from January 1, 2011 to the
closing date of the sale. Under the full cost method of accounting for oil and natural gas
properties, the sale proceeds were accounted for as a reduction of capitalized costs in April 2011.
Since the disposition did not significantly alter the relationship between capitalized costs and
proved reserves of oil and gas attributable to the cost center, the Company did not record any gain
or loss from this sale.
-30-
Item 2. Managements Discussion and Analysis of Financial Condition and Results of
Operations
OVERVIEW
[Please note that this overview is 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 March 31, 2011 compared to the quarter ended March 31, 2010, the Company experienced an
increase in earnings of $35.2 million. For the six months ended March 31, 2011 compared to the six
months ended March 31, 2010, the Company experienced an increase in earnings of $29.2 million. The
earnings increase for both the quarter and six-month periods is primarily due to the recognition of
a gain on the sale of unconsolidated subsidiaries of $50.9 million ($31.4 million after tax) during
the current quarter in the All Other category. In February 2011, the Company sold its 50% equity
method investments in Seneca Energy and Model City for $59.4 million. Seneca Energy and Model City
generate and sell electricity using methane gas obtained from landfills owned by outside parties.
The sale is the result of the Companys strategy to pursue the sale of smaller, non-core assets in
order to focus on its core businesses, including the development of the Marcellus Shale and the
expansion of its pipeline business throughout the Appalachian region.
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
controls approximately 745,000 net acres within the Marcellus Shale area of Pennsylvania, with a
majority of the acreage held in fee, carrying no royalty and no lease expirations. The Companys
reserve base has grown substantially from development in the Marcellus Shale. Natural gas proved
developed and undeveloped reserves in the Appalachian region increased from 150 Bcf at September
30, 2009 to 331 Bcf at September 30, 2010. 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 of capital in this region. For the six months ended March 31, 2011, the Company spent
$295.7 million towards the development of the Marcellus Shale. This includes paying $24.1 million
in November 2010 for the acquisition of additional oil and gas properties in the Covington Township
area of Tioga County, Pennsylvania from EOG Resources, Inc. These properties are producing natural
gas from the Marcellus Shale and are also prospective for additional Marcellus reserves. As a
result of the transaction, it is anticipated that the Appalachian region of the Exploration and
Production segment will add approximately 42 Bcf of proved natural gas reserves, thereby having an
immediate positive impact on the Companys production and proved reserves.
As the Company has been accelerating its Marcellus Shale development, it has been decreasing
its emphasis in the Gulf Coast region. In March 2011, the Company entered into a purchase and sale
agreement to sell its off-shore oil and natural gas properties effective as of January 1, 2011 in
the Gulf of Mexico for approximately $70 million and received a deposit of $7.0 million from the
purchaser. The Company completed the sale in April 2011, receiving an additional $54.8 million.
The difference between the total proceeds received of $61.8 million and the sale price of $70.0
million represents a purchase price adjustment for the operating cash
flow that the Company recorded from
January 1, 2011 to the closing date of the sale. Under the full cost method of accounting for oil
and natural gas properties, the sale proceeds were accounted for as a reduction of capitalized
costs in April 2011. Since the disposition did not significantly alter the relationship between
capitalized costs and proved reserves of oil and gas attributable to the cost center, the Company
did not record any gain or loss from this sale.
The Company has engaged Jefferies & Company to explore joint-venture opportunities across its
Marcellus Shale acreage in its Exploration and Production segment. It is the Companys goal to
accelerate Marcellus Shale development faster than its current plans. By entering into a
joint-venture agreement, the Company expects to enhance shareholder value by shifting a significant
portion of the early drilling costs to a noncontrolling-interest partner while still allowing the
Company to continue operating across most of its acreage. The Companys position in the Marcellus
Shale provides a competitive advantage for a potential joint-venture partner as a majority of the
acreage is held in fee, carrying no royalty and no lease expirations,
-31-
Item 2. Managements Discussion and Analysis of Financial Condition and Results of Operations
(Cont.)
and large, contiguous acreage blocks allow for operating- and cost-efficiency through multi-well
pad drilling. The Company will forgo any joint-venture opportunities that do not enhance
shareholder value when compared to its current growth plans.
Coincident with the development of its Marcellus Shale acreage, the Companys Pipeline and
Storage segment 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 the
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. This factor has been causing shippers to seek alternative gas
supplies and consequently alternative transportation routes. 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, will involve significant capital
expenditures.
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 and short-term
borrowings. The Company had $144.8 million in Cash and Temporary Cash Investments at March 31,
2011, as shown on the Companys Consolidated Balance Sheet. For the remainder of fiscal 2011, the
Company expects that it will be able to use cash on hand, cash from operations, and cash from asset
sales as its first means of financing capital expenditures, with short-term borrowings and
long-term borrowings being its next sources of funding. It is not expected that long-term financing
will be required to meet capital expenditure needs until the later part of fiscal 2011 or in fiscal
2012.
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
negative 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 in place that prevents 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, 2010 as well as updates to that section in the Form 10-Q
for the quarter ended December 31, 2010 for further discussion.
CRITICAL ACCOUNTING ESTIMATES
For a complete discussion of critical accounting estimates, refer to Critical Accounting
Estimates in Item 7 of the Companys 2010 Form 10-K and Item 2 of the Companys December 31, 2010
Form 10-Q. There have been no material changes to those disclosures other than as set forth below.
The information presented below updates and should be read in conjunction with the critical
accounting estimates in those documents.
-32-
Item 2. Managements Discussion and Analysis of Financial Condition and Results of Operations
(Cont.)
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 an unweighted arithmetic average of the first day of the
month oil and gas prices for each month within the twelve-month period prior to the end of the
reporting period (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 March 31, 2011, the ceiling exceeded the book value of
the oil and gas properties by approximately $230 million. The 12-month average of the first day of
the month price for crude oil for each month during the twelve months ended March 31, 2011, based
on posted Midway-Sunset prices was $77.73 per Bbl. The 12-month average of the first day of the
month price for natural gas for each month during the twelve months ended March 31, 2011, based on
the quoted Henry Hub spot price for natural gas, was $4.10 per MMBtu. (Note Because actual
pricing of the Companys various producing properties varies depending on their location and
hedging, the actual various prices received for such production is utilized to calculate the
ceiling, rather than the Midway-Sunset and Henry Hub prices, which are only indicative of 12-month
average prices for the twelve months ended March 31, 2011.) If natural gas average prices used in
the ceiling test calculation at March 31, 2011 had been $1 per MMBtu lower, the ceiling would have
exceeded the book value of the Companys oil and gas properties by approximately $77 million. If
crude oil average prices used in the ceiling test calculation at March 31, 2011 had been $5 per Bbl
lower, the ceiling would have exceeded the book value of the Companys oil and gas properties by
approximately $184 million. If both natural gas and crude oil average prices used in the ceiling
test calculation at March 31, 2011 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
$31 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 2010 Form 10-K.
RESULTS OF OPERATIONS
Earnings
The Companys earnings were $115.6 million for the quarter ended March 31, 2011 compared to
earnings of $80.4 million for the quarter ended March 31, 2010. As previously discussed, the
Company sold its landfill gas operations in the states of Ohio, Michigan, Kentucky, Missouri,
Maryland and Indiana in September 2010. Accordingly, all financial results for these operations,
which are part of the All Other category, have been presented as discontinued operations. The
Companys earnings from continuing operations were $115.6 million for the quarter ended March 31,
2011 compared with $79.9 million for the quarter ended March 31, 2010. The increase in earnings
from continuing operations of $35.7 million is primarily a result of higher earnings in the All
Other category and the Exploration and Production segment. Lower earnings in the Pipeline and
Storage segment slightly offset these increases. The Companys earnings for the quarter ended
March 31, 2011 include a $50.9 million ($31.4 million after tax) gain on the sale of
unconsolidated subsidiaries as a result of the Companys sale of its 50% equity method investments
in Seneca Energy and Model City, as discussed above.
The Companys earnings were $174.2 million for the six months ended March 31, 2011 compared to
earnings of $144.9 million for the six months ended March 31, 2010. The Companys earnings from
continuing operations were $174.2 million for the six months ended March 31, 2011 compared with
$144.1 million for the six months ended March 31, 2010. The increase in earnings from continuing
operations of $30.1 million is primarily the result of higher earnings in the All Other category
and the Exploration and Production segment. Lower earnings in the Pipeline and Storage segment
slightly offset these increases. The Companys earnings for the six months ended March 31, 2011
include a $50.9 million ($31.4 million after tax) gain on the sale of unconsolidated subsidiaries,
as discussed above.
-33-
Item 2. Managements Discussion and Analysis of Financial Condition and Results of Operations
(Cont.)
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 |
|
Six Months Ended |
|
|
March 31, |
|
March 31, |
|
|
|
|
|
|
|
|
|
|
Increase |
|
|
|
|
|
|
|
|
|
Increase |
(Thousands) |
|
2011 |
|
2010 |
|
(Decrease) |
|
2011 |
|
2010 |
|
(Decrease) |
Utility |
|
$ |
33,081 |
|
|
$ |
33,273 |
|
|
$ |
(192 |
) |
|
$ |
56,071 |
|
|
$ |
56,286 |
|
|
$ |
(215 |
) |
Pipeline and Storage |
|
|
10,955 |
|
|
|
12,448 |
|
|
|
(1,493 |
) |
|
|
19,533 |
|
|
|
22,802 |
|
|
|
(3,269 |
) |
Exploration and Production |
|
|
33,299 |
|
|
|
27,383 |
|
|
|
5,916 |
|
|
|
60,672 |
|
|
|
57,163 |
|
|
|
3,509 |
|
Energy Marketing |
|
|
6,299 |
|
|
|
5,969 |
|
|
|
330 |
|
|
|
7,231 |
|
|
|
7,061 |
|
|
|
170 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Reportable Segments |
|
|
83,634 |
|
|
|
79,073 |
|
|
|
4,561 |
|
|
|
143,507 |
|
|
|
143,312 |
|
|
|
195 |
|
All Other |
|
|
32,181 |
|
|
|
1,020 |
|
|
|
31,161 |
|
|
|
31,606 |
|
|
|
1,910 |
|
|
|
29,696 |
|
Corporate |
|
|
(204 |
) |
|
|
(219 |
) |
|
|
15 |
|
|
|
(959 |
) |
|
|
(1,123 |
) |
|
|
164 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Earnings from
Continuing Operations |
|
|
115,611 |
|
|
|
79,874 |
|
|
|
35,737 |
|
|
|
174,154 |
|
|
|
144,099 |
|
|
|
30,055 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings from Discontinued
Operations |
|
|
|
|
|
|
554 |
|
|
|
(554 |
) |
|
|
|
|
|
|
828 |
|
|
|
(828 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Consolidated |
|
$ |
115,611 |
|
|
$ |
80,428 |
|
|
$ |
35,183 |
|
|
$ |
174,154 |
|
|
$ |
144,927 |
|
|
$ |
29,227 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Utility
Utility Operating Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
Six Months Ended |
|
|
March 31, |
|
March 31, |
|
|
|
|
|
|
|
|
|
|
Increase |
|
|
|
|
|
|
|
|
|
Increase |
(Thousands) |
|
2011 |
|
2010 |
|
(Decrease) |
|
2011 |
|
2010 |
|
(Decrease) |
Retail Sales Revenues: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Residential |
|
$ |
263,596 |
|
|
$ |
256,447 |
|
|
$ |
7,149 |
|
|
$ |
440,785 |
|
|
$ |
433,043 |
|
|
$ |
7,742 |
|
Commercial |
|
|
38,813 |
|
|
|
38,311 |
|
|
|
502 |
|
|
|
61,359 |
|
|
|
62,717 |
|
|
|
(1,358 |
) |
Industrial |
|
|
2,900 |
|
|
|
2,594 |
|
|
|
306 |
|
|
|
4,144 |
|
|
|
3,883 |
|
|
|
261 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
305,309 |
|
|
|
297,352 |
|
|
|
7,957 |
|
|
|
506,288 |
|
|
|
499,643 |
|
|
|
6,645 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Transportation |
|
|
44,951 |
|
|
|
40,509 |
|
|
|
4,442 |
|
|
|
80,363 |
|
|
|
71,203 |
|
|
|
9,160 |
|
Off-System Sales |
|
|
16,699 |
|
|
|
13,314 |
|
|
|
3,385 |
|
|
|
25,589 |
|
|
|
15,005 |
|
|
|
10,584 |
|
Other |
|
|
1,421 |
|
|
|
3,567 |
|
|
|
(2,146 |
) |
|
|
3,552 |
|
|
|
5,808 |
|
|
|
(2,256 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
368,380 |
|
|
$ |
354,742 |
|
|
$ |
13,638 |
|
|
$ |
615,792 |
|
|
$ |
591,659 |
|
|
$ |
24,133 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Utility Throughput
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
Six Months Ended |
|
|
March 31, |
|
March 31, |
(MMcf) |
|
2011 |
|
2010 |
|
Increase |
|
2011 |
|
2010 |
|
Increase |
Retail Sales: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Residential |
|
|
28,048 |
|
|
|
26,413 |
|
|
|
1,635 |
|
|
|
45,207 |
|
|
|
43,237 |
|
|
|
1,970 |
|
Commercial |
|
|
4,372 |
|
|
|
4,256 |
|
|
|
116 |
|
|
|
6,842 |
|
|
|
6,746 |
|
|
|
96 |
|
Industrial |
|
|
393 |
|
|
|
288 |
|
|
|
105 |
|
|
|
539 |
|
|
|
446 |
|
|
|
93 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
32,813 |
|
|
|
30,957 |
|
|
|
1,856 |
|
|
|
52,588 |
|
|
|
50,429 |
|
|
|
2,159 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Transportation |
|
|
27,472 |
|
|
|
24,366 |
|
|
|
3,106 |
|
|
|
45,581 |
|
|
|
41,427 |
|
|
|
4,154 |
|
Off-System Sales |
|
|
3,458 |
|
|
|
2,554 |
|
|
|
904 |
|
|
|
5,321 |
|
|
|
2,910 |
|
|
|
2,411 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
63,743 |
|
|
|
57,877 |
|
|
|
5,866 |
|
|
|
103,490 |
|
|
|
94,766 |
|
|
|
8,724 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
-34-
Item 2. Managements Discussion and Analysis of Financial Condition and Results of Operations
(Cont.)
Degree Days
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Percent |
Three Months Ended |
|
|
|
|
|
|
|
|
|
|
|
|
|
Colder (Warmer) Than |
March 31 |
|
Normal |
|
2011 |
|
2010 |
|
Norm
al(1) |
|
Prior Year(1) |
Buffalo |
|
|
3,327 |
|
|
|
3,494 |
|
|
|
3,241 |
|
|
|
5.0 |
|
|
|
7.8 |
|
Erie |
|
|
3,142 |
|
|
|
3,312 |
|
|
|
3,163 |
|
|
|
5.4 |
|
|
|
4.7 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended
March 31 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Buffalo |
|
|
5,587 |
|
|
|
5,826 |
|
|
|
5,487 |
|
|
|
4.3 |
|
|
|
6.2 |
|
Erie |
|
|
5,223 |
|
|
|
5,472 |
|
|
|
5,211 |
|
|
|
4.8 |
|
|
|
5.0 |
|
|
|
|
(1) |
|
Percents compare actual 2011 degree days to normal degree days and actual 2011
degree days to actual 2010 degree days. |
2011 Compared with 2010
Operating revenues for the Utility segment increased $13.6 million for the quarter ended March
31, 2011 as compared with the quarter ended March 31, 2010. This increase largely resulted from an
$8.0 million increase in retail gas sales revenues, a $4.4 million increase in transportation
revenues and a $3.4 million increase in off-system sales revenues. These increases were partially
offset by a $2.1 million decrease in other operating revenues. The increase in retail gas sales
revenues of $8.0 million was largely a function of higher volumes (1.9 Bcf) due to colder weather
and higher customer usage per account. The phrase usage per account refers to the average gas
consumption per customer account after factoring out any impact that weather may have had on
consumption. The increase in volumes resulted in the recovery of a larger amount of gas costs,
despite a decline in the Utility segments average cost of purchased gas. The Utility segments
average cost of purchased gas, including the cost of transportation and storage, was $6.31 per Mcf
for the three months ended March 31, 2011, a decrease of 17.1% from the average cost of $7.61 per
Mcf for the three months ended March 31, 2010. Subject to certain timing variations, gas costs are
recovered dollar for dollar in revenues. The increase in transportation revenues of $4.4 million
was primarily due to a 3.1 Bcf increase in transportation throughput, largely the result of colder
weather and the migration of customers from retail sales to transportation service. The increase
in off-system sales revenues was largely due to an increase in off-system sales volume. Due to
profit sharing with retail customers, the margins resulting from off-system sales are minimal and
there was not a material impact to margins. The $2.1 million decrease in other operating revenues
was largely attributable to a regulatory adjustment to reduce a previous undercollection of pension
and other post-retirement benefit costs.
Operating revenues for the Utility segment increased $24.1 million for the six months ended
March 31, 2011 as compared with the six months ended March 31, 2010. This increase largely
resulted from a $6.6 million increase in retail gas sales revenues, a $9.2 million increase in
transportation revenues and a $10.6 million increase in off-system sales revenues. These increases
were partially offset by a $2.3 million decrease in other operating revenues. The increase in
retail gas sales revenues of $6.6 million was largely a function of higher volumes (2.2 Bcf) due to
colder weather and higher customer usage per account. The increase in volumes resulted in the
recovery of a larger amount of gas costs, despite a decline in the Utility segments average cost
of purchased gas. The Utility segments average cost of purchased gas, including the cost of
transportation and storage, was $6.19 per Mcf for the six months ended March 31, 2011, a decrease
of 15.9% from the average cost of $7.36 per Mcf for the six months ended March 31, 2010. Subject
to certain timing variations, gas costs are recovered dollar for dollar in revenues. The increase
in transportation revenues of $9.2 million was primarily due to a 4.2 Bcf increase in
transportation throughput, largely the result of colder weather and the migration of customers from
retail sales to transportation service. The increase in off-system sales revenues was largely due
to an increase in off-system sales volume. Due to profit sharing with retail customers, the
margins resulting from off-system sales are minimal and there was not a material impact to margins.
The $2.3 million decrease in other operating revenues was largely attributable to a regulatory
adjustment to reduce a previous undercollection of pension and other post-retirement benefit costs.
The Utility segments earnings for the quarter ended March 31, 2011 were $33.1
million, a decrease of $0.2 million when compared with earnings of $33.3 million for the quarter
ended March 31, 2010.
-35-
Item 2. Managements Discussion and Analysis of Financial Condition and Results of Operations
(Cont.)
In the New York jurisdiction, earnings decreased $1.3 million. The decrease in earnings was
mainly due to the decrease in other operating revenues ($1.4 million), which was largely
attributable to a regulatory adjustment to reduce a previous undercollection of pension and other
post-retirement benefit costs.
In the Pennsylvania jurisdiction, earnings increased $1.1 million. The earnings
increase was largely attributable to higher usage per account ($1.0 million) and colder weather
($0.5 million).
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. In addition, in periods of colder than normal weather, the WNC
benefits the Utility segments New York customers. For the quarter ended March 31, 2011, the WNC
reduced earnings by $0.7 million, as it was colder than normal. The WNC did not have a significant
earnings impact during the quarter ended March 31, 2010.
The Utility segments earnings for the six months ended March 31, 2011 were $56.1 million, a
decrease of $0.2 million when compared with earnings of $56.3 million for the six months ended
March 31, 2010.
In the New York jurisdiction, earnings decreased $2.5 million. The decrease in earnings was
mainly due to the decrease in other operating revenues ($1.4 million), which was largely
attributable to a regulatory adjustment to reduce a previous undercollection of pension and other
post-retirement benefit costs. In addition, the negative earnings impact associated with an
increase in other taxes ($0.5 million), higher depreciation expense ($0.3 million), higher interest
expense ($0.3 million) and higher income tax expense ($0.2 million) further reduced earnings.
In the Pennsylvania jurisdiction, earnings increased $2.3 million. The earnings increase was
largely attributable to higher usage per account ($1.5 million) and colder weather ($1.0 million).
In addition, the positive earnings impact associated with lower interest expense on deferred gas
costs ($0.6 million) further increased earnings. These increases were partially offset by the
negative earnings impact associated with higher income tax expense of $0.4 million and higher
operating expenses of $0.4 million. Operating expenses increased primarily because of higher
pension costs.
For the six months ended March 31, 2011, the WNC reduced earnings by $0.8 million, as it was
colder than normal. The WNC did not have a significant earnings impact during the quarter ended
March 31, 2010.
Pipeline and Storage
Pipeline and Storage Operating Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
Six Months Ended |
|
|
March 31, |
|
March 31, |
|
|
|
|
|
|
|
|
|
|
Increase |
|
|
|
|
|
|
|
|
|
Increase |
(Thousands) |
|
2011 |
|
2010 |
|
(Decrease) |
|
2011 |
|
2010 |
|
(Decrease) |
Firm Transportation |
|
$ |
37,290 |
|
|
$ |
38,294 |
|
|
$ |
(1,004 |
) |
|
$ |
72,240 |
|
|
$ |
74,722 |
|
|
$ |
(2,482 |
) |
Interruptible Transportation |
|
|
415 |
|
|
|
535 |
|
|
|
(120 |
) |
|
|
730 |
|
|
|
840 |
|
|
|
(110 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
37,705 |
|
|
|
38,829 |
|
|
|
(1,124 |
) |
|
|
72,970 |
|
|
|
75,562 |
|
|
|
(2,592 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Firm Storage Service |
|
|
16,859 |
|
|
|
16,763 |
|
|
|
96 |
|
|
|
33,461 |
|
|
|
33,386 |
|
|
|
75 |
|
Interruptible Storage Service |
|
|
2 |
|
|
|
2 |
|
|
|
|
|
|
|
19 |
|
|
|
59 |
|
|
|
(40 |
) |
Other |
|
|
5,735 |
|
|
|
5,942 |
|
|
|
(207 |
) |
|
|
7,246 |
|
|
|
7,290 |
|
|
|
(44 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
60,301 |
|
|
$ |
61,536 |
|
|
$ |
(1,235 |
) |
|
$ |
113,696 |
|
|
$ |
116,297 |
|
|
$ |
(2,601 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
-36-
Item 2. Managements Discussion and Analysis of Financial Condition and Results of Operations
(Cont.)
Pipeline and Storage Throughput
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
Six Months Ended |
|
|
March 31, |
|
March 31, |
|
|
|
|
|
|
|
|
|
|
Increase |
|
|
|
|
|
|
|
|
|
Increase |
(MMcf) |
|
2011 |
|
2010 |
|
(Decrease) |
|
2011 |
|
2010 |
|
(Decrease) |
Firm Transportation |
|
|
123,969 |
|
|
|
112,146 |
|
|
|
11,823 |
|
|
|
213,218 |
|
|
|
192,785 |
|
|
|
20,433 |
|
Interruptible Transportation |
|
|
1,095 |
|
|
|
1,804 |
|
|
|
(709 |
) |
|
|
1,220 |
|
|
|
2,559 |
|
|
|
(1,339 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
125,064 |
|
|
|
113,950 |
|
|
|
11,114 |
|
|
|
214,438 |
|
|
|
195,344 |
|
|
|
19,094 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2011 Compared with 2010
Operating revenues for the Pipeline and Storage segment decreased $1.2 million in the quarter
ended March 31, 2011 as compared with the quarter ended March 31, 2010. The decrease was primarily
due to a decrease in transportation revenues of $1.1 million. This decrease was primarily the
result of a reduction in the level of short-term contracts entered into by shippers quarter over
quarter as shippers utilized lower priced pipeline transportation routes and a decrease in the
gathering rate under Supply Corporations tariff. Shippers are seeking alternative lower priced
gas supply (and in some cases, not renewing short-term transportation contracts) because of the
relatively higher price of natural gas supplies available at the United States/Canadian border at
the Niagara River near Buffalo, New York compared to the lower pricing for supplies available at
Leidy, Pennsylvania. 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.
Operating revenues for the Pipeline and Storage segment for the six months ended March 31,
2011 decreased $2.6 million as compared with the six months ended March 31, 2010. The decrease was
primarily due to a decrease in transportation revenues of $2.6 million, which was primarily the
result of a reduction in the level of short-term contracts entered into by shippers period over
period as shippers utilized lower priced pipeline transportation routes, as discussed above.
Volume fluctuations generally do not have a significant impact on revenues as a result of the
straight fixed-variable rate design utilized by Supply Corporation and Empire, but this rate design
does not protect Supply Corporation or Empire in situations where 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. Transportation volume for the quarter ended
March 31, 2011 increased by 11.1 Bcf from the prior years quarter. For the six months ended March
31, 2011, transportation volumes increased by 19.1 Bcf from the prior years six-month period.
While transportation volume increased largely due to colder weather, there was little impact on
revenues due to the straight fixed-variable rate design.
The Pipeline and Storage segments earnings for the quarter ended March 31, 2011 were $11.0
million, a decrease of $1.4 million when compared with earnings of $12.4 million for the quarter
ended March 31, 2010. The earnings decrease was primarily due to the earnings impact of lower
transportation revenues of $0.7 million, as discussed above, combined with higher operating
expenses ($0.9 million). The increase in operating expenses can primarily be attributed to higher
pension expense and higher personnel costs. Higher property taxes ($0.3 million) and higher
depreciation expense ($0.2 million) also contributed to the decrease in earnings. The increase in
property taxes is primarily a result of additional property and higher Pennsylvania public utility
realty taxes. The increase in depreciation expense is primarily the result of Supply Corporations
Lamont Project being placed in service on June 15, 2010 as well as additional projects that were
placed in service in the last year. These earnings decreases were slightly offset by an increase
in the allowance for funds used during construction (equity component) of $0.3 million primarily
due to construction commencing during the current quarter on Supply Corporations Line N Expansion
Project and Lamont Phase II Project, projects designed to move anticipated Marcellus production gas
to other interstate pipelines and to markets beyond the Supply Corporation system, as discussed in
the Investing Cash Flow section that follows.
-37-
Item 2. Managements Discussion and Analysis of Financial Condition and Results of Operations
(Cont.)
The Pipeline and Storage segments earnings for the six months ended March 31, 2011 were $19.5
million, a decrease of $3.3 million when compared with earnings of $22.8 million for the six months
ended March 31, 2010. The decrease in earnings is primarily due to the earnings impact of lower
transportation revenues of $1.7 million, as discussed above, combined with higher operating
expenses ($1.8 million), higher property taxes ($0.3 million), and higher depreciation expense
($0.3 million). The increase in operating expenses can primarily be attributed to higher pension
expense and higher personnel costs. The increase in property taxes is primarily a result of
additional property and higher Pennsylvania public utility realty taxes. The increase in
depreciation expense is primarily the result of Supply Corporations Lamont Project being placed in
service on June 15, 2010 as well as additional projects that were placed in service in the last
year. These earnings decreases were partially offset by an increase in the allowance for funds
used during construction (equity component) of $0.5 million primarily due to construction
commencing during the current quarter on Supply Corporations Line N Expansion Project and Lamont
Phase II Project, as discussed above, and lower income tax expense ($0.4 million) due to a lower
effective tax rate.
Exploration and Production
Exploration and Production Operating Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
Six Months Ended |
|
|
March 31, |
|
March 31, |
|
|
|
|
|
|
|
|
|
|
Increase |
|
|
|
|
|
|
|
|
|
Increase |
(Thousands) |
|
2011 |
|
2010 |
|
(Decrease) |
|
2011 |
|
2010 |
|
(Decrease) |
Gas (after Hedging) |
|
$ |
73,256 |
|
|
$ |
46,512 |
|
|
$ |
26,744 |
|
|
$ |
131,265 |
|
|
$ |
87,380 |
|
|
$ |
43,885 |
|
Oil (after Hedging) |
|
|
61,337 |
|
|
|
60,215 |
|
|
|
1,122 |
|
|
|
120,030 |
|
|
|
122,910 |
|
|
|
(2,880 |
) |
Gas Processing Plant |
|
|
6,659 |
|
|
|
7,663 |
|
|
|
(1,004 |
) |
|
|
13,342 |
|
|
|
14,871 |
|
|
|
(1,529 |
) |
Other |
|
|
44 |
|
|
|
116 |
|
|
|
(72 |
) |
|
|
(71 |
) |
|
|
162 |
|
|
|
(233 |
) |
Intrasegment Elimination (1) |
|
|
(3,866 |
) |
|
|
(5,348 |
) |
|
|
1,482 |
|
|
|
(6,968 |
) |
|
|
(9,812 |
) |
|
|
2,844 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
137,430 |
|
|
$ |
109,158 |
|
|
$ |
28,272 |
|
|
$ |
257,598 |
|
|
$ |
215,511 |
|
|
$ |
42,087 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Represents the elimination of certain West Coast gas production revenue
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. |
Production Volumes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
Six Months Ended |
|
|
March 31, |
|
March 31, |
|
|
|
|
|
|
|
|
|
|
Increase |
|
|
|
|
|
|
|
|
|
Increase |
|
|
2011 |
|
2010 |
|
(Decrease) |
|
2011 |
|
2010 |
|
(Decrease) |
|
Gas Production (MMcf) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gulf Coast |
|
|
2,056 |
|
|
|
2,643 |
|
|
|
(587 |
) |
|
|
4,070 |
|
|
|
5,333 |
|
|
|
(1,263 |
) |
West Coast |
|
|
855 |
|
|
|
930 |
|
|
|
(75 |
) |
|
|
1,790 |
|
|
|
1,926 |
|
|
|
(136 |
) |
Appalachia |
|
|
10,848 |
|
|
|
3,542 |
|
|
|
7,306 |
|
|
|
18,930 |
|
|
|
6,344 |
|
|
|
12,586 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Production |
|
|
13,759 |
|
|
|
7,115 |
|
|
|
6,644 |
|
|
|
24,790 |
|
|
|
13,603 |
|
|
|
11,187 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil Production (Mbbl) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gulf Coast |
|
|
92 |
|
|
|
109 |
|
|
|
(17 |
) |
|
|
197 |
|
|
|
255 |
|
|
|
(58 |
) |
West Coast |
|
|
643 |
|
|
|
661 |
|
|
|
(18 |
) |
|
|
1,297 |
|
|
|
1,345 |
|
|
|
(48 |
) |
Appalachia |
|
|
11 |
|
|
|
9 |
|
|
|
2 |
|
|
|
21 |
|
|
|
20 |
|
|
|
1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Production |
|
|
746 |
|
|
|
779 |
|
|
|
(33 |
) |
|
|
1,515 |
|
|
|
1,620 |
|
|
|
(105 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
-38-
Item 2. Managements Discussion and Analysis of Financial Condition and Results of Operations
(Cont.)
Average Prices
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
Six Months Ended |
|
|
March 31, |
|
March 31, |
|
|
|
|
|
|
|
|
|
|
Increase |
|
|
|
|
|
|
|
|
|
Increase |
|
|
2011 |
|
2010 |
|
(Decrease) |
|
2011 |
|
2010 |
|
(Decrease) |
Average Gas Price/Mcf |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gulf Coast |
|
$ |
4.87 |
|
|
$ |
6.02 |
|
|
$ |
(1.15 |
) |
|
$ |
4.71 |
|
|
$ |
5.42 |
|
|
$ |
(0.71 |
) |
West Coast |
|
$ |
4.46 |
|
|
$ |
5.79 |
|
|
$ |
(1.33 |
) |
|
$ |
4.18 |
|
|
$ |
5.19 |
|
|
$ |
(1.01 |
) |
Appalachia |
|
$ |
4.40 |
|
|
$ |
5.97 |
|
|
$ |
(1.57 |
) |
|
$ |
4.24 |
|
|
$ |
5.57 |
|
|
$ |
(1.33 |
) |
Weighted Average |
|
$ |
4.48 |
|
|
$ |
5.96 |
|
|
$ |
(1.48 |
) |
|
$ |
4.31 |
|
|
$ |
5.46 |
|
|
$ |
(1.15 |
) |
Weighted Average After Hedging |
|
$ |
5.32 |
|
|
$ |
6.54 |
|
|
$ |
(1.22 |
) |
|
$ |
5.30 |
|
|
$ |
6.42 |
|
|
$ |
(1.12 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Oil Price/bbl |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gulf Coast |
|
$ |
96.12 |
|
|
$ |
89.22 |
|
|
$ |
6.90 |
|
|
$ |
89.61 |
|
|
$ |
79.81 |
|
|
$ |
9.80 |
|
West Coast |
|
$ |
95.35 |
|
|
$ |
73.16 |
|
|
$ |
22.19 |
|
|
$ |
87.84 |
|
|
$ |
71.72 |
|
|
$ |
16.12 |
|
Appalachia |
|
$ |
86.53 |
|
|
$ |
73.80 |
|
|
$ |
12.73 |
|
|
$ |
84.07 |
|
|
$ |
79.67 |
|
|
$ |
4.40 |
|
Weighted Average |
|
$ |
95.31 |
|
|
$ |
75.41 |
|
|
$ |
19.90 |
|
|
$ |
88.01 |
|
|
$ |
73.09 |
|
|
$ |
14.92 |
|
Weighted Average After Hedging |
|
$ |
82.28 |
|
|
$ |
77.29 |
|
|
$ |
4.99 |
|
|
$ |
79.21 |
|
|
$ |
75.86 |
|
|
$ |
3.35 |
|
2011 Compared with 2010
Operating revenues for the Exploration and Production segment increased $28.3 million for the
quarter ended March 31, 2011 as compared with the quarter ended March 31, 2010. Gas production
revenue after hedging increased $26.7 million. Increases in Appalachian natural gas production were
partially offset by a $1.22 per Mcf decrease in the weighted average price of gas after hedging.
The increase in Appalachian production was primarily due to additional wells within the Marcellus
Shale formation, primarily in Tioga County, Pennsylvania, coming on line late in fiscal 2010 and
the first six months of fiscal 2011. Oil production revenue after hedging increased $1.1 million.
An increase in the weighted average price of oil after hedging ($4.99 per Bbl) was the primary
cause, as oil production levels were slightly lower quarter over
quarter. The decrease in oil production is a result of the Company
switching its emphasis from the Gulf Coast region to the Appalachian
region combined with natural declines in the West Coast region. The
Company intends to spend modest amounts of capital to maintain West
Coast production at current levels in the future. In addition, there was a
$0.5 million increase in processing plant revenues (net of eliminations) primarily because of the
lower cost of West Coast gas production quarter over quarter.
Operating revenues for the Exploration and Production segment increased $42.1 million for the
six months ended March 31, 2011 as compared with the six months ended March 31, 2010. Gas
production revenue after hedging increased $43.9 million. Increases in Appalachian natural gas
production were partially offset by a $1.12 per Mcf decrease in the weighted average price of gas
after hedging. The increase in Appalachian production was primarily due to additional wells within
the Marcellus Shale formation, primarily in Tioga County, Pennsylvania, coming on line late in
fiscal 2010 and the first six months of fiscal 2011. Oil production revenue after hedging
decreased $2.9 million due to lower crude oil production levels, which were partially offset by an
increase in the weighted average price of oil after hedging ($3.35
per Bbl). The decrease in oil production is a result of the Company
switching its emphasis from the Gulf Coast region to the Appalachian
region combined with natural declines in the West Coast region. The
Company intends to spend modest amounts of capital to maintain West
Coast production at current levels in the future. In addition, there
was a $1.3 million increase in processing plant revenues (net of eliminations) primarily because of
the lower cost of West Coast gas production for the six months ended March 31, 2011 as compared to
the six months ended March 31, 2010.
The Exploration and Production segments earnings for the quarter ended March 31, 2011 were
$33.3 million, an increase of $5.9 million when compared with earnings of $27.4 million for the
quarter ended March 31, 2010. Higher crude oil prices and higher natural gas production increased
earnings by $2.4 million and $28.2 million, respectively. In addition, higher processing plant
revenues ($0.3 million) and lower interest expense ($2.5 million) also contributed to an increase
in earnings. The decrease in interest expense is primarily due to a lower average amount of debt
outstanding and the capitalization of interest during the quarter ended March 31, 2011. These
earnings increases were partially offset by lower natural gas prices after hedging and lower crude
oil production, which decreased earnings by $10.8 million and $1.7 million, respectively. In
addition, earnings were further reduced by higher depletion expense ($9.2 million), higher lease
operating expenses ($2.1 million), higher general, administrative and other operating expenses
($2.4 million), and higher property taxes ($1.3 million). The increase in depletion expense is
primarily due to an increase in production and depletable base (largely due to increased capital
spending in the Appalachian region, specifically related to the development of Marcellus
Shale properties). The increase in lease
-39-
|
|
|
Item 2. |
|
Managements Discussion and Analysis of Financial Condition and Results of
Operations (Cont.) |
operating expenses is largely attributable to a higher number of producing properties in
Appalachia. Higher personnel costs are largely responsible for the increase in general,
administrative and other operating expenses. Higher property taxes are attributable to a revision
of the California property tax liability.
The Exploration and Production segments earnings for the six months ended March 31,
2011 were $60.7 million, an increase of $3.5 million when compared with earnings of $57.2 million
for the quarter ended March 31, 2010. Higher crude oil prices and higher natural gas production
increased earnings by $3.3 million and $46.7 million, respectively. In addition, higher processing
plant revenues ($0.9 million) and lower interest expense ($3.6 million) also contributed to an
increase in earnings. The decrease in interest expense is primarily due to a lower average amount
of debt outstanding and the capitalization of interest during the six months ended March 31, 2011.
These earnings increases were partially offset by lower natural gas prices after hedging and lower
crude oil production, which decreased earnings by $18.2 million and $5.2 million, respectively. In
addition, earnings were further reduced by higher depletion expense ($15.5 million), higher lease
operating expenses ($5.5 million), higher general, administrative and other operating expenses
($4.1 million), higher property taxes ($1.6 million), and higher income tax expense ($0.7 million).
The increase in depletion expense is primarily due to an increase in production and depletable
base (largely due to increased capital spending in the Appalachian region, specifically related to
the development of Marcellus Shale properties). The increase in lease operating expenses is
largely attributable to a higher number of producing properties in Appalachia. Higher personnel
costs are largely responsible for the increase in general, administrative and other operating
expenses. Higher property taxes are attributable to a revision of the California property tax
liability. The increase in income taxes is attributable to the loss of a domestic production
activities deduction that occurred during the quarter ended September 30, 2010 and its impact on
the effective tax rate during fiscal 2011 coupled with higher state income taxes.
Energy Marketing
Energy Marketing Operating Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
Six Months Ended |
|
|
March 31, |
|
March 31, |
(Thousands) |
|
2011 |
|
2010 |
|
Decrease |
|
2011 |
|
2010 |
|
Decrease |
Natural Gas (after Hedging) |
|
$ |
121,294 |
|
|
$ |
158,459 |
|
|
$ |
(37,165 |
) |
|
$ |
174,933 |
|
|
$ |
230,172 |
|
|
$ |
(55,239 |
) |
Other |
|
|
27 |
|
|
|
78 |
|
|
|
(51 |
) |
|
|
40 |
|
|
|
101 |
|
|
|
(61 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
121,321 |
|
|
$ |
158,537 |
|
|
$ |
(37,216 |
) |
|
$ |
174,973 |
|
|
$ |
230,273 |
|
|
$ |
(55,300 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy Marketing Volume
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
Six Months Ended |
|
|
March 31, |
|
March 31, |
|
|
2011 |
|
2010 |
|
Decrease |
|
2011 |
|
2010 |
|
Decrease |
Natural Gas (MMcf) |
|
|
21,609 |
|
|
|
23,996 |
|
|
|
(2,387 |
) |
|
|
32,355 |
|
|
|
38,097 |
|
|
|
(5,742 |
) |
2011 Compared with 2010
Operating revenues for the Energy Marketing segment decreased $37.2 million and
$55.3 million for the quarter and six months ended March 31, 2011, as compared with the quarter and
six months ended March 31, 2010. The decrease for both the quarter and six months ended March 31,
2011 primarily reflects a decline in gas sales revenue due largely to a decrease in volume sold as
well as a lower average price of natural gas that was recovered through revenues. The decrease in
volume is largely attributable to a decrease in volume sold to low-margin wholesale customers as
well as the non-recurrence of 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 decrease in volume sold to
wholesale customers was offset slightly by an increase in volume sold to retail customers.
-40-
|
|
|
Item 2. |
|
Managements Discussion and Analysis of Financial Condition and Results of Operations
(Cont.) |
The Energy Marketing segments earnings for the quarter ended March 31, 2011 were $6.3
million, an increase of $0.3 million when compared with earnings of $6.0 million for the quarter
ended March 31, 2010. The Energy Marketing segments earnings for the six months ended March 31,
2011 were $7.2 million, an increase of $0.1 million when compared with earnings of $7.1 million for
the six months ended March 31, 2010. These increases were largely attributable to higher margin of
$0.3 million for both the quarter and six-month periods, respectively. The increase in margin was
primarily driven by improved average margins per Mcf as well as an increase in volume sold to
retail customers. Partially offsetting the increase in earnings for the six months ended March 31,
2011 were higher operating expenses of $0.2 million primarily due to higher pension expense and
higher personnel costs, offset slightly by lower bad debt expense.
Corporate and All Other
2011 Compared with 2010
Corporate and All Other recorded earnings from continuing operations of $32.0 million for the
quarter ended March 31, 2011, an increase of $31.2 million when compared with earnings from
continuing operations of $0.8 million for the quarter ended March 31, 2010. The increase in
earnings is due to the gain on the sale of Horizon Powers investments in Seneca Energy and Model
City of $31.4 million, lower interest expense of $2.4 million (primarily the result of lower
borrowings at a lower interest rate due to the repayment of $200 million of 7.5% notes that matured
in November 2010), higher gathering and processing revenues of $1.4 million (due to an increase in
Midstream Corporations gathering and processing activities) and lower depreciation and depletion
expense of $1.0 million (due to a decrease in timber harvested as a result of the sale of the
Companys timber harvesting and milling operations in September 2010). The factors contributing to
the overall increase in earnings were partially offset by lower interest income of $2.3 million
(due to lower interest collected from the Companys Exploration and Production segment as a result
of the aforementioned November 2010 debt repayment), lower margins of $2.2 million (due to a
decrease in timber harvested as a result of the sale of the Companys timber harvesting and milling
operations in September 2010) and higher operating expenses of $0.3 million (primarily due to the
increase in Midstream Corporations operating activities).
For the six months ended March 31, 2011, Corporate and All Other had earnings from continuing
operations of $30.6 million, an increase of $29.8 million when compared with earnings from
continuing operations of $0.8 million for the six months ended March 31, 2010. The increase in
earnings is due to the gain on the sale of Horizon Powers investments in Seneca Energy and Model
City of $31.4 million, lower interest expense of $3.5 million (primarily the result of lower
borrowings at a lower interest rate due to the aforementioned November 2010 debt repayment), higher
gathering and processing revenues of $2.6 million (due to an increase in Midstream Corporations
gathering and processing activities) and lower depreciation and depletion expense of $2.1 million
(due to a decrease in timber harvested due to the sale of the Companys timber harvesting and
milling operations in September 2010). The factors contributing to the overall increase in earnings
were partially offset by lower margins of $5.1 million (due to a decrease in timber harvested due
to the sale of the Companys timber harvesting and milling operations in September 2010), lower
interest income of $3.3 million (due to lower interest collected from the Companys Exploration and
Production segment as a result of the aforementioned November 2010 debt repayment) and higher
operating expenses of $0.7 million (primarily due to the increase in Midstream Corporations
operating activities). Additionally, the Company recorded a loss from unconsolidated subsidiaries
of $0.4 million during the six months ended March 31, 2011 compared to income of $0.7 million
during the six months ended March 31, 2010.
Other Income
Other income increased $0.7 million for the quarter ended March 31, 2011 as compared with the
quarter ended March 31, 2010. This increase is mainly attributable to a gain on corporate-owned
life insurance policies of $0.5 million recognized during the quarter. In addition, there was a
$0.3 million increase in allowance for funds used during construction in the Pipeline and Storage
segment. For the six months ended March 31, 2011, other income increased $1.3 million as compared
with the six months ended March 31, 2010. This increase is attributable to a $0.5 million
gain on corporate-owned life insurance policies
-41-
|
|
|
Item 2. |
|
Managements Discussion and Analysis of Financial Condition and Results of Operations
(Cont.) |
recognized during the second quarter and a $0.4 million gain on the sale of Horizon Energy
Development recognized during the first quarter. In addition, there was a $0.5 million increase in
allowance for funds used during construction in the Pipeline and Storage segment.
Interest Expense on Long-Term Debt
Interest on long-term debt decreased $4.1 million for the quarter ended March 31,
2011 as compared with the quarter ended March 31, 2010. For the six months ended March 31, 2011,
interest on long-term debt decreased $6.0 million as compared with the six months ended March 31,
2010. This decrease is primarily the result of a lower average amount of long-term debt
outstanding, slightly lower average interest rates and capitalization of interest during the
quarter and six months ended March 31, 2011. The Company repaid $200 million of 7.5% notes that
matured in November 2010.
CAPITAL RESOURCES AND LIQUIDITY
The Companys primary source of cash during the six-month period ended March 31, 2011
consisted of cash provided by operating activities and net proceeds from the sale of unconsolidated
subsidiaries. The Companys primary source of cash during the six-month period ended March 31,
2010 consisted of cash provided by operating activities. This source of cash was supplemented by
issues of new shares of common stock as a result of stock option exercises for the six months ended
March 31, 2010. During the six months ended March 31, 2011 and March 31, 2010, 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. In April 2011, the Company
began issuing original issue shares for the Direct Stock Purchase and Dividend Reinvestment Plan.
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, deferred income
taxes, gain on the sale of unconsolidated subsidiaries, and income or loss from unconsolidated
subsidiaries net of cash distributions.
Cash provided by operating activities in the Utility and 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 $343.2 million for the six months ended
March 31, 2011, an increase of $63.9 million compared with $279.3 million provided by operating
activities for the six months ended March 31, 2010. In the Exploration and Production
segment, cash provided by operations
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Item 2. |
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Managements Discussion and Analysis of Financial Condition and Results of Operations
(Cont.) |
increased due to higher cash receipts from the sale of natural gas production. An increase in
hedging collateral deposits in the Exploration and Production segment at March 31, 2011 partly
offset the increase in cash provided by operating activities. Hedging collateral deposits serve as
collateral for open positions on exchange-traded futures contracts and over-the-counter swaps.
Investing Cash Flow
Expenditures for Long-Lived Assets
The Companys
expenditures from continuing operations for long-lived assets totaled
$382.7
million during the six months ended March 31, 2011 and $236.0 million for the six months ended
March 31, 2010. The table below presents these expenditures:
Total Expenditures for Long-Lived Assets
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended March 31, |
|
|
|
|
|
|
|
|
|
Increase |
|
(Millions) |
|
2011 |
|
|
2010 |
|
|
(Decrease) |
|
Utility : |
|
|
|
|
|
|
|
|
|
|
|
|
Capital Expenditures |
|
$ |
25.4 |
|
|
$ |
25.5 |
|
|
$ |
(0.1 |
) |
Pipeline and Storage: |
|
|
|
|
|
|
|
|
|
|
|
|
Capital Expenditures |
|
|
39.5 |
(1) |
|
|
15.5 |
|
|
|
24.0 |
|
Exploration and Production: |
|
|
|
|
|
|
|
|
|
|
|
|
Capital Expenditures |
|
|
315.2 |
(1)(2) |
|
|
191.0 |
(3)(4) |
|
|
124.2 |
|
All Other: |
|
|
|
|
|
|
|
|
|
|
|
|
Capital Expenditures |
|
|
2.6 |
|
|
|
4.0 |
(4) |
|
|
(1.4 |
) |
|
|
|
|
|
|
|
|
|
|
Total Expenditures from Continuing
Operations |
|
$ |
382.7 |
|
|
$ |
236.0 |
|
|
$ |
146.7 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Capital expenditures for the Exploration and Production
segment include $43.9
million of accrued capital expenditures at March 31, 2011, the majority of which was in the
Appalachian region. In addition, capital expenditures for the Pipeline and Storage segment include
$2.0 million of accrued capital expenditures at March 31, 2011. These amounts were excluded from
the Consolidated Statement of Cash Flows at March 31, 2011 since they represented non-cash
investing activities at that date. |
|
(2) |
|
Amount for the six months ended March 31, 2011 excludes $55.5 million of
accrued capital expenditures in the Exploration and Production segment, the majority of which was
in the Appalachian region. This amount was accrued at September 30, 2010 and paid during the six
months ended March 31, 2010. This amount was excluded from the Consolidated Statement of Cash
Flows at September 30, 2010 since it represented a non-cash investing activity at that date. The
amount has been included in the Consolidated Statement of Cash Flows at March 31, 2011. |
|
(3) |
|
Amount includes $15.3 million of accrued capital expenditures at March 31,
2010, the majority of which was in the Appalachian region. This amount has been excluded from the
Consolidated Statement of Cash Flows at March 31, 2010 since it represents a non-cash investing
activity at that date. |
|
(4) |
|
Capital expenditures for the Exploration and Production segment for the six
months ended March 31, 2010 exclude $9.1 million of capital expenditures, the majority of which was
in the Appalachian region. Capital expenditures for All Other for the six months ended March 31,
2010 exclude $0.7 million of 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 six months ended March 31, 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
March 31, 2010. |
Utility
The majority of the Utility capital expenditures for the six months ended March 31, 2011 and
March 31, 2010 were made for replacement of mains and main extensions, as well as for the
replacement of service lines.
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Item 2. |
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Managements Discussion and Analysis of Financial Condition and Results of Operations
(Cont.) |
Pipeline and Storage
The majority of the Pipeline and Storage capital expenditures for the six months
ended March 31, 2011 and March 31, 2010 were related to additions, improvements, and replacements
to this segments transmission and gas storage systems. In addition, the Pipeline and Storage
capital expenditure amounts for the six months ended March 31, 2011 include $7.3 million spent on
the Line N Expansion Project, $5.0 million spent on the Lamont Phase II Project and $4.0 million
spent on the Tioga County Extension Project, as discussed below. The Pipeline and Storage capital
expenditure amounts for the six months ended March 31, 2010, also include $2.5 million spent on the
Lamont Project.
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, the amounts remain in
Deferred Charges until such time as capital expenditures for the project have been incurred and
activities that are necessary to get the construction project ready for its intended use are in
progress. At that 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. As of
March 31, 2011, the total amount reserved for the Pipeline and Storage segments preliminary survey
and investigation costs was $6.6 million.
Supply Corporation and Empire are moving forward with several projects designed to move
anticipated Marcellus production gas to other interstate pipelines and to markets beyond the Supply
Corporation and Empire pipeline systems.
Supply Corporation has signed a 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 will provide the
subscribing shipper with a firm transportation path from the Tennessee Gas Pipeline (TGP) 300
Line at Ellisburg to the TransCanada Pipeline at Niagara. This path is attractive because it
provides a route for Marcellus shale gas, principally along the TGP 300 Line in northern
Pennsylvania, to be transported from the Marcellus supply basin to northern markets. Service is
expected to begin in November 2012, and Supply Corporation filed an application for FERC
authorization of the project on March 7, 2011. The project facilities involve approximately 9,500
horsepower of additional compression at Supply Corporations existing Ellisburg Station and a new
approximately 5,000 horsepower compressor station in East Aurora, New York, along with other system
enhancements including enhancements to the jointly owned Niagara Spur Loop Line. The preliminary
cost estimate for the Northern Access expansion is $62 million. As of March 31, 2011, approximately
$0.4 million has been spent to study the Northern Access expansion project, which has been included
in preliminary survey and investigation charges and has been fully reserved for at March 31, 2011.
Another expansion project involves new compression along Supply Corporations Line N (Line N
Expansion Project), increasing that lines capacity by 160,000 Dth/day into Texas Easterns
Holbrook Station (TETCO Holbrook) in southwestern Pennsylvania. Two service agreements totaling
160,000 Dth/day of firm transportation have been executed. The project will allow Marcellus
production located in the vicinity of Line N to flow south into Texas Eastern and access markets
off Texas Easterns system, with a projected in-service date of September 2011. The FERC issued the
NGA Section 7(c) certificate on December 16, 2010. Supply Corporation has accepted the certificate,
received a FERC Notice to Proceed, and in February 2011 commenced construction. Service agreements
for all 160,000 Dth/day of firm transportation have been executed. The preliminary cost estimate
for the Line N Expansion Project is $20 million. As of March 31, 2011, approximately $7.3 million
has been spent on the Line N expansion project, all of which has been capitalized as Construction
Work in Progress.
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|
Item 2. |
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Managements Discussion and Analysis of Financial Condition and Results of Operations
(Cont.) |
Supply Corporation has also executed a precedent agreement for 150,000 Dth/day of additional
capacity on Line N to TETCO Holbrook and has designed a project for their shippers to be ready for
service beginning November 2012 (Line N 2012 Expansion Project). The preliminary cost estimate
for the Line N 2012 Expansion Project is approximately $30 million. As of March 31, 2011,
approximately $0.1 million has been spent to study the Line N 2012 Expansion Project, which has
been included in preliminary survey and investigation charges and has been fully reserved for at
March 31, 2011.
Following up on Supply Corporations Lamont Project that went into service on June 15, 2010, a
second Lamont project is planned (Lamont Phase II Project). With the construction of an
additional 3,400 horsepower, 50,000 Dth/day of incremental firm capacity is expected to be
available starting July 1, 2011 ramping up to full service by approximately October 1, 2011. Supply
Corporation has two executed binding service agreements for the full capacity of this project. The
preliminary cost estimate for the Lamont Phase II Project is approximately $7.6 million. The
Company began construction in March 2011. As of March 31, 2011, approximately $5.0 million has been
spent on the Lamont Phase II project, all of which has been capitalized as Construction Work in
Progress.
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. As currently envisioned, the first
two phases of W2E, referred to as the W2E Overbeck to Leidy project, are 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.
Following an Open Season that concluded on October 8, 2009, Supply Corporation executed
precedent agreements to provide 125,000 Dth/day of firm transportation on the W2E Overbeck to Leidy
project. 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 the W2E Overbeck to Leidy project
is estimated to be $260 million. As of March 31, 2011, approximately $4.4 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 March 31, 2011.
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 project, 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 the
Appalachian Lateral and all other remaining sections of W2E. The timeline and projected costs
associated with W2E sections other than W2E Overbeck to Leidy, including the Appalachian Lateral
project, will depend on market development, and as of March 31, 2011, no preliminary survey and
investigation charges had been spent on those projects.
Empire has executed precedent agreements for all 350,000 Dth/day of incremental firm
transportation capacity in its Tioga County Extension Project. This project will transport
Marcellus production from new interconnections at the southern terminus of a 15-mile extension of
its recently completed Empire Connector line, in Tioga County, Pennsylvania. Empires preliminary
cost estimate for the Tioga County Extension Project is approximately $49 million. This project
will enable shippers to deliver their natural 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. On January 28, 2010, the
FERC granted Empires request for a pre-filing environmental review of the Tioga County Extension
Project, and on August 26, 2010, Empire filed an NGA Section 7(c) application to the
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|
Item 2. |
|
Managements Discussion and Analysis of Financial Condition and Results of Operations
(Cont.) |
FERC for approval of the project. Empire anticipates that these facilities will be placed in
service on September 1, 2011. As of March 31, 2011, approximately $4.0 million has been spent
related to the Tioga County Extension Project, all of which has been capitalized as Construction
Work in Progress.
On December 17, 2010, Empire concluded an Open Season for up to 260,000 Dth per day of
additional capacity from Tioga County, Pennsylvania, to TransCanada Pipeline and the TGP 200 Line,
as well as additional short-haul capacity to Millennium Pipeline at Corning (Central Tioga County
Extension). Empire is evaluating the substantial market interest resulting from this Open Season,
which was for more than 260,000 Dth per day of capacity, and is studying the facility design that
would be necessary to provide the requested service. The Central Tioga County Extension project
may involve up to 25,000 horsepower of compression at up to three new stations and a 25 mile 24
pipeline extension, at a preliminary cost estimate of $135 million. As of March 31, 2011, less
than $0.1 million has been spent to study the Central Tioga County Extension project, which has
been included in preliminary survey and investigation charges and has been fully reserved for at
March 31, 2011. No decision has been made to proceed with this project.
The Company anticipates financing the Line N Expansion Projects, the Lamont Project, the
Northern Access expansion project, the W2E Overbeck to Leidy project, the Appalachian Lateral
project, and the Tioga County Extension Projects, all of which are discussed above, with a
combination of cash from operations, short-term debt, and long-term debt. The Company had $144.8
million in Cash and Temporary Cash Investments at March 31, 2011, 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 debt providing temporary financing when needed. The
Company may issue some long-term debt in conjunction with these projects in the later part of
fiscal 2011 or in fiscal 2012.
Exploration and Production
The Exploration and Production segment capital expenditures for the six months ended March 31,
2011 were primarily well drilling and completion expenditures and included approximately $298.7
million for the Appalachian region (including $295.7 million in the Marcellus Shale area), $14.7
million for the West Coast region and $1.8 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. These amounts included
approximately $109.4 million spent to develop proved undeveloped reserves. The capital expenditures
in the Appalachian region include the Companys acquisition of oil and gas properties in the
Covington Township area of Tioga County, Pennsylvania from EOG Resources, Inc. for approximately
$24.1 million in November 2010. The Company funded this transaction with cash from operations.
As the Company has been accelerating its Marcellus Shale development, it has been decreasing
its emphasis in the Gulf Coast region. In March 2011, the Company entered into a purchase and sale
agreement to sell its off-shore oil and natural gas properties in the Gulf of Mexico effective as
of January 1, 2011 for approximately $70 million and received a deposit of $7.0 million from the
purchaser. The Company completed the sale in April 2011, receiving an additional $54.8 million.
The difference between the total proceeds received of $61.8 million and the sale price of $70.0
million represents a purchase price adjustment for the operating cash
flow that the Company recorded from
January 1, 2011 to the closing date of the sale. Under the full cost method of accounting for oil
and natural gas properties, the sale proceeds were accounted for as a reduction of capitalized
costs in April 2011. Since the disposition did not significantly alter the relationship between
capitalized costs and proved reserves of oil and gas attributable to the cost center, the Company
did not record any gain or loss from this sale.
The Exploration and Production segment capital expenditures for the six months ended March 31,
2010 were primarily well drilling and completion expenditures and included approximately $170.8
million for the Appalachian region (including $152.7 million in the Marcellus Shale area), $14.8
million for the West Coast region and $5.4 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. These amounts included
approximately $18.2 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
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|
|
Item 2. |
|
Managements Discussion and Analysis of Financial Condition and Results of Operations
(Cont.) |
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. The
transaction closed on March 12, 2010.
For all of fiscal 2011, the Company expects to spend $629.0 million on Exploration and
Production segment capital expenditures. Previously reported 2011 estimated capital expenditures
for the Exploration and Production segment were $531.0 million. In the Appalachian region,
estimated capital expenditures will increase from $490.0 million to $588.0 million. The Company
had previously reported that it anticipates drilling 100 to 130 gross wells in the Marcellus Shale
during 2011. The Company now anticipates drilling 85 to 110 gross horizontal wells in the
Marcellus Shale during 2011. The increase in estimated capital expenditures in the Appalachian
region is primarily due to an increase in estimated well costs due to drilling longer laterals in
horizontal wells, hydraulic fracturing at more stages per well, and an increase in service company
completion costs.
For all of fiscal 2012, the Company expects to spend $732.0 million on Exploration and
Production segment capital expenditures. Previously reported 2012 estimated capital expenditures
for the Exploration and Production segment were $596.0 million. In the Appalachian region,
estimated capital expenditures will increase from $533.0 million to $689.0 million. Estimated
capital expenditures in the Gulf Coast region will decrease from $20.0 million to zero. Estimated
capital expenditures in the West Coast region will remain at the previously reported $43.0 million.
The Company had previously reported that it anticipates drilling 130 to 160 gross wells in the
Marcellus Shale during fiscal 2012. The Company now anticipates drilling 115 to 140 gross
horizontal wells in the Marcellus Shale during fiscal 2012. The increase in estimated capital
expenditures in the Appalachian region is primarily due to an increase in estimated well costs, as
noted above. The decline in the Gulf Coast region estimated capital expenditures is due to the
Companys sale of its offshore Gulf of Mexico oil and natural gas producing properties, as noted
above.
The Company expects to use cash from operations and cash from asset sales as the first means
of financing its future capital expenditures during 2011 and 2012, with short-term debt providing
temporary financing when needed. 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 with cash from operations. The Company may issue some long-term debt in conjunction with
these expenditures in the later part of fiscal 2011 or in fiscal 2012.
All Other
The majority of the All Other categorys capital expenditures for the six months ended March
31, 2011 were primarily for expansion of Midstream Corporations Covington Gathering system in
Tioga County, Pennsylvania as well as for the construction of Midstream Corporations Trout Run
Gathering System, as discussed below. The majority of the All Other categorys capital expenditures
for the six months ended March 31, 2010 were for the construction of Midstream Corporations
Covington Gathering System.
NFG Midstream Trout Run, LLC, a wholly owned subsidiary of Midstream Corporation, is
developing a gathering system in Lycoming County, Pennsylvania. The project, called the Trout Run
Gathering System, is anticipated to be placed in service in the fall of 2011. The system will
consist of approximately 16.5 miles of gathering system at a cost of $35 million. As of March 31,
2011, the Company has spent approximately $0.9 million in costs related to this project.
The Company anticipates funding the Trout Run Gathering System project with cash from
operations and/or short-term borrowings. Given the Companys cash position at March 31, 2011, the
Company expects to use cash from operations as the first means of financing these projects.
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
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|
Item 2. |
|
Managements Discussion and Analysis of Financial Condition and Results of Operations
(Cont.) |
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 March 31, 2011. During the six months ended March 31, 2011, consolidated short-term debt did
not exceed $31.5 million outstanding. 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 $385.0 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 substantially 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, 2013. Under the Companys committed
credit facility, the Company has agreed that its debt to capitalization ratio will not exceed .65
at the last day of any fiscal quarter through September 30, 2013. At March 31, 2011, the Companys
debt to capitalization ratio (as calculated under the facility) was .37. The constraints specified
in the committed credit facility would permit an additional $2.32 billion in short-term and/or
long-term debt to be outstanding (further limited by the indenture covenants discussed below)
before the Companys debt to capitalization ratio would exceed .65. If a downgrade in any of the
Companys credit ratings were to occur, access to the commercial paper markets might not be
possible. However, the Company expects that it could borrow under its committed credit facility,
uncommitted bank lines of credit or rely upon other liquidity sources, including cash provided by
operations.
Under the Companys existing indenture covenants, at March 31, 2011, the Company would have
been permitted to issue up to a maximum of $1.65 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 a significant loss in
the future (for example, as a result of an impairment of oil and gas properties), it is possible,
depending on factors including the magnitude of the loss, that these indenture covenants would
restrict the Companys ability to issue additional long-term unsecured indebtedness for a period of
up to nine calendar months, beginning with the fourth calendar month following the loss. This would
not at any time preclude the Company from issuing new indebtedness to replace maturing debt.
The Companys 1974 indenture pursuant to which $99.0 million (or 9.4%) of the Companys
long-term debt (as of March 31, 2011) 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
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|
Item 2. |
|
Managements Discussion and Analysis of Financial Condition and Results of Operations
(Cont.) |
repayment obligation could be triggered if (i) the Company or any of its significant subsidiaries
fails to make a payment when due of any principal or interest on any other indebtedness aggregating
$40.0 million or more, or (ii) an event occurs that causes, or would permit the holders of any
other indebtedness aggregating $40.0 million or more to cause, such indebtedness to become due
prior to its stated maturity. As of March 31, 2011, the Company had no debt outstanding under the
committed credit facility.
The Companys embedded cost of long-term debt was 6.85% at March 31, 2011 and 6.95% at March
31, 2010. If the Company were to issue 10-year long-term debt today, its borrowing costs might be
expected to be in the range of 4.75% to 5.25%.
Current Portion of Long-Term Debt at March 31, 2011 consists of $150 million of 6.70%
medium-term notes that mature in November 2011. Currently, the Company expects to refund these
medium-term notes in November 2011 with cash on hand, short-term borrowings and/or long-term debt.
In November 2010, the Company repaid $200 million of 7.50% notes that matured on November 22, 2010
that were classified as Current Portion of Long-Term Debt at September 30, 2010.
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 $25.0 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.
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 six months ended March 31, 2011, the Company contributed $32.4 million to its
Retirement Plan and $16.0 million to its VEBA trusts and 401(h) accounts for its other
post-retirement benefits. In the remainder of 2011, the Company expects to contribute at a minimum
in the range of $7.0 million to $15.0 million to the Retirement Plan. Changes in the discount
rate, other actuarial assumptions, and asset performance could ultimately cause the Company to fund
larger amounts to the Retirement Plan in fiscal 2011 in order to be in compliance with the Pension
Protection Act of 2006. In the remainder of 2011, the Company expects to contribute in the range
of $9.0 million to $14.0 million to its VEBA trusts and 401(h) accounts.
Market Risk Sensitive Instruments
On July 21, 2010, the Dodd-Frank 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. A variety of rules must be adopted by federal agencies (including the
Commodity Futures Trading Commission, SEC and the FERC) to implement the law. These rules, which
will be implemented over time frames as determined in the law, could have a significant impact on
the Company. For example, while the Company
-49-
|
|
|
Item 2. |
|
Managements Discussion and Analysis of Financial Condition and Results of Operations
(Cont.) |
expects to be exempt from the laws mandatory clearing and exchange trading requirements for most
or all of its commodity hedges, other requirements with respect to these hedges, including capital,
margin and reporting requirements, may apply to the Company. These requirements will be determined
as regulators write detailed rules. The Company is currently reviewing the provisions of H.R. 4173
and proposed rules, but it will not be able to determine the impact to its financial condition
until the final rules 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 net 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 derivative net 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 $71.9 million
at March 31, 2011 and represent 41.2% of the Total Net Assets shown in Part I, Item 1 at Note 2
Fair Value Measurements at March 31, 2011.
The increase in the net fair value liability of the Level 3 positions from October 1, 2010 to
March 31, 2011, 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 March 31, 2011.
The fair value of all of the Companys Net Derivative Liability was reduced by $0.1 million
based upon the Companys assessment of counterparty credit risk (for the Companys derivative
assets) and the Companys credit risk (for the Companys derivative liabilities). The Company
applied default probabilities to the anticipated cash flows that it was expecting to receive and
pay to 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 2010 Form 10-K. There have been no subsequent
material changes to the Companys exposure to market risk sensitive instruments.
Rate and Regulatory Matters
Utility Operation
Delivery rates for both the New York and Pennsylvania divisions are regulated by the states
respective public utility commissions and are changed when approved through a procedure known as a
rate case. Currently neither division has a rate case on file. In both jurisdictions, delivery
rates do not reflect the recovery of purchased gas costs. Prudently-incurred gas costs are
recovered through operation of automatic adjustment clauses, and are collected largely through a
separately-stated supply charge on the customer bill.
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 that would collect up to $10.8
million to cover 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 decouples revenues from throughput by enabling the Company to collect
from small volume customers its allowed margin on average
-50-
Item 2. Managements Discussion and Analysis of Financial Condition and Results of
Operations (Cont.)
weather normalized usage per customer. The effect of the revenue decoupling mechanism is to render
the Company financially indifferent to throughput decreases resulting from conservation. The
Company surcharges or credits any difference from the average weather normalized usage per customer
account. The surcharge or credit is calculated to recover total margin for the most recent
twelve-month period ending December 31, and is applied to customer bills annually, beginning March
1st.
On April 18, 2008, Distribution Corporation filed an appeal with Supreme Court, Albany County,
seeking review of the rate order. The appeal 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. The NYPSCs motion was granted and was followed by briefs and oral
argument. On March 29, 2011, the Court of Appeals issued a judgment and opinion affirming the
Appellate Divisions judgment.
Pennsylvania Jurisdiction
Distribution Corporations current delivery charges in its Pennsylvania jurisdiction were
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.
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
$14.6 million.
At March 31, 2011, 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 $17.1 million to $21.3
million. The minimum estimated
-51-
Item 2. Managements Discussion and Analysis of Financial Condition and Results of Operations
(Cont.)
liability of $17.1 million, which includes the $14.6 million discussed above, has been recorded on
the Consolidated Balance Sheet at March 31, 2011. The Company expects to recover its 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. Pursuant to an EPA determination, effective
January 2011 projects proposing new stationary sources of significant greenhouse gas emissions or
major modifications of existing facilities are required under the federal Clean Air Act to obtain
permits covering such emissions. In April, the U.S. Senate rejected bills aimed at curbing the
authority of the EPA to regulate greenhouse gas emissions. In addition, the U.S. Congress has from
time to time considered 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.
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, estimates of oil and gas quantities, strategies, future events or performance and
underlying assumptions, capital structure, anticipated capital expenditures, completion of
construction projects, projections for pension and other post-retirement benefit obligations,
impacts of the adoption of new accounting rules, and possible outcomes of litigation or regulatory
proceedings, as well as statements that are identified by the use of the words anticipates,
estimates, expects, forecasts, intends, plans, predicts, projects, believes,
seeks, will, may, and similar expressions, are forward-looking statements as defined in the
Private Securities Litigation Reform Act of 1995 and accordingly involve risks and uncertainties
which could cause actual results or outcomes to differ materially from those expressed in the
forward-looking statements. The forward-looking statements contained herein are based on various
assumptions, many of which are based, in turn, upon further assumptions. The Companys
expectations, beliefs and projections are expressed in good faith and are believed by the Company
to have a reasonable basis, including, without limitation, managements examination of historical
operating trends, data contained in the Companys records and other data available from third
parties, but there can be no assurance that managements expectations, beliefs or projections will
result or be achieved or accomplished. In addition to other factors and matters discussed
elsewhere herein, the following are important factors that, in the view of the Company, could cause
actual results to differ materially from those discussed in the forward-looking statements:
-52-
Item 2. Managements Discussion and Analysis of Financial Condition and Results of Operations
(Cont.)
|
1. |
|
Financial and economic conditions, including the availability of credit, and occurrences
affecting the Companys ability to obtain financing on acceptable terms for working capital,
capital expenditures and other investments, including any downgrades in the Companys credit
ratings and changes in interest rates and other capital market conditions; |
|
|
2. |
|
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; |
|
|
3. |
|
The creditworthiness or performance of the Companys key suppliers, customers and
counterparties; |
|
|
4. |
|
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; |
|
|
5. |
|
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, the need to obtain governmental approvals and permits, and compliance
with environmental laws and regulations; |
|
|
6. |
|
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; |
|
|
7. |
|
Uncertainty of oil and gas reserve estimates; |
|
|
8. |
|
Significant differences between the Companys projected and actual production levels for
natural gas or oil; |
|
|
9. |
|
Significant changes in market dynamics or competitive factors affecting the Companys ability
to retain existing customers or obtain new customers; |
|
|
10. |
|
Changes in demographic patterns and weather conditions; |
|
|
11. |
|
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; |
|
|
12. |
|
Impairments under the SECs full cost ceiling test for natural gas and oil reserves; |
|
|
13. |
|
Changes in the availability and/or price of derivative financial instruments; |
|
|
14. |
|
Changes in price differential between similar quantities of natural gas at different
geographic locations, and the effect of such changes on the demand for pipeline transportation
capacity to or from such locations; |
|
|
15. |
|
Other changes in price differentials between similar quantities of oil or natural gas having
different quality, heating value, geographic location or delivery date; |
|
|
16. |
|
Changes in the projected profitability of pending or potential projects, investments or
transactions; |
|
|
17. |
|
Significant differences between the Companys projected and actual capital expenditures and
operating expenses; |
|
|
18. |
|
Delays or changes in costs or plans with respect to Company projects or related projects of
other companies, including difficulties or delays in obtaining necessary governmental
approvals, permits or orders or in obtaining the cooperation of interconnecting facility
operators; |
-53-
Item 2. Managements Discussion and Analysis of Financial Condition and Results of Operations
(Concl.)
|
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.
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
-54-
Item 4. Controls and Procedures (Concl.)
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 March 31, 2011.
Changes in Internal Control Over Financial Reporting
There were no changes in the Companys internal control over financial reporting that occurred
during the quarter ended March 31, 2011 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 2010 Form 10-K, as amended by Item 1A of Part II
of the Companys Form 10-Q for the quarter ended December 31, 2010, have not materially changed
other than as set forth below. The risk factor presented below supersedes the risk factor having
the same caption in the 2010 Form 10-K and should otherwise be read in conjunction with all of the
risk factors disclosed in that Form 10-K and in the Companys December 31, 2010 Form 10-Q.
The Company has significant transactions involving price hedging of its oil and natural gas
production as well as its fixed price purchase and sale commitments.
In order to protect itself to some extent against unusual price volatility and to lock in
fixed pricing on oil and natural gas production for certain periods of time, the Companys
Exploration and Production segment regularly enters into commodity price derivatives contracts
(hedging arrangements) with respect to a portion of its expected production. These contracts may at
any time cover as much as approximately 80% of the Companys expected energy production during the
upcoming 12-month period. These contracts reduce exposure to subsequent price drops but can also
limit the Companys ability to benefit from increases in commodity prices. In addition, the Energy
Marketing segment enters into certain hedging arrangements, primarily with respect to its fixed
price purchase and sales commitments and its gas stored underground. The Companys Pipeline and
Storage segment enters into hedging arrangements with respect to certain sales of efficiency gas.
Under applicable accounting rules currently in effect, the Companys hedging arrangements are
subject to quarterly effectiveness tests. Inherent within those effectiveness tests are assumptions
concerning the long-term price differential between different types of crude oil, assumptions
concerning the difference between published natural gas price indexes established by pipelines in
which hedged natural gas production
-55-
Item 1A. Risk Factors (Concl.)
is delivered and the reference price established in the hedging arrangements, assumptions regarding
the levels of production that will be achieved and, with regard to fixed price commitments,
assumptions regarding the creditworthiness of certain customers and their forecasted consumption of
natural gas. Depending on market conditions for natural gas and crude oil and the levels of
production actually achieved, it is possible that certain of those assumptions may change in the
future, and, depending on the magnitude of any such changes, it is possible that a portion of the
Companys hedges may no longer be considered highly effective. In that case, gains or losses from
the ineffective derivative financial instruments would be marked-to-market on the income statement
without regard to an underlying physical transaction. For example, in the Exploration and
Production segment, where the Company uses short positions (i.e. positions that pay off in the
event of commodity price decline) to hedge forecasted sales, gains would occur to the extent that
natural gas and crude oil hedge prices exceed market prices for the Companys natural gas and crude
oil production, and losses would occur to the extent that market prices for the Companys natural
gas and crude oil production exceed hedge prices.
Use of energy commodity price hedges also exposes the Company to the risk of non-performance
by a contract counterparty. These parties might not be able to perform their obligations under the
hedge arrangements.
It is the Companys policy that the use of commodity derivatives contracts comply with various
restrictions in effect in respective business segments. For example, in the Exploration and
Production segment, commodity derivatives contracts must be confined to the price hedging of
existing and forecast production, and in the Energy Marketing segment, commodity derivatives with
respect to fixed price purchase and sales commitments must be matched against commitments
reasonably certain to be fulfilled. Similar restrictions apply in the Pipeline and Storage segment.
The Company maintains a system of internal controls to monitor compliance with its policy. However,
unauthorized speculative trades, if they were to occur, could expose the Company to substantial
losses to cover positions in its derivatives contracts. In addition, in the event the Companys
actual production of oil and natural gas falls short of hedged forecast production, the Company may
incur substantial losses to cover its hedges.
In July 2010, the Dodd-Frank Wall Street Reform and Consumer Protection Act was signed into
law. The law includes provisions aimed at increasing the transparency and stability of the
over-the-counter derivatives markets and preventing excessive speculation. A variety of rules must
be adopted by federal agencies (including the Commodity Futures Trading Commission, SEC and the
FERC) to implement the law. These rules, which have not yet been finalized, could reduce trading
positions in the energy futures markets and otherwise negatively impact the Company. For example,
while the Company expects to be exempt from the laws mandatory clearing and exchange trading
requirements for most or all of its commodity hedges, other requirements with respect to these
hedges, including capital, margin and reporting requirements, may apply to the Company. These
requirements could increase the Companys hedging costs. The new rules could also reduce the
Companys hedging opportunities, which could negatively affect the Companys revenues and cash flow
during periods of declining commodity prices and negatively affect the Companys expenses during
periods of rising commodity prices.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
On January 3, 2011, 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 2009 Non-Employee Director Equity Compensation Plan as partial consideration for such
directors services during the quarter ended March 31, 2011. These transactions were exempt from
registration under Section 4(2) of the Securities Act of 1933, as transactions not involving a
public offering.
-56-
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 Paid |
|
Repurchase Plans |
|
Repurchase Plans |
Period |
|
Purchased(a) |
|
per Share |
|
or Programs |
|
or Programs (b) |
Jan. 1 - 31, 2011 |
|
|
6,598 |
|
|
$ |
69.60 |
|
|
|
|
|
|
|
6,971,019 |
|
Feb. 1 - 28, 2011 |
|
|
92,361 |
|
|
$ |
70.87 |
|
|
|
|
|
|
|
6,971,019 |
|
Mar. 1 - 31, 2011 |
|
|
22,033 |
|
|
$ |
70.71 |
|
|
|
|
|
|
|
6,971,019 |
|
Total |
|
|
120,992 |
|
|
$ |
70.77 |
|
|
|
|
|
|
|
6,971,019 |
|
|
|
|
(a) |
|
Represents (i) shares of common stock of the Company purchased on the open market
with Company matching contributions for the accounts of participants in the Companys 401(k)
plans, and (ii) shares of common stock of the Company tendered to the Company by holders of
stock options, SARs or shares of restricted stock for the payment of option exercise prices or
applicable withholding taxes. During the quarter ended March 31, 2011, the Company did not
purchase any shares of its common stock pursuant to its publicly announced share repurchase
program. Of the 120,992 shares purchased other than through a publicly announced share
repurchase program, 18,311 were purchased for the Companys 401(k) plans
and 102,681 were purchased as a result of shares tendered to the Company by holders of stock
options, SARs or shares of restricted stock. |
|
|
|
|
(b) |
|
In September 2008, the Companys Board of Directors authorized the repurchase of
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. Since that time, the Company has increased its emphasis on Marcellus Shale
development and pipeline expansion. As such, the Company does not
anticipate repurchasing any shares in the near future. |
Item 6. Exhibits
|
|
|
|
|
Exhibit |
|
|
Number |
|
Description of Exhibit |
|
|
|
|
|
|
|
|
|
By-Laws of National Fuel Gas Company, as amended March 10, 2011
(incorporated herein by reference to Exhibit 3.1, Form 8-K dated March
14, 2011). |
|
|
|
|
|
|
12 |
|
|
Statements regarding Computation of Ratios: |
|
|
|
|
Ratio of Earnings to Fixed Charges for the Twelve Months Ended March
31, 2011 and the Fiscal Years Ended September 30, 2007 through 2010. |
|
|
|
|
|
|
31.1 |
|
|
Written statements of Chief Executive Officer pursuant to Rule
13a-14(a) or Rule 15d-14(a) under the Securities Exchange Act of 1934. |
|
|
|
|
|
|
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 Statement of Income for
the Twelve Months Ended March 31, 2011 and 2010. |
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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 six months ended March 31, 2011 and 2010, (ii) the Consolidated
Balance Sheets at March 31, 2011 and September 30, 2010, (iii) the Consolidated
Statements of Cash Flows for the six months ended March 31, 2011 and 2010, (iv)
the Consolidated Statements of Comprehensive Income for the three and six months
ended March 31, 2011 and 2010 and (v) the Notes to Condensed Consolidated
Financial Statements. |
Incorporated herein by reference as indicated.
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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
(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: May 6, 2011
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