NATIONAL FUEL GAS CO, 10-K filed on 11/24/2010
Annual Report
Document and Entity Information
Year Ended
Sep. 30, 2010
Oct. 31, 2010
Mar. 31, 2010
Document and Entity Information
 
 
 
Document Type
10-K 
 
 
Amendment Flag
FALSE 
 
 
Document Period End Date
2010-09-30 
 
 
Document Fiscal Year Focus
2010 
 
 
Document Fiscal Period Focus
FY 
 
 
Entity Registrant Name
NATIONAL FUEL GAS CO 
 
 
Entity Central Index Key
0000070145 
 
 
Current Fiscal Year End Date
09/30 
 
 
Entity Filer Category
Large Accelerated Filer 
 
 
Entity Common Stock, Shares Outstanding
 
82,190,871 
 
Entity Public Float
 
 
4,041,725,000 
Entity Current Reporting Status
Yes 
 
 
Entity Well-known Seasoned Issuer
Yes 
 
 
Entity Voluntary Filers
No 
 
 
Consolidated Statements of Income and Earnings Reinvested in the Business (USD $)
In Thousands, except Share data
Year Ended
Sep. 30,
2010
2009
2008
INCOME
 
 
 
Operating Revenues
$ 1,760,503 
$ 2,051,543 
$ 2,396,837 
Operating Expenses
 
 
 
Purchased Gas
658,432 
997,216 
1,238,405 
Operation and Maintenance
394,569 
401,200 
429,394 
Property, Franchise and Other Taxes
75,852 
72,102 
75,525 
Depreciation, Depletion and Amortization
191,199 
170,620 
169,846 
Impairment of Oil and Gas Producing Properties
182,811 
Total Operating Expenses
1,320,052 
1,823,949 
1,913,170 
Operating Income
440,451 
227,594 
483,667 
Other Income (Expense):
 
 
 
Income from Unconsolidated Subsidiaries
2,488 
3,366 
6,303 
Impairment of Investment in Partnership
(1,804)
Other Income
3,638 
8,200 
7,164 
Interest Income
3,729 
5,776 
10,815 
Interest Expense on Long-Term Debt
(87,190)
(79,419)
(70,099)
Other Interest Expense
(6,756)
(7,370)
(3,271)
Income from Continuing Operations Before Income Taxes
356,360 
156,343 
434,579 
Income Tax Expense
137,227 
52,859 
167,672 
Income from Continuing Operations
219,133 
103,484 
266,907 
Discontinued Operations:
 
 
 
Income (Loss) from Operations, Net of Tax
470 
(2,776)
1,821 
Gain on Disposal, Net of Tax
6,310 
Income (Loss) from Discontinued Operations, Net of Tax
6,780 
(2,776)
1,821 
Net Income Available for Common Stock
225,913 
100,708 
268,728 
EARNINGS REINVESTED IN THE BUSINESS
 
 
 
Balance at Beginning of Year
948,293 
953,799 
983,776 
Beginning Retained Earnings and Current Period Net Income
1,174,206 
1,054,507 
1,252,504 
Share Repurchases
(194,776)
Cumulative Effect of Adoption of Authoritative Guidance for Income Taxes
(406)
Adoption of Authoritative Guidance for Defined Benefit Pension and Other Post-Retirement Plans
(804)
Dividends on Common Stock
(110,944)
(105,410)
(103,523)
Balance at End of Year
1,063,262 
948,293 
953,799 
Earnings Per Common Share, Basic:
 
 
 
Income from Continuing Operations - Basic
2.7 
1.29 
3.25 
Income (Loss) from Discontinued Operations - Basic
0.08 
(0.03)
0.02 
Net Income Available for Common Stock
2.78 
1.26 
3.27 
Earnings Per Common Share, Diluted:
 
 
 
Income from Continuing Operations - Diluted
2.65 
1.28 
3.16 
Income (Loss) from Discontinued Operations - Diluted
0.08 
(0.03)
0.02 
Net Income Available for Common Stock
$ 2.73 
$ 1.25 
$ 3.18 
Weighted Average Common Shares Outstanding:
 
 
 
Used in Basic Calculation
81,380,434 
79,649,965 
82,304,335 
Used in Diluted Calculation
82,660,598 
80,628,685 
84,474,839 
Consolidated Balance Sheets (USD $)
In Thousands
Year Ended
Sep. 30,
2010
2009
ASSETS
 
 
Property, Plant and Equipment
$ 5,637,498 
$ 5,184,844 
Less - Accumulated Depreciation, Depletion and Amortization
2,187,269 
2,051,482 
Property, Plant and Equipment, Net, Total
3,450,229 
3,133,362 
Current Assets
 
 
Cash and Temporary Cash Investments
395,171 
408,053 
Cash Held in Escrow
2,000 
2,000 
Hedging Collateral Deposits
11,134 
848 
Receivables - Net of Allowance for Uncollectible Accounts of $30,961 and $38,334, Respectively
132,136 
144,466 
Unbilled Utility Revenue
20,920 
18,884 
Gas Stored Underground
48,584 
55,862 
Materials and Supplies - at average cost
24,987 
24,520 
Other Current Assets
115,969 
68,474 
Deferred Income Taxes
24,476 
53,863 
Total Current Assets
775,377 
776,970 
Other Assets
 
 
Recoverable Future Taxes
149,712 
138,435 
Unamortized Debt Expense
12,550 
14,815 
Other Regulatory Assets
542,801 
530,913 
Deferred Charges
9,646 
2,737 
Other Investments
77,839 
78,503 
Investments in Unconsolidated Subsidiaries
14,828 
14,940 
Goodwill
5,476 
5,476 
Intangible Assets
1,677 
21,536 
Fair Value of Derivative Financial Instruments
65,184 
44,817 
Other
306 
6,625 
Total Other Assets
880,019 
858,797 
Total Assets
5,105,625 
4,769,129 
Capitalization:
 
 
Common Stock, $1 Par Value Authorized - 200,000,000 Shares; Issued and Outstanding - 82,075,470 Shares and 80,499,915 Shares, Respectively
82,075 
80,500 
Paid in Capital
645,619 
602,839 
Earnings Reinvested in the Business
1,063,262 
948,293 
Total Common Shareholders' Equity Before Items Of Other Comprehensive Loss
1,790,956 
1,631,632 
Accumulated Other Comprehensive Loss
(44,985)
(42,396)
Total Comprehensive Shareholders' Equity
1,745,971 
1,589,236 
Long-Term Debt, Net of Current Portion
1,049,000 
1,249,000 
Total Capitalization
2,794,971 
2,838,236 
Current and Accrued Liabilities
 
 
Notes Payable to Banks and Commercial Paper
Current Portion of Long-Term Debt
200,000 
Accounts Payable
145,223 
90,723 
Amounts Payable to Customers
38,109 
105,778 
Dividends Payable
28,316 
26,967 
Interest Payable on Long-Term Debt
30,512 
32,031 
Customer Advances
27,638 
24,555 
Customer Security Deposits
18,320 
17,430 
Other Accruals and Current Liabilities
16,046 
18,875 
Fair Value of Derivative Financial Instruments
20,160 
2,148 
Total Current and Accrued Liabilities
524,324 
318,507 
Deferred Credits
 
 
Deferred Income Taxes
800,758 
663,876 
Taxes Refundable to Customers
69,585 
67,046 
Unamortized Investment Tax Credit
3,288 
3,989 
Cost of Removal Regulatory Liability
124,032 
105,546 
Other Regulatory Liabilities
89,334 
120,229 
Pension and Other Post-Retirement Liabilities
446,082 
415,888 
Asset Retirement Obligations
101,618 
91,373 
Other Deferred Credits
151,633 
144,439 
Total Deferred Credits
1,786,330 
1,612,386 
Commitments and Contingencies
 
 
Total Capitalization and Liabilities
$ 5,105,625 
$ 4,769,129 
Consolidated Balance Sheets (Parenthetical) (USD $)
In Thousands, except Share data
Sep. 30, 2010
Sep. 30, 2009
Consolidated Balance Sheets (Parenthetical)
 
 
Receivables Allowance for Uncollectible Accounts
$ 30,961 
$ 38,334 
Common Stock, Par Value
$ 1 
$ 1 
Common Stock, Shares Authorized
200,000,000 
200,000,000 
Common Stock, Shares Issued
82,075,470 
80,499,915 
Common Stock, Shares Outstanding
82,075,470 
80,499,915 
Consolidated Statement of Cash Flows (USD $)
In Thousands
Year Ended
Sep. 30,
2010
2009
2008
Operating Activities
 
 
 
Net Income Available for Common Stock
$ 225,913 
$ 100,708 
$ 268,728 
Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities:
 
 
 
Gain on Sale of Discontinued Operations
(10,334)
Impairment of Oil and Gas Producing Properties
182,811 
Depreciation, Depletion and Amortization
191,809 
173,410 
170,623 
Deferred Income Taxes
134,679 
(2,521)
72,496 
Income from Unconsolidated Subsidiaries, Net of Cash Distributions
112 
(466)
1,977 
Impairment of Investment in Partnership
1,804 
Excess Tax Benefits Associated with Stock-Based Compensation Awards
(13,207)
(5,927)
(16,275)
Other
9,108 
19,829 
4,858 
Change in:
 
 
 
Hedging Collateral Deposits
(10,286)
(847)
4,065 
Receivables and Unbilled Utility Revenue
10,262 
47,658 
(16,815)
Gas Stored Underground and Materials and Supplies
6,546 
43,598 
(22,116)
Unrecovered Purchased Gas Costs
37,708 
(22,939)
Prepayments and Other Current Assets
(34,288)
2,921 
(36,376)
Accounts Payable
8,047 
(61,149)
32,763 
Amounts Payable to Customers
(67,669)
103,025 
(7,656)
Customer Advances
3,083 
(8,462)
10,154 
Customer Security Deposits
890 
3,383 
609 
Other Accruals and Current Liabilities
(3,649)
13,676 
(4,250)
Other Assets
7,237 
(35,140)
(11,887)
Other Liabilities
1,442 
(4,201)
54,817 
Net Cash Provided by Operating Activities
459,695 
611,818 
482,776 
Investing Activities
 
 
 
Capital Expenditures
(455,764)
(313,633)
(397,734)
Investment in Subsidiary, Net of Cash Acquired
(34,933)
Net Proceeds from Sale of Timber Mill and Related Assets
15,770 
Net Proceeds from Sale of Landfill Gas Pipeline Assets
38,000 
Cash Held in Escrow
(2,000)
58,397 
Net Proceeds from Sale of Oil and Gas Producing Properties
3,643 
5,969 
Other
(251)
(2,806)
4,376 
Net Cash Used in Investing Activities
(402,245)
(349,729)
(328,992)
Financing Activities
 
 
 
Excess Tax Benefits Associated with Stock-Based Compensation Awards
13,207 
5,927 
16,275 
Shares Repurchased under Repurchase Plan
(237,006)
Net Proceeds from Issuance of Long-Term Debt
247,780 
296,655 
Reduction of Long-Term Debt
(100,000)
(200,024)
Net Proceeds from Issuance of Common Stock
26,057 
28,176 
17,432 
Dividends Paid on Common Stock
(109,596)
(104,158)
(103,683)
Net Cash Provided by (Used in) Financing Activities
(70,332)
77,725 
(210,351)
Net Increase (Decrease) in Cash and Temporary Cash Investments
(12,882)
339,814 
(56,567)
Cash and Temporary Cash Investments At Beginning of Year
408,053 
68,239 
124,806 
Cash and Temporary Cash Investments At End of Year
395,171 
408,053 
68,239 
Cash Paid For:
 
 
 
Interest
93,333 
75,640 
69,841 
Income Taxes
$ 30,975 
$ 40,638 
$ 103,154 
Consolidated Statements of Comprehensive Income (USD $)
In Thousands
Year Ended
Sep. 30,
2010
2009
2008
Consolidated Statements of Comprehensive Income
 
 
 
Net Income Available for Common Stock
$ 225,913 
$ 100,708 
$ 268,728 
Other Comprehensive Income (Loss), Before Tax:
 
 
 
Decrease in the Funded Status of the Pension and Other Post-Retirement Benefit Plans
(30,155)
(71,771)
(13,584)
Reclassification Adjustment for Amortization of Prior Year Funded Status of the Pension and Other Post-Retirement Benefit Plans
5,000 
1,008 
1,924 
Foreign Currency Translation Adjustment
53 
(33)
12 
Unrealized Loss on Securities Available for Sale Arising During the Period
(2,195)
(6,118)
(4,856)
Unrealized Gain (Loss) on Derivative Financial Instruments Arising During the Period
65,366 
119,210 
(31,490)
Reclassification Adjustment for Realized (Gains) Losses on Derivative Financial Instruments in Net Income
(41,320)
(114,380)
64,645 
Other Comprehensive Income (Loss), Before Tax
(3,251)
(72,084)
16,651 
Income Tax Benefit Related to the Decrease in the Funded Status of the Pension and Other Post-Retirement Benefit Plans
(11,379)
(27,082)
(5,127)
Reclassification Adjustment for Income Tax Benefit Related to the Amortization of the Prior Year Funded Status of the Pension and Other Post-Retirement Benefit Plans
1,887 
380 
726 
Income Tax Benefit Related to Unrealized Loss on Securities Available for Sale Arising During the Period
(831)
(2,311)
(1,434)
Income Tax Expense (Benefit) Related to Unrealized Gain (Loss) on Derivative Financial Instruments Arising During the Period
26,628 
48,293 
(13,228)
Reclassification Adjustment for Income Tax (Expense) Benefit on Realized (Gains) Losses on Derivative Financial Instruments in Net Income
(16,967)
(46,005)
26,548 
Income Taxes - Net
(662)
(26,725)
7,485 
Other Comprehensive Income (Loss)
(2,589)
(45,359)
9,166 
Comprehensive Income
$ 223,324 
$ 55,349 
$ 277,894 
Summary of Significant Accounting Policies
Summary of Significant Accounting Policies
Note A — Summary of Significant Accounting Policies
 
Principles of Consolidation
 
The Company consolidates its majority owned entities. The equity method is used to account for minority owned entities. All significant intercompany balances and transactions are eliminated. The Company uses proportionate consolidation when accounting for drilling arrangements related to oil and gas producing properties accounted for under the full cost method of accounting.
 
The preparation of the consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
 
Reclassification
 
Certain prior year amounts have been reclassified to conform with current year presentation.
 
Regulation
 
The Company is subject to regulation by certain state and federal authorities. The Company has accounting policies which conform to GAAP, as applied to regulated enterprises, and are in accordance with the accounting requirements and ratemaking practices of the regulatory authorities. Reference is made to Note C — Regulatory Matters for further discussion.
 
Revenue Recognition
 
The Company's Utility segment records revenue as bills are rendered, except that service supplied but not billed is reported as unbilled utility revenue and is included in operating revenues for the year in which service is furnished.
 
The Company's Energy Marketing segment records revenue as bills are rendered for service supplied on a monthly basis.
 
The Company's Pipeline and Storage segment records revenue for natural gas transportation and storage services. Revenue from reservation charges on firm contracted capacity is recognized through equal monthly charges over the contract period regardless of the amount of gas that is transported or stored. Commodity charges on firm contracted capacity and interruptible contracts are recognized as revenue when physical deliveries of natural gas are made at the agreed upon delivery point or when gas is injected or withdrawn from the storage field. The point of delivery into the pipeline or injection or withdrawal from storage is the point at which ownership and risk of loss transfers to the buyer of such transportation and storage services.
 
The Company's Exploration and Production segment records revenue based on entitlement, which means that revenue is recorded based on the actual amount of gas or oil that is delivered to a pipeline and the Company's ownership interest in the producing well. If a production imbalance occurs between what was supposed to be delivered to a pipeline and what was actually produced and delivered, the Company accrues the difference as an imbalance.
 
Allowance for Uncollectible Accounts
 
The allowance for uncollectible accounts is the Company's best estimate of the amount of probable credit losses in the existing accounts receivable. The allowance is determined based on historical experience, the age and other specific information about customer accounts. Account balances are charged off against the allowance twelve months after the account is final billed or when it is anticipated that the receivable will not be recovered.
 
Regulatory Mechanisms
 
The Company's rate schedules in the Utility segment contain clauses that permit adjustment of revenues to reflect price changes from the cost of purchased gas included in base rates. Differences between amounts currently recoverable and actual adjustment clause revenues, as well as other price changes and pipeline and storage company refunds not yet includable in adjustment clause rates, are deferred and accounted for as either unrecovered purchased gas costs or amounts payable to customers. Such amounts are generally recovered from (or passed back to) customers during the following fiscal year.
 
Estimated refund liabilities to ratepayers represent management's current estimate of such refunds. Reference is made to Note C — Regulatory Matters for further discussion.
 
The impact of weather on revenues in the Utility segment's New York rate jurisdiction is tempered by a WNC, which covers the eight-month period from October through May. The WNC is designed to adjust the rates of retail customers to reflect the impact of deviations from normal weather. Weather that is warmer than normal results in a surcharge being added to customers' current bills, while weather that is colder than normal results in a refund being credited to customers' current bills. Since the Utility segment's Pennsylvania rate jurisdiction does not have a WNC, weather variations have a direct impact on the Pennsylvania rate jurisdiction's revenues.
 
The impact of weather normalized usage per customer account in the Utility segment's New York rate jurisdiction is tempered by a revenue decoupling mechanism. The effect of the revenue decoupling mechanism is to render the Company financially indifferent to throughput decreases resulting from conservation. Weather normalized usage per account that exceeds the average weather normalized usage per customer account results in a refund being credited to customers' bills. Weather normalized usage per account that is below the average weather normalized usage per account results in a surcharge being added to customers' bills. The surcharge or credit is calculated over a twelve-month period ending December 31st, and applied to customer bills annually, beginning March 1st.
 
In the Pipeline and Storage segment, the allowed rates that Supply Corporation bills its customers are based on a straight fixed-variable rate design, which allows recovery of all fixed costs, including return on equity and income taxes, through fixed monthly reservation charges. Because of this rate design, changes in throughput due to weather variations do not have a significant impact on the revenues of Supply Corporation.
 
Prior to December 10, 2008, the allowed rates that Empire billed its customers were based on a modified fixed-variable rate design, which recovered return on equity and income taxes through variable charges. Because of this rate design, changes in throughput due to weather variations could have had a significant impact on Empire's revenues. On December 10, 2008, Empire became FERC regulated. As a result, Empire now bills its customers based on a straight fixed-variable rate design. Changes in throughput due to weather variations no longer have a significant impact on Empire's revenue.
 
Property, Plant and Equipment
 
The principal assets of the Utility and Pipeline and Storage segments, consisting primarily of gas plant in service, are recorded at the historical cost when originally devoted to service in the regulated businesses, as required by regulatory authorities.
 
In the Company's Exploration and Production segment, oil and gas property acquisition, exploration and development costs are capitalized under the full cost method of accounting. Under this methodology, all costs associated with property acquisition, exploration and development activities are capitalized, including internal costs directly identified with acquisition, exploration and development activities. The internal costs that are capitalized do not include any costs related to production, general corporate overhead, or similar activities. The Company does not recognize any gain or loss on the sale or other disposition of oil and gas properties unless the gain or loss would significantly alter the relationship between capitalized costs and proved reserves of oil and gas attributable to a cost center.
 
Capitalized costs include costs related to unproved properties, which are excluded from amortization until proved reserves are found or it is determined that the unproved properties are impaired. All costs related to unproved properties are reviewed quarterly to determine if impairment has occurred. The amount of any impairment is transferred to the pool of capitalized costs being amortized.
 
Capitalized costs are subject to the SEC full cost ceiling test. The ceiling test, which is performed each quarter, determines a limit, or ceiling, on the amount of property acquisition, exploration and development costs that can be capitalized. The ceiling under this test represents (a) the present value of estimated future net 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 September 30, 2010) 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 capitalized costs, net of accumulated depreciation, depletion and amortization and related deferred income taxes, exceed the ceiling at the end of any quarter, a permanent impairment is required to be charged to earnings in that quarter. In adjusting estimated future net cash flows for hedging under the ceiling test at September 30, 2010, 2009, and 2008, estimated future net cash flows were increased by $65.4 million, $143.3 million and $34.5 million, respectively. The Company's capitalized costs exceeded the full cost ceiling for the Company's oil and gas properties at December 31, 2008. As such, the Company recognized a pre-tax impairment of $182.8 million at December 31, 2008 (utilizing period end pricing as required by the SEC full cost rules then in effect). Deferred income taxes of $74.6 million were recorded associated with this impairment.
 
Maintenance and repairs of property and replacements of minor items of property are charged directly to maintenance expense. The original cost of the regulated subsidiaries' property, plant and equipment retired, and the cost of removal less salvage, are charged to accumulated depreciation.
 
Depreciation, Depletion and Amortization
 
For oil and gas properties, depreciation, depletion and amortization is computed based on quantities produced in relation to proved reserves using the units of production method. The cost of unproved oil and gas properties is excluded from this computation. In the All Other category, for timber properties, depletion, determined on a property by property basis, is charged to operations based on the actual amount of timber cut in relation to the total amount of recoverable timber. For all other property, plant and equipment, depreciation, depletion and amortization is computed using the straight-line method in amounts sufficient to recover costs over the estimated service lives of property in service. The following is a summary of depreciable plant by segment:
 
                 
    As of September 30  
    2010     2009  
    (Thousands)  
 
Utility
  $ 1,657,686     $ 1,616,908  
Pipeline and Storage
    1,241,179       1,196,937  
Exploration and Production
    2,294,235       1,972,353  
Energy Marketing
    1,634       1,241  
All Other and Corporate
    127,939       154,512  
                 
    $ 5,322,673     $ 4,941,951  
                 


 

Average depreciation, depletion and amortization rates are as follows:
 
                         
    Year Ended September 30  
    2010     2009     2008  
 
Utility
    2.6 %     2.6 %     2.6 %
Pipeline and Storage
    3.0 %     3.0 %     3.2 %
Exploration and Production, per Mcfe(1)
  $ 2.14     $ 2.14     $ 2.26  
Energy Marketing
    2.9 %     3.4 %     3.5 %
All Other and Corporate
    6.6 %     5.2 %     4.3 %
 
 
(1) Amounts include depletion of oil and gas producing properties as well as depreciation of fixed assets. As disclosed in Note Q — Supplementary Information for Oil and Gas Producing Properties, depletion of oil and gas producing properties amounted to $2.10, $2.10 and $2.23 per Mcfe of production in 2010, 2009 and 2008, respectively.
 
Goodwill
 
The Company has recognized goodwill of $5.5 million as of September 30, 2010, 2009 and 2008 on its Consolidated Balance Sheets related to the Company's acquisition of Empire in 2003. The Company accounts for goodwill in accordance with the current authoritative guidance, which requires the Company to test goodwill for impairment annually. At September 30, 2010, 2009 and 2008, the fair value of Empire was greater than its book value. As such, the goodwill was not considered impaired at those dates. Going back to the origination of the goodwill in 2003, the Company has never recorded an impairment of its goodwill balance.
 
Financial Instruments
 
Unrealized gains or losses from the Company's investments in an equity mutual fund and the stock of an insurance company (securities available for sale) are recorded as a component of accumulated other comprehensive income (loss). Reference is made to Note G — Financial Instruments for further discussion.
 
The Company uses a variety of derivative financial instruments to manage a portion of the market risk associated with fluctuations in the price of natural gas and crude oil. These instruments include price swap agreements and futures contracts. The Company accounts for these instruments as either cash flow hedges or fair value hedges. In both cases, the fair value of the instrument is recognized on the Consolidated Balance Sheets as either an asset or a liability labeled Fair Value of Derivative Financial Instruments. Reference is made to Note F — Fair Value Measurements for further discussion concerning the fair value of derivative financial instruments.
 
For effective cash flow hedges, the offset to the asset or liability that is recorded is a gain or loss recorded in accumulated other comprehensive income (loss) on the Consolidated Balance Sheets. The gain or loss recorded in accumulated other comprehensive income (loss) remains there until the hedged transaction occurs, at which point the gains or losses are reclassified to operating revenues or purchased gas expense on the Consolidated Statements of Income. Any ineffectiveness associated with the cash flow hedges is recorded in the Consolidated Statements of Income. The Company did not experience any material ineffectiveness with regard to its cash flow hedges during 2010, 2009 or 2008.
 
For fair value hedges, the offset to the asset or liability that is recorded is a gain or loss recorded to operating revenues or purchased gas expense on the Consolidated Statements of Income. However, in the case of fair value hedges, the Company also records an asset or liability on the Consolidated Balance Sheets representing the change in fair value of the asset or firm commitment that is being hedged (see Other Current Assets section in this footnote). The offset to this asset or liability is a gain or loss recorded to operating revenues or purchased gas expense on the Consolidated Statements of Income as well. If the fair value hedge is effective, the gain or loss from the derivative financial instrument is offset by the gain or loss that arises from the change in fair value of the asset or firm commitment that is being hedged. The Company did not experience any material ineffectiveness with regard to its fair value hedges during 2010, 2009 or 2008.
 
 Accumulated Other Comprehensive Income (Loss)
 
The components of Accumulated Other Comprehensive Income (Loss) are as follows:
 
                 
    Year Ended September 30  
    2010     2009  
    (Thousands)  
 
Funded Status of the Pension and Other Post-Retirement Benefit Plans
  $ (79,465 )   $ (63,802 )
Cumulative Foreign Currency Translation Adjustment
    (51 )     (104 )
Net Unrealized Gain on Derivative Financial Instruments
    32,876       18,491  
Net Unrealized Gain on Securities Available for Sale
    1,655       3,019  
                 
Accumulated Other Comprehensive Loss
  $ (44,985 )   $ (42,396 )
                 
 
At September 30, 2010, it is estimated that of the $32.9 million net unrealized gain on derivative financial instruments shown in the table above, $23.6 million of unrealized gains will be reclassified into the Consolidated Statement of Income during 2011. The remaining unrealized gains on derivative financial instruments of $9.3 million will be reclassified into the Consolidated Statement of Income in subsequent years. The Company's derivative financial instruments extend out to 2014.
 
The amounts included in accumulated other comprehensive income (loss) related to the funded status of the Company's pension and other post-retirement benefit plans consist of prior service costs and accumulated losses. The total amount for prior service costs was $0.3 million at September 30, 2010 and 2009. The total amount for accumulated losses was $79.2 million and $63.5 million at September 30, 2010 and 2009, respectively.
 
Gas Stored Underground — Current
 
In the Utility segment, gas stored underground — current in the amount of $24.9 million is carried at lower of cost or market, on a LIFO method. Based upon the average price of spot market gas purchased in September 2010, including transportation costs, the current cost of replacing this inventory of gas stored underground — current exceeded the amount stated on a LIFO basis by approximately $82.5 million at September 30, 2010. All other gas stored underground — current, which is in the Energy Marketing segment, is carried at an average cost method, subject to lower of cost or market adjustments.
 
Purchased Timber Cutting Rights
 
In September 2010, the Company sold all of its purchased timber cutting rights in connection with the sale of its sawmill in Marienville, Pennsylvania. The Company continues to maintain a forestry operation, but will no longer be processing lumber products. Prior to the sale, the Company purchased the right to harvest timber from land owned by other parties. These rights, which extended from several months to several years, were purchased to ensure an adequate supply of timber for the Company's sawmill and kiln operations. The historical value of timber rights expected to be harvested during the following year were included in Materials and Supplies on the Consolidated Balance Sheets while the historical value of timber rights expected to be harvested beyond one year were included in Other Assets on the Consolidated Balance Sheets. The components of the Company's purchased timber cutting rights are as follows:

 
 
                 
    Year Ended September 30  
    2010     2009  
    (Thousands)  
 
Materials and Supplies
  $     $ 6,349  
Other Assets
          6,343  
                 
    $     $ 12,692  
                 
 
Unamortized Debt Expense
 
Costs associated with the issuance of debt by the Company are deferred and amortized over the lives of the related debt. Costs associated with the reacquisition of debt related to rate-regulated subsidiaries are deferred and amortized over the remaining life of the issue or the life of the replacement debt in order to match regulatory treatment.
 
Foreign Currency Translation
 
The functional currency for the Company's foreign operations is the local currency of the country where the operations are located. Asset and liability accounts are translated at the rate of exchange on the balance sheet date. Revenues and expenses are translated at the average exchange rate during the period. Foreign currency translation adjustments are recorded as a component of accumulated other comprehensive income (loss). With the sale of SECI on August 31, 2007, the Company eliminated its major foreign operation. While the Company is in the process of winding up or selling certain power development projects in Europe, the investment in such projects is not significant and the Company does not expect to have any significant foreign currency translation adjustments in the future.
 
Income Taxes
 
The Company and its domestic subsidiaries file a consolidated federal income tax return. Investment tax credit, prior to its repeal in 1986, was deferred and is being amortized over the estimated useful lives of the related property, as required by regulatory authorities having jurisdiction.
 
Consolidated Statements of Cash Flows
 
For purposes of the Consolidated Statements of Cash Flows, the Company considers all highly liquid debt instruments purchased with a maturity of three months or less to be cash equivalents.
 
At September 30, 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.
 
At September 30, 2009, the Company accrued $9.1 million of capital expenditures in the Exploration and Production segment, the majority of which was in the Appalachian region. The Company also accrued $0.7 million of capital expenditures in the All Other category related to the construction of the Midstream Covington Gathering System at September 30, 2009. These amounts were excluded from the Consolidated Statement of Cash Flows at September 30, 2009 since they represent non-cash investing activities at that date. 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 year ended September 30, 2010.
 
At September 30, 2008, the Company accrued $16.8 million of capital expenditures related to the construction of the Empire Connector project. This amount was excluded from the Consolidated Statement of Cash Flows at September 30, 2008 since it represented a non-cash investing activity at that date. These capital expenditures were paid during the quarter ended December 31, 2008 and have been included in the Consolidated Statement of Cash Flows for the year ended September 30, 2009.
 
Hedging Collateral Account
 
This is an account title for cash held in margin accounts funded by the Company to serve as collateral for hedging positions. 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. At September 30, 2009, the Company had hedging collateral deposits of $0.8 million related to its exchange-traded futures contracts. In accordance with its accounting policy, the Company does not offset hedging collateral deposits paid or received against related derivative financial instrument liability or asset balances.
 
Cash Held in Escrow
 
On July 20, 2009, the Company's wholly-owned subsidiary in the Exploration and Production segment, Seneca, acquired Ivanhoe Energy's United States oil and gas operations for approximately $39.2 million in cash (including cash acquired of $4.3 million). The cash acquired at acquisition includes $2 million held in escrow at September 30, 2010 and 2009. Seneca placed this amount in escrow as part of the purchase price. Currently, the Company and Ivanhoe Energy are negotiating a final resolution to the issue of whether Ivanhoe Energy is entitled to some or all of the amount held in escrow.
 
On August 31, 2007, the Company received approximately $232.1 million of proceeds from the sale of SECI, of which $58.0 million was placed in escrow pending receipt of a tax clearance certificate from the Canadian government. The escrow account was a Canadian dollar denominated account. On a U.S. dollar basis, the value of this account was $62.0 million at September 30, 2007. In December 2007, the Canadian government issued the tax clearance certificate, thereby releasing the proceeds from restriction as of December 31, 2007. To hedge against foreign currency exchange risk related to the cash being held in escrow, the Company held a forward contract to sell Canadian dollars. For presentation purposes on the Consolidated Statement of Cash Flows, for the year ended September 30, 2008, the Cash Held in Escrow line item within Investing Activities reflects the net proceeds to the Company (received on January 8, 2008) after adjusting for the impact of the foreign currency hedge.
 
Other Current Assets
 
The components of the Company's Other Current Assets are as follows:
 
                 
    Year Ended September 30  
    2010     2009  
    (Thousands)  
 
Prepayments
  $ 13,884     $ 12,096  
Prepaid Property and Other Taxes
    12,413       12,059  
Federal Income Taxes Receivable
    56,334       23,325  
State Income Taxes Receivable
    18,007       13,469  
Fair Values of Firm Commitments
    15,331       7,525  
                 
    $ 115,969     $ 68,474  
                 
 
 
Customer Advances
 
The Company's Utility and Energy Marketing segments have balanced billing programs whereby customers pay their estimated annual usage in equal installments over a twelve-month period. Monthly payments under the balanced billing programs are typically higher than current month usage during the summer months. During the winter months, monthly payments under the balanced billing programs are typically lower than current month usage. At September 30, 2010 and 2009, customers in the balanced billing programs had advanced excess funds of $27.6 million and $24.6 million, respectively.
 
Customer Security Deposits
 
The Company, in its Utility, Pipeline and Storage, and Energy Marketing segments, often times requires security deposits from marketers, producers, pipeline companies, and commercial and industrial customers before providing services to such customers. At September 30, 2010 and 2009, the Company had received customer security deposits amounting to $18.3 million and $17.4 million, respectively.
 
Earnings Per Common Share
 
Basic earnings per common share is computed by dividing income available for common stock by the weighted average number of common shares outstanding for the period. Diluted earnings per common share reflects the potential dilution that could occur if securities or other contracts to issue common stock were exercised or converted into common stock. For purposes of determining earnings per common share, the only potentially dilutive securities the Company has outstanding are stock options and SARs. The diluted weighted average shares outstanding shown on the Consolidated Statements of Income reflects the potential dilution as a result of these stock options and SARs as determined using the Treasury Stock Method. Stock options and SARs that are antidilutive are excluded from the calculation of diluted earnings per common share. For 2010, there were 314,910 SARs excluded as being antidilutive, and there were no stock options excluded as being antidilutive. For 2009, there were 365,000 SARs and 765,000 stock options excluded as being antidilutive. For 2008, there were 7,344 SARs excluded as being antidilutive, and there were no stock options excluded as being antidilutive.
 
Share Repurchases
 
The Company considers all shares repurchased as cancelled shares restored to the status of authorized but unissued shares, in accordance with New Jersey law. The repurchases are accounted for on the date the share repurchase is settled as an adjustment to common stock (at par value) with the excess repurchase price allocated between paid in capital and retained earnings. Refer to Note E — Capitalization and Short-Term Borrowings for further discussion of the share repurchase program.
 
Stock-Based Compensation
 
The Company has various stock option and stock award plans which provide or provided for the issuance of one or more of the following to key employees: incentive stock options, nonqualified stock options, SARs, restricted stock, restricted stock units, performance units or performance shares. Stock options and SARs under all plans have exercise prices equal to the average market price of Company common stock on the date of grant, and generally no stock option or SAR is exercisable less than one year or more than ten years after the date of each grant. Restricted stock is subject to restrictions on vesting and transferability. Restricted stock awards entitle the participants to full dividend and voting rights. Certificates for shares of restricted stock awarded under the Company's stock option and stock award plans are held by the Company during the periods in which the restrictions on vesting are effective. Restrictions on restricted stock awards generally lapse ratably over a period of not more than ten years after the date of each grant.
 
The Company follows authoritative guidance which requires the measurement and recognition of compensation cost at fair value for all share-based payments, including stock options and SARs. The Company has chosen the Black-Scholes-Merton closed form model to calculate the compensation expense associated with such share-based payments since it is easier to administer than the Binomial option-pricing model. Furthermore, since the Company does not have complex stock-based compensation awards, it does not believe that compensation expense would be materially different under either model.
 
The Company granted 520,500, 610,000 and 321,000 performance based SARs during the years ended September 30, 2010, 2009 and 2008, respectively. The Company did not grant any stock options or non-performance based SARs during the years ended September 30, 2010, 2009 and 2008. The accounting treatment for performance based and non-performance based SARs is the same as the accounting for stock options under the current authoritative guidance for stock-based compensation. The performance based SARs granted for the years ended September 30, 2010 and 2009 vest and become exercisable annually in one-third increments, provided that a performance condition is met. The performance condition for each fiscal year, generally stated, is an increase over the prior fiscal year of at least five percent in certain oil and natural gas production of the Exploration and Production segment. The performance based SARs granted for the year ended September 30, 2008 vest and become exercisable annually, in one-third increments, provided that a performance condition for diluted earnings per share is met for the prior fiscal year. The weighted average grant date fair value of the performance based SARs granted during 2010, 2009 and 2008 was estimated on the date of grant using the same accounting treatment that is applied for stock options, and assumes that the performance conditions specified will be achieved. If such conditions are not met or it is not considered probable that such conditions will be met, no compensation expense is recognized and any previously recognized compensation expense is reversed. During 2009, the Company reversed $0.5 million of previously recognized compensation expense associated with performance based SARs. The Company also granted 4,000, 63,000, and 25,000 restricted share awards (non-vested stock as defined by the current accounting literature) during the years ended September 30, 2010, 2009 and 2008, respectively.
 
Stock-based compensation expense for the years ended September 30, 2010, 2009 and 2008 was approximately $4.4 million, $2.1 million (net of the $0.5 million reversal of compensation expense discussed above), and $2.3 million, respectively. Stock-based compensation expense is included in operation and maintenance expense on the Consolidated Statement of Income. The total income tax benefit related to stock-based compensation expense during the years ended September 30, 2010, 2009 and 2008 was approximately $1.8 million, $0.8 million and $0.9 million, respectively. There were no capitalized stock-based compensation costs during the years ended September 30, 2010, 2009 and 2008.
 
Stock Options
 
The total intrinsic value of stock options exercised during the years ended September 30, 2010, 2009 and 2008 totaled approximately $53.6 million, $18.7 million, and $24.6 million, respectively. For 2010, 2009 and 2008, the amount of cash received by the Company from the exercise of such stock options was approximately $34.5 million, $29.2 million, and $18.5 million, respectively.
 
The Company realizes tax benefits related to the exercise of stock options on a calendar year basis as opposed to a fiscal year basis. As such, for stock options exercised during the quarters ended December 31, 2009, 2008, and 2007, the Company realized a tax benefit of $8.0 million, $1.6 million, and $4.4 million, respectively. For stock options exercised during the period of January 1, 2010 through September 30, 2010, the Company will realize a tax benefit of approximately $13.3 million in the quarter ended December 31, 2010. For stock options exercised during the period of January 1, 2009 through September 30, 2009, the Company realized a tax benefit of approximately $5.7 million in the quarter ended December 31, 2009. For stock options exercised during the period of January 1, 2008 through September 30, 2008, the Company realized a tax benefit of approximately $4.3 million in the quarter ended December 31, 2008. As stated above, there were no stock options granted during the years ended September 30, 2010, 2009 and 2008. For the years ended September 30, 2010, 2009 and 2008, 100,000, 27,000 and 358,000 stock options became fully vested, respectively. The total fair value of the stock options that became vested during the years ended September 30, 2010, 2009 and 2008 was approximately $0.7 million, $0.2 million and $2.6 million, respectively. As of September 30, 2010, there was no unrecognized compensation expense related to stock options. For a summary of transactions during 2010 involving option shares for all plans, refer to Note E — Capitalization and Short-Term Borrowings.
 
Non-Performance Based SARs
 
Participants in the stock option and award plans did not exercise any non-performance based SARs during the years ended September 30, 2010, 2009 and 2008. As stated above, the Company did not grant any non-performance based SARs during the years ended September 30, 2010, 2009 and 2008. For the year ended September 30, 2010, 50,000 non-performance based SARs became fully vested. Fiscal 2010 was the first year in which non-performance based SARs became vested. The total fair value of the non-performance based SARs that became vested during the year ended September 30, 2010 was approximately $0.4 million. As of September 30, 2010, there was no unrecognized compensation expense related to non-performance based SARs. For a summary of transactions during 2010 involving non-performance based SARs for all plans, refer to Note E — Capitalization and Short-Term Borrowings.
 
Performance Based SARs
 
Participants in the stock option and award plans did not exercise any performance based SARs during the years ended September 30, 2010, 2009 and 2008. As stated above, there were 520,500, 610,000 and 321,000 performance based SARs granted during the years ended September 30, 2010, 2009 and 2008, respectively. The weighted average grant date fair value of performance based SARs granted in 2010, 2009 and 2008 is $12.06 per share, $4.09 per share and $9.06 per share, respectively. For the years ended September 30, 2010 and 2009, 203,324 and 96,984 performance based SARs became fully vested. Fiscal 2009 was the first year in which performance based SARs became vested. The total fair value of the performance based SARs that became vested during each of the years ended September 30, 2010 and 2009 was approximately $0.8 million. As of September 30, 2010, unrecognized compensation expense related to performance based SARs totaled approximately $4.0 million, which will be recognized over a weighted average period of 10.3 months. For a summary of transactions during 2010 involving performance based SARs for all plans, refer to Note E — Capitalization and Short-Term Borrowings.
 
The fair value of performance based SARs at the date of grant was estimated using the Black-Scholes-Merton closed form model. The following weighted average assumptions were used in estimating the fair value of performance based SARs at the date of grant:
 
                         
    Year Ended September 30  
    2010     2009     2008  
 
Risk Free Interest Rate
    3.55 %     2.56 %     3.78 %
Expected Life (Years)
    7.75       7.50       7.25  
Expected Volatility
    23.25 %     22.16 %     17.69 %
Expected Dividend Yield (Quarterly)
    0.64 %     1.09 %     0.64 %
 
The risk-free interest rate is based on the yield of a Treasury Note with a remaining term commensurate with the expected term of the performance based SARs. The expected life and expected volatility are based on historical experience.
 
For grants during the years ended September 30, 2010, 2009 and 2008, it was assumed that there would be no forfeitures, based on the vesting term and the number of grantees.
 
Restricted Share Awards
 
The weighted average fair value of restricted share awards granted in 2010, 2009 and 2008 is $52.10 per share, $47.46 per share and $48.41 per share, respectively. As of September 30, 2010, unrecognized compensation expense related to restricted share awards totaled approximately $3.4 million, which will be recognized over a weighted average period of 4.0 years. For a summary of transactions during 2010 involving restricted share awards, refer to Note E — Capitalization and Short-Term Borrowings.
 
New Authoritative Accounting and Financial Reporting Guidance
 
In September 2006, the FASB issued authoritative guidance for using fair value to measure assets and liabilities. This guidance serves to clarify the extent to which companies measure assets and liabilities at fair value, the information used to measure fair value, and the effect that fair-value measurements have on earnings. This guidance is to be applied whenever assets or liabilities are to be measured at fair value. On October 1, 2008, the Company adopted this guidance for financial assets and financial liabilities that are recognized or disclosed at fair value on a recurring basis. The FASB's authoritative guidance for using fair value to measure nonfinancial assets and nonfinancial liabilities on a nonrecurring basis became effective during the quarter ended December 31, 2009. The Company's nonfinancial assets and nonfinancial liabilities were not significantly impacted by this guidance during the year ended September 30, 2010. The Company had identified Goodwill as being the major nonfinancial asset that may have been impacted by the adoption of this guidance; however, the adoption of the guidance did not have a significant impact on the Company's annual test for goodwill impairment. The Company had identified Asset Retirement Obligations as a nonfinancial liability that may have been impacted by the adoption of the guidance. The adoption of the guidance did not have a significant impact on the Company's Asset Retirement Obligations. Refer to Note B — Asset Retirement Obligations for further disclosure. Additionally, in February 2010, the FASB issued updated guidance that includes additional requirements and disclosures regarding fair value measurements. The guidance now requires the gross presentation of activity within the Level 3 roll forward and requires disclosure of details on transfers in and out of Level 1 and 2 fair value measurements. It also provides further clarification on the level of disaggregation of fair value measurements and disclosures on inputs and valuation techniques. The Company has updated its disclosures to reflect the new requirements in Note F — Fair Value Measurements, except for the Level 3 roll forward gross presentation, which will be effective as of the Company's first quarter of fiscal 2012.
 
On December 31, 2008, the SEC issued a final rule on Modernization of Oil and Gas Reporting. The final rule modifies the SEC's reporting and disclosure rules for oil and gas reserves and aligns the full cost accounting rules with the revised disclosures. The most notable changes of the final rule include the replacement of the single day period-end pricing used to value oil and gas reserves with 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 final rule also permits voluntary disclosure of probable and possible reserves, a disclosure previously prohibited by SEC rules. Additionally, on January 6, 2010, the FASB amended the oil and gas accounting standards to conform to the SEC final rule on Modernization of Oil and Gas Reporting (final rule). The revised reporting and disclosure requirements became effective with this Form 10-K for the period ended September 30, 2010. The Company has updated its disclosures to reflect the new requirements in Note Q — Supplementary Information for Oil and Gas Producing Activities. The Company chose not to disclose probable and possible reserves. In order to estimate the effect of adopting the final rule, the Company would be required to prepare two sets of reserve reports (applying both the final rule and previous rules). There would be significant time and expense associated with preparing two sets of reports to address changes between the different rules. Since the information obtained from the dual reserve reports would be relevant only for transitional purposes, the cost is deemed to exceed the benefit. As a result, the Company has determined it would be impractical to estimate the impact of adoption of the final rule.
 
In March 2009, the FASB issued authoritative guidance that expands the disclosures required in an employer's financial statements about pension and other post-retirement benefit plan assets. The additional disclosures include more details on how investment allocation decisions are made, the plan's investment policies and strategies, the major categories of plan assets, the inputs and valuation techniques used to measure the fair value of plan assets, the effect of fair value measurements using significant unobservable inputs on changes in plan assets for the period, and disclosure regarding significant concentrations of risk within plan assets. The additional disclosure requirements became effective with this Form 10-K for the period ended September 30, 2010. The Company has updated its disclosures to reflect the new requirements in Note H — Retirement Plan and Other Post-Retirement Benefits.
 
In June 2009, the FASB issued amended authoritative guidance to improve and clarify financial reporting requirements by companies involved with variable interest entities. The new guidance requires a company to perform an analysis to determine whether the company's variable interest or interests give it a controlling financial interest in a variable interest entity. The analysis also assists in identifying the primary beneficiary of a variable interest entity. This authoritative guidance will be effective as of the Company's first quarter of fiscal 2011. Given the current organizational structure of the Company, the Company does not believe this authoritative guidance will have any impact on its consolidated financial statements.
Asset Retirement Obligations
Asset Retirement Obligations
Note B — Asset Retirement Obligations
 
The Company accounts for asset retirement obligations in accordance with the authoritative guidance that requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred. An asset retirement obligation is defined as a legal obligation associated with the retirement of a tangible long-lived asset in which the timing and/or method of settlement may or may not be conditional on a future event that may or may not be within the control of the Company. When the liability is initially recorded, the entity capitalizes the estimated cost of retiring the asset as part of the carrying amount of the related long-lived asset. Over time, the liability is adjusted to its present value each period and the capitalized cost is depreciated over the useful life of the related asset. The Company estimates the fair value of its asset retirement obligations based on the discounting of expected cash flows using various estimates, assumptions and judgments regarding certain factors such as the existence of a legal obligation for an asset retirement obligation; estimated amounts and timing of settlements; the credit-adjusted risk-free rate to be used; and inflation rates. Asset retirement obligations incurred in the current period were Level 3 fair value measurements as the inputs used to measure the fair value are unobservable.
 
As previously disclosed, the Company follows the full cost method of accounting for its exploration and production costs. In accordance with the current authoritative guidance for asset retirement obligations, the Company has recorded an asset retirement obligation representing plugging and abandonment costs associated with the Exploration and Production segment's crude oil and natural gas wells and has capitalized such costs in property, plant and equipment (i.e. the full cost pool). Under the current authoritative guidance for asset retirement obligations, since plugging and abandonment costs are already included in the full cost pool, the units-of-production depletion calculation excludes from the depletion base any estimate of future plugging and abandonment costs that are already recorded in the full cost pool.
 
The full cost method of accounting provides a limit to the amount of costs that can be capitalized in the full cost pool. This limit is referred to as the full cost ceiling. In accordance with current authoritative guidance, since the full cost pool includes an amount associated with plugging and abandoning the wells, as discussed in the preceding paragraph, the calculation of the full cost ceiling no longer reduces the future net cash flows from proved oil and gas reserves by an estimate of plugging and abandonment costs.
 
In addition to the asset retirement obligation recorded in the Exploration and Production segment, the Company has recorded future asset retirement obligations associated with the plugging and abandonment of natural gas storage wells in the Pipeline and Storage segment and the removal of asbestos and asbestos-containing material in various facilities in the Utility and Pipeline and Storage segments. The Company has also recorded asset retirement obligations for certain costs connected with the retirement of the distribution mains and services components of the pipeline system in the Utility segment and with the transmission mains and other components in the pipeline system in the Pipeline and Storage segment. These retirement costs within the distribution and transmission systems are primarily for the capping and purging of pipe, which are generally abandoned in place when retired, as well as for the clean-up of PCB contamination associated with the removal of certain pipe.
 
A reconciliation of the Company's asset retirement obligation is shown below:
 
                         
    Year Ended September 30  
    2010     2009     2008  
          (Thousands)        
 
Balance at Beginning of Year
  $ 91,373     $ 93,247     $ 75,939  
Liabilities Incurred and Revisions of Estimates
    16,140       4,492       18,739  
Liabilities Settled
    (12,622 )     (13,155 )     (6,871 )
Accretion Expense
    6,727       6,789       5,440  
                         
Balance at End of Year
  $ 101,618     $ 91,373     $ 93,247  
Regulatory Matters
Regulatory Matters
Note C — Regulatory Matters
 
Regulatory Assets and Liabilities
 
The Company has recorded the following regulatory assets and liabilities:
 
                 
    At September 30  
    2010     2009  
    (Thousands)  
 
Regulatory Assets(1):
               
Pension Costs(2) (Note H)
  $ 308,822     $ 262,370  
Post-Retirement Benefit Costs(2) (Note H)
    159,498       198,982  
Recoverable Future Taxes (Note D)
    149,712       138,435  
Environmental Site Remediation Costs(2) (Note I)
    20,491       21,456  
NYPSC Assessment(2)
    19,229       24,445  
Asset Retirement Obligations(2) (Note B)
    12,529       7,884  
Unamortized Debt Expense (Note A)
    5,727       6,610  
Other(2)
    22,232       15,776  
                 
Total Regulatory Assets
    698,240       675,958  
                 
Regulatory Liabilities:
               
Cost of Removal Regulatory Liability
    124,032       105,546  
Taxes Refundable to Customers (Note D)
    69,585       67,046  
Post-Retirement Benefit Costs(3) (Note H)
    42,461       45,594  
Amounts Payable to Customers (See Regulatory Mechanisms in Note A)
    38,109       105,778  
Pension Costs(3) (Note H)
    16,171       15,409  
Off-System Sales and Capacity Release Credits(3)
    11,594       8,340  
Tax Benefit on Medicare Part D Subsidy(3)
    4,842       28,817  
Deferred Insurance Proceeds(3)
    2,445       3,804  
Other(3)
    11,821       18,265  
                 
Total Regulatory Liabilities
    321,060       398,599  
                 
Net Regulatory Position
  $ 377,180     $ 277,359  
                 

 

 
(1) The Company recovers the cost of its regulatory assets but generally does not earn a return on them. There are a few exceptions to this rule. For example, the Company does earn a return on Unrecovered Purchased Gas Costs and, in the New York jurisdiction of its Utility segment, earns a return, within certain parameters, on the excess of cumulative funding to the pension plan over the cumulative amount collected in rates.
 
(2) Included in Other Regulatory Assets on the Consolidated Balance Sheets.
 
(3) Included in Other Regulatory Liabilities on the Consolidated Balance Sheets.
 
If for any reason the Company ceases to meet the criteria for application of regulatory accounting treatment for all or part of its operations, the regulatory assets and liabilities related to those portions ceasing to meet such criteria would be eliminated from the Consolidated Balance Sheets and included in income of the period in which the discontinuance of regulatory accounting treatment occurs. Such amounts would be classified as an extraordinary item.
 
Cost of Removal Regulatory Liability
 
In the Company's Utility and Pipeline and Storage segments, costs of removing assets (i.e. asset retirement costs) are collected from customers through depreciation expense. These amounts are not a legal retirement obligation as discussed in Note B — Asset Retirement Obligations. Rather, they are classified as a regulatory liability in recognition of the fact that the Company has collected dollars from the customer that will be used in the future to fund asset retirement costs.
 
Tax Benefit on Medicare Part D Subsidy
 
The Company has established a regulatory liability for the tax benefit it will receive under the Medicare Prescription Drug, Improvement, and Modernization Act of 2003 (the Act) amounting to $4.8 million and $28.8 million at September 30, 2010 and 2009, respectively. The Act provides a federal subsidy to sponsors of retiree health care benefit plans that provide a benefit that is at least actuarially equivalent to Medicare Part D. The Company reduced its deferred tax asset relating to the Medicare Part D subsidy by $27.5 million to reflect changes made by the fundamental health care reform legislation enacted on March 23, 2010. In conjunction with the reduction of the deferred tax asset, the Company reduced its Medicare Part D regulatory liability by $27.5 million. In the Company's Utility and Pipeline and Storage segments, the Company's post-retirement benefit plans are funded by a component of tariff rates charged to customers. As such, prior to the fundamental health care reform legislation, the $27.5 million tax benefit had been recorded as a regulatory liability in anticipation of flowing that tax benefit back to customers through adjusted tariff rates. Refer to Note H — Retirement Plan and Other Post-Retirement Benefits for further discussion of the Act and its impact on the Company.
 
Deferred Insurance Proceeds
 
The Company, in its Pipeline and Storage segment, has deferred environmental insurance settlement proceeds amounting to $2.4 million and $3.8 million at September 30, 2010 and 2009, respectively. Such proceeds have been deferred as a regulatory liability to be applied against any future environmental claims that may be incurred. The proceeds have been classified as a regulatory liability in recognition of the fact that customers funded the premiums on the former insurance policies.
 
NYPSC Assessment
 
On April 7, 2009, the Governor of the State of New York signed into law an amendment to the Public Service Law increasing the allowed utility assessment from the then current rate of one-third of one percent to one percent of a utility's in-state gross operating revenue, together with a temporary surcharge (expiring March 31, 2014) equal, as applied, to an additional one percent of the utility's in-state gross operating revenue.
 
          The NYPSC, in a generic proceeding initiated for the purpose of implementing the amended law, has authorized the recovery, through rates, of the full cost of the increased assessment. The assessment is currently being applied to customer bills in the Utility segment's New York jurisdiction.
 
Off-System Sales and Capacity Release Credits
 
The Company, in its Utility segment, has entered into off-system sales and capacity release transactions. Most of the margins on such transactions are returned to the customer with only a small percentage being retained by the Company. The amount owed to the customer has been deferred as a regulatory liability.
 
Income Taxes
Income Taxes
Note D — Income Taxes
 
The components of federal, state and foreign income taxes included in the Consolidated Statements of Income are as follows:
 
                         
    Year Ended September 30  
    2010     2009     2008  
    (Thousands)  
 
Current Income Taxes —
                       
Federal
  $ 2,074     $ 43,300     $ 75,169  
State
    4,991       10,341       20,257  
Deferred Income Taxes —
                       
Federal
    110,515       (4,940 )     56,668  
State
    24,164       2,419       15,828  
                         
      141,744       51,120       167,922  
Deferred Investment Tax Credit
    (697 )     (697 )     (697 )
                         
Total Income Taxes
  $ 141,047     $ 50,423     $ 167,225  
                         
Presented as Follows:
                       
Other Income
  $ (697 )   $ (697 )   $ (697 )
Income Tax Expense — Continuing Operations
    137,227       52,859       167,672  
Discontinued Operations —
                       
Income From Operations
    493       (1,739 )     250  
Gain on Disposal
    4,024              
                         
Total Income Taxes
  $ 141,047     $ 50,423     $ 167,225  
                         
 
Total income taxes as reported differ from the amounts that were computed by applying the federal income tax rate to income before income taxes. The following is a reconciliation of this difference:
 
                         
    Year Ended September 30  
    2010     2009     2008  
    (Thousands)  
 
U.S. Income Before Income Taxes
  $ 366,960     $ 151,131     $ 435,953  
                         
Income Tax Expense, Computed at U.S. Federal Statutory Rate of 35%
  $ 128,436     $ 52,896     $ 152,584  
Increase (Reduction) in Taxes Resulting from:
                       
State Income Taxes
    18,951       8,294       23,455  
Miscellaneous
    (6,340 )     (10,767 )     (8,814 )
                         
Total Income Taxes
  $ 141,047     $ 50,423     $ 167,225  
                         


 

Significant components of the Company's deferred tax liabilities and assets are as follows:
 
                 
    At September 30  
    2010     2009  
    (Thousands)  
 
Deferred Tax Liabilities:
               
Property, Plant and Equipment
  $ 849,869     $ 733,581  
Pension and Other Post-Retirement Benefit Costs
    177,853       178,440  
Other
    63,671       54,977  
                 
Total Deferred Tax Liabilities
    1,091,393       966,998  
                 
Deferred Tax Assets:
               
Pension and Other Post-Retirement Benefit Costs
    (223,588 )     (212,299 )
Other
    (91,523 )     (144,686 )
                 
Total Deferred Tax Assets
    (315,111 )     (356,985 )
                 
Total Net Deferred Income Taxes
  $ 776,282     $ 610,013  
                 
Presented as Follows:
               
Net Deferred Tax Liability/(Asset) — Current
  $ (24,476 )   $ (53,863 )
Net Deferred Tax Liability — Non-Current
    800,758       663,876  
                 
Total Net Deferred Income Taxes
  $ 776,282     $ 610,013  
                 
 
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 and $67.0 million at September 30, 2010 and 2009, respectively. Also, regulatory assets representing future amounts collectible from customers, corresponding to additional deferred income taxes not previously recorded because of prior ratemaking practices, amounted to $149.7 million and $138.4 million at September 30, 2010 and 2009, respectively. Included in the above are regulatory liabilities and assets relating to the tax accounting method change noted below. The amounts are as follows: regulatory liabilities of $47.3 million as of September 30, 2010 and 2009, and regulatory assets of $56.3 million and $51.1 million as of September 30, 2010 and 2009, respectively.
 
The Company reduced its deferred tax asset relating to the Medicare Part D subsidy by $27.5 million to reflect changes made by the fundamental health care reform legislation enacted on March 23, 2010. In conjunction with the reduction of the deferred tax asset, the Company reduced its Medicare Part D regulatory liability by $27.5 million. In the Company's Utility and Pipeline and Storage segments, the Company's post-retirement benefit plans are funded by a component of tariff rates charged to customers. As such, prior to the fundamental health care reform legislation, the $27.5 million tax benefit had been recorded as a regulatory liability in anticipation of flowing that tax benefit back to customers through adjusted tariff rates.
 
The Company adopted the FASB authoritative guidance for income tax uncertainties on October 1, 2007. As of the date of adoption, a cumulative effect adjustment was recorded that resulted in a decrease to retained earnings of $0.4 million. Upon adoption, the unrecognized tax benefits were $1.7 million.
 
The following is a reconciliation of the change in unrecognized tax benefits:
 
                         
    Year Ended September 30  
    2010     2009     2008  
    (Thousands)  
 
Balance at Beginning of Year
  $ 8,721     $ 1,700     $ 1,700  
Additions for Tax Positions Related to Current Year
    699       8,721        
Additions for Tax Positions of Prior Years
    45              
Reductions for Tax Positions of Prior Years
    (975 )            
Settlements with Taxing Authorities
          (1,700 )      
Lapse of Statute of Limitations
                 
                         
Balance at End of Year
  $ 8,490     $ 8,721     $ 1,700  
                         
 
If the amount of unrecognized tax benefits recorded as of September 30, 2010 were recognized, there would not be a material impact on the effective tax rate. The Company anticipates that the unrecognized tax benefits will not significantly change within the next twelve months.
 
The Company recognizes interest relating to income taxes in Other Interest Expense and penalties relating to income taxes in Other Income. The Company recognized interest expense relating to income taxes of $0.2 million, $0.0 million and $0.5 million for fiscal 2010, 2009 and 2008, respectively. The Company has not accrued any penalties during fiscal 2010, 2009 and 2008.
 
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 2009 and fiscal 2010 in accordance with the Compliance Assurance Process ("CAP"). The CAP audit employs a real time review of the Company's 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 Company's application to change its tax method of accounting for certain capitalized costs relating to its utility property. During this year, local IRS examiners proposed to disallow most of the accounting method change. 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 Company's operating subsidiaries mainly operate in four states which have statutes of limitations that generally expire between three to four years from the date of filing of the income tax return.
 
As of September 30, 2010, the Company has a federal net operating loss carryover of $19.7 million, which expires in varying amounts between 2023 and 2029. Although this loss carryover is subject to certain annual limitations, no valuation allowance was recorded because of management's determination that the amount will be fully utilized during the carryforward period.
Capitalization and Short-Term Borrowings
Capitalization and Short-Term Borrowings
Note E — Capitalization and Short-Term Borrowings
 
Summary of Changes in Common Stock Equity
 
                                         
                      Earnings
    Accumulated
 
                      Reinvested
    Other
 
                Paid
    in
    Comprehensive
 
    Common Stock     In
    the
    Income
 
    Shares     Amount     Capital     Business     (Loss)  
    (Thousands, except per share amounts)  
 
Balance at September 30, 2007
    83,461     $ 83,461     $ 569,085     $ 983,776     $ (6,203 )
Net Income Available for Common Stock
                            268,728          
Dividends Declared on Common Stock ($1.27 Per Share)
                            (103,523 )        
Cumulative Effect of the Adoption of Authoritative Guidance for Income Taxes
                            (406 )        
Other Comprehensive Income, Net of Tax
                                    9,166  
Share-Based Payment Expense(2)
                    2,332                  
Common Stock Issued Under Stock and Benefit Plans(1)
    854       854       33,335                  
Share Repurchases
    (5,194 )     (5,194 )     (37,036 )     (194,776 )        
                                         
Balance at September 30, 2008
    79,121       79,121       567,716       953,799       2,963  
                                         
Net Income Available for Common Stock
                            100,708          
Dividends Declared on Common Stock ($1.32 Per Share)
                            (105,410 )        
Adoption of Authoritative Guidance for Defined Benefit Pension and Other Post-Retirement Plans
                            (804 )        
Other Comprehensive Loss, Net of Tax
                                    (45,359 )
Share-Based Payment Expense(2)
                    2,055                  
Common Stock Issued Under Stock and Benefit Plans(1)
    1,379       1,379       33,068                  
                                         
Balance at September 30, 2009
    80,500       80,500       602,839       948,293       (42,396 )
                                         
Net Income Available for Common Stock
                            225,913          
Dividends Declared on Common Stock ($1.36 Per Share)
                            (110,944 )        
Other Comprehensive Loss, Net of Tax
                                    (2,589 )
Share-Based Payment Expense(2)
                    4,435                  
Common Stock Issued Under Stock and Benefit Plans(1)
    1,575       1,575       38,345                  
                                         
Balance at September 30, 2010
    82,075     $ 82,075     $ 645,619     $ 1,063,262 (3)   $ (44,985 )
                                         
 
 
(1) Paid in Capital includes tax benefits of $13.2 million, $5.9 million and $16.3 million for September 30, 2010, 2009 and 2008, respectively, associated with the exercise of stock options.
 
(2) Paid in Capital includes compensation costs associated with stock option, SARs and/or restricted stock awards. The expense is included within Net Income Available For Common Stock, net of tax benefits.


 

(3) The availability of consolidated earnings reinvested in the business for dividends payable in cash is limited under terms of the indentures covering long-term debt. At September 30, 2010, $919.1 million of accumulated earnings was free of such limitations.
 
Common Stock
 
The Company has various plans which allow shareholders, employees and others to purchase shares of the Company common stock. The National Fuel Gas Company Direct Stock Purchase and Dividend Reinvestment Plan allows shareholders to reinvest cash dividends and make cash investments in the Company's common stock and provides investors the opportunity to acquire shares of the Company common stock without the payment of any brokerage commissions in connection with such acquisitions. The 401(k) Plans allow employees the opportunity to invest in the Company common stock, in addition to a variety of other investment alternatives. Generally, at the discretion of the Company, shares purchased under these plans are either original issue shares purchased directly from the Company or shares purchased on the open market by an independent agent.
 
During 2010, the Company issued 1,975,853 original issue shares of common stock as a result of stock option exercises and 4,000 original issue shares for restricted stock awards (non-vested stock as defined by the current accounting literature for stock-based compensation). Holders of stock options or restricted stock will often tender shares of common stock to the Company for payment of option exercise prices and/or applicable withholding taxes. During 2010, 417,987 shares of common stock were tendered to the Company for such purposes. The Company considers all shares tendered as cancelled shares restored to the status of authorized but unissued shares, in accordance with New Jersey law.
 
The Company also has a director stock program under which it issues shares of Company common stock to the non-employee directors of the Company who receive compensation under the Company's Retainer Policy for Non-Employee Directors, as partial consideration for the directors' services during the fiscal year. Under this program, the Company issued 13,689 original issue shares of common stock during 2010.
 
In December 2005, the Company's Board of Directors authorized the Company to implement a share repurchase program, whereby the Company may repurchase outstanding shares of common stock, up to an aggregate amount of eight million shares in the open market or through privately negotiated transactions. The Company completed the repurchase of the eight million shares during 2008 for a total program cost of $324.2 million (of which 4,165,122 shares were repurchased during the year ended September 30, 2008 for $191.0 million). In September 2008, the Company's Board of Directors authorized the repurchase of an additional eight million shares. Under this new authorization, the Company repurchased 1,028,981 shares for $46.0 million through September 17, 2008. The Company, however, stopped repurchasing shares after September 17, 2008 in light of the unsettled nature of the credit markets. 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. The share repurchases mentioned above were funded with cash provided by operating activities and/or through the use of the Company's lines of credit.
 
Shareholder Rights Plan
 
In 1996, the Company's Board of Directors adopted a shareholder rights plan (Plan). The Plan has been amended several times since it was adopted and is now embodied in an Amended and Restated Rights Agreement effective December 4, 2008, a copy of which was included as an exhibit to the Form 8-K filed by the Company on December 4, 2008.
 
Pursuant to the Plan, the holders of the Company's common stock have one right (Right) for each of their shares. Each Right is initially evidenced by the Company's common stock certificates representing the outstanding shares of common stock.
 
The Rights have anti-takeover effects because they will cause substantial dilution of the Company's common stock if a person attempts to acquire the Company on terms not approved by the Board of Directors (an Acquiring Person).
 
The Rights become exercisable upon the occurrence of a Distribution Date as described below, but after a Distribution Date Rights that are owned by an Acquiring Person will be null and void. At any time following a Distribution Date, each holder of a Right may exercise its right to receive, upon payment of an amount calculated under the Rights Agreement, common stock of the Company (or, under certain circumstances, other securities or assets of the Company) having a value equal to two times the amount paid to exercise the Right. However, the Rights are subject to redemption or exchange by the Company prior to their exercise as described below.
 
A Distribution Date would occur upon the earlier of (i) ten days after the public announcement that a person or group has acquired, or obtained the right to acquire, beneficial ownership of the Company's common stock or other voting stock (including Synthetic Long Positions as defined in the Plan) having 10% or more of the total voting power of the Company's common stock and other voting stock and (ii) ten days after the commencement or announcement by a person or group of an intention to make a tender or exchange offer that would result in that person acquiring, or obtaining the right to acquire, beneficial ownership of the Company's common stock or other voting stock having 10% or more of the total voting power of the Company's common stock and other voting stock.
 
In certain situations after a person or group has acquired beneficial ownership of 10% or more of the total voting power of the Company's stock as described above, each holder of a Right will have the right to exercise its Rights to receive, upon exercise of the right, common stock of the acquiring company having a value equal to two times the amount paid to exercise the right. These situations would arise if the Company is acquired in a merger or other business combination or if 50% or more of the Company's assets or earning power are sold or transferred.
 
At any time prior to the end of the business day on the tenth day following the Distribution Date, the Company may redeem the Rights in whole, but not in part, at a price of $0.005 per Right, payable in cash or stock. A decision to redeem the Rights requires the vote of 75% of the Company's full Board of Directors. Also, at any time following the Distribution Date, 75% of the Company's full Board of Directors may vote to exchange the Rights, in whole or in part, at an exchange rate of one share of common stock, or other property deemed to have the same value, per Right, subject to certain adjustments.
 
Upon exercise of the Rights, the Company may need additional regulatory approvals to satisfy the requirements of the Rights Agreement. The Rights will expire on July 31, 2018, unless earlier than that date, they are exchanged or redeemed or the Plan is amended to extend the expiration date.
 
Stock Option and Stock Award Plans
 
The Company has various stock option and stock award plans which provide or provided for the issuance of one or more of the following to key employees: incentive stock options, nonqualified stock options, SARs, restricted stock, performance units or performance shares. Stock options and SARs under all plans have exercise prices equal to the average market price of Company common stock on the date of grant, and generally no option or SAR is exercisable less than one year or more than ten years after the date of each grant.
 
Transactions involving option shares for all plans are summarized as follows:
 
                                 
                Weighted
       
                Average
       
    Number of
          Remaining
    Aggregate
 
    Shares Subject
    Weighted Average
    Contractual
    Intrinsic
 
    to Option     Exercise Price     Life (Years)     Value  
                      (In thousands)  
 
Outstanding at September 30, 2009
    4,855,100     $ 27.18                  
Granted in 2010
        $                  
Exercised in 2010
    (1,975,853 )   $ 24.08                  
Forfeited in 2010
        $                  
                                 
Outstanding at September 30, 2010
    2,879,247     $ 29.30       2.80     $ 64,813  
                                 
Option shares exercisable at September 30, 2010
    2,879,247     $ 29.30       2.80     $ 64,813  
                                 
Option shares available for future grant at September 30, 2010(1)
    2,645,304                          
                                 
 
 
(1) Includes shares available for SARs and restricted stock grants.
 
Transactions involving non-performance based SARs for all plans are summarized as follows:
 
                                 
                Weighted
       
                Average
       
    Number of
          Remaining
    Aggregate
 
    Shares Subject
    Weighted Average
    Contractual
    Intrinsic
 
    To Option     Exercise Price     Life (Years)     Value  
                      (In thousands)  
 
Outstanding at September 30, 2009
    50,000     $ 41.20                  
Granted in 2010
        $                  
Exercised in 2010
        $                  
Forfeited in 2010
        $                  
                                 
Outstanding at September 30, 2010
    50,000     $ 41.20       6.45     $ 531  
                                 
SARs exercisable at September 30, 2010
    50,000     $ 41.20       6.45     $ 531  
                                 


 

Transactions involving performance based SARs for all plans are summarized as follows:
 
                                 
                Weighted
       
                Average
       
    Number of
          Remaining
    Aggregate
 
    Shares Subject
    Weighted Average
    Contractual
    Intrinsic
 
    To Option     Exercise Price     Life (Years)     Value  
                      (In thousands)  
 
Outstanding at September 30, 2009
    925,000     $ 36.14                  
Granted in 2010
    520,500     $ 52.10                  
Exercised in 2010
        $                  
Forfeited in 2010
        $                  
Canceled in 2010(1)
    (97,007 )   $ 47.37                  
                                 
Outstanding at September 30, 2010
    1,348,493     $ 41.49       8.57     $ 13,915  
                                 
SARs exercisable at September 30, 2010
    300,308     $ 35.53       7.96     $ 4,890  
                                 
 
 
(1) Shares were canceled during 2010 due to performance condition not being met.
 
Restricted Share Awards
 
Restricted stock is subject to restrictions on vesting and transferability. Restricted stock awards entitle the participants to full dividend and voting rights. The market value of restricted stock on the date of the award is recorded as compensation expense over the vesting period. Certificates for shares of restricted stock awarded under the Company's stock option and stock award plans are held by the Company during the periods in which the restrictions on vesting are effective.
 
Transactions involving restricted shares for all plans are summarized as follows:
 
                 
    Number of
    Weighted Average
 
    Restricted
    Fair Value per
 
    Share Awards     Award  
 
Restricted Share Awards Outstanding at September 30, 2009
    118,000     $ 45.58  
Granted in 2010
    4,000     $ 52.10  
Vested in 2010
    (27,500 )   $ 39.70  
Forfeited in 2010
        $  
                 
Restricted Share Awards Outstanding at September 30, 2010
    94,500     $ 47.57  
                 
 
Vesting restrictions for the outstanding shares of non-vested restricted stock at September 30, 2010 will lapse as follows: 2011 — 2,500 shares; 2012 — 5,000 shares; 2013 — 5,000 shares; 2014 — 5,000 shares; 2015 — 17,000 shares; 2016 — 5,000 shares; 2018 — 35,000 shares; and 2021 — 20,000 shares.
 
Redeemable Preferred Stock
 
As of September 30, 2010, there were 10,000,000 shares of $1 par value Preferred Stock authorized but unissued.
 
Long-Term Debt
 
The outstanding long-term debt is as follows:
 
                 
    At September 30  
    2010     2009  
    (Thousands)  
 
Medium-Term Notes(1):
               
6.7% to 7.50% due November 2010 to June 2025
  $ 449,000     $ 449,000  
Notes(1):
               
5.25% to 8.75% due March 2013 to May 2019
    800,000       800,000  
                 
Total Long-Term Debt
    1,249,000       1,249,000  
Less Current Portion(2)
    200,000        
                 
    $ 1,049,000     $ 1,249,000  
                 
 
 
(1) The Medium-Term Notes and Notes are unsecured.
 
(2) Current Portion of Long-Term Debt at September 30, 2010 consists of $200 million of 7.50% medium-term notes that mature in November 2010.
 
In April 2009, the Company issued $250.0 million of 8.75% notes due in May 2019. After deducting underwriting discounts and commissions, the net proceeds to the Company amounted to $247.8 million. These notes were registered under the Securities Act of 1933. The holders of the notes may require the Company to repurchase their notes at a price equal to 101% of the principal amount in the event of both a change in control and a ratings downgrade to a rating below investment grade. The proceeds of this debt issuance were used for general corporate purposes, including to replenish cash that was used to pay the $100 million due at the maturity of the Company's 6.0% medium-term notes on March 1, 2009.
 
The Company has $300.0 million of 6.50% notes that mature in April 2018. The holders of the notes may require the Company to repurchase their notes at a price equal to 101% of the principal amount in the event of both a change in control and a ratings downgrade to a rating below investment grade.
 
As of September 30, 2010, the aggregate principal amounts of long-term debt maturing during the next five years and thereafter are as follows: $200.0 million in 2011, $150.0 million in 2012, $250.0 million in 2013, zero in 2014, zero in 2015 and $649.0 million thereafter.
 
Short-Term Borrowings
 
The Company historically has obtained short-term funds either through bank loans or the issuance of commercial paper. As for the former, the Company maintains a number of individual uncommitted or discretionary lines of credit with certain financial institutions for general corporate purposes. Borrowings under these lines of credit are made at competitive market rates. These credit lines, which aggregate to $405.0 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 Company's 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.
 
At September 30, 2010 and 2009, the Company did not have any outstanding short-term notes payable to banks or commercial paper.
 
Debt Restrictions
 
Under the Company's 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 September 30, 2010, the Company's debt to capitalization ratio (as calculated under the facility) was .42. The constraints specified in the committed credit facility would permit an additional $1.99 billion in short-term and/or long-term debt to be outstanding (further limited by the indenture covenants discussed below) before the Company's debt to capitalization ratio would exceed .65. If a downgrade in any of the Company's 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 Company's existing indenture covenants, at September 30, 2010, the Company would have been permitted to issue up to a maximum of $1.3 billion in additional long-term unsecured indebtedness at then current market interest rates in addition to being able to issue new indebtedness to replace maturing debt. The Company's 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 Company's 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 Company's 1974 indenture pursuant to which $99.0 million (or 7.9%) of the Company's long-term debt (as of September 30, 2010) was issued, contains a cross-default provision whereby the failure by the Company to perform certain obligations under other borrowing arrangements could trigger an obligation to repay the debt outstanding under the indenture. In particular, a repayment obligation could be triggered if the Company fails (i) to pay any scheduled principal or interest on any debt under any other indenture or agreement, or (ii) to perform any other term in any other such indenture or agreement, and the effect of the failure causes, or would permit the holders of the debt to cause, the debt under such indenture or agreement to become due prior to its stated maturity, unless cured or waived.
 
The Company's $300.0 million committed credit facility also contains a cross-default provision whereby the failure by the Company or its significant subsidiaries to make payments under other borrowing arrangements, or the occurrence of certain events affecting those other borrowing arrangements, could trigger an obligation to repay any amounts outstanding under the committed credit facility. In particular, a repayment obligation could be triggered if (i) the Company or any of its significant subsidiaries 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 September 30, 2010, the Company had no debt outstanding under the committed credit facility.
Fair Value Measurements
Fair Value Measurements
Note F — 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 Company's 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 Company's financial assets and liabilities (as applicable) that were accounted for at fair value on a recurring basis as of September 30, 2010 and 2009. Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. In January 2010, the FASB issued amended authoritative guidance respecting disclosures related to fair value measurements. The amended guidance requires disclosure of financial instruments and liabilities by class of assets and liabilities (not major category of assets and liabilities). In addition, this amended guidance also requires enhanced disclosures about the valuation techniques and inputs used to measure fair value and disclosures of transfers in and out of Level 1 or 2. During the quarter ended March 31, 2010, the Company adopted this amended guidance.
 
                                 
    At Fair Value as of September 30, 2010  
Recurring Fair Value Measures   Level 1     Level 2     Level 3     Total  
    (Dollars in thousands)  
 
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  
                                 

 
                                 
    At Fair Value as of September 30, 2009  
Recurring Fair Value Measures   Level 1     Level 2     Level 3     Total  
    (Dollars in thousands)  
 
Assets:
                               
Cash Equivalents
  $ 390,462     $     $     $ 390,462  
Derivative Financial Instruments
    5,312       12,536       26,969       44,817  
Other Investments
    24,276                   24,276  
Hedging Collateral Deposits
    848                   848  
                                 
Total
  $ 420,898     $ 12,536     $ 26,969     $ 460,403  
                                 
Liabilities:
                               
Derivative Financial Instruments
  $     $ 2,148     $     $ 2,148  
                                 
Total
  $     $ 2,148     $     $ 2,148  
                                 
Total Net Assets/(Liabilities)
  $ 420,898     $ 10,388     $ 26,969     $ 458,255  
                                 
 
Derivative Financial Instruments
 
At September 30, 2010 and 2009, the derivative financial instruments reported in Level 1 consist of natural gas NYMEX futures contracts used in the Company's Energy Marketing segment. Hedging collateral deposits of $10.1 million (at September 30, 2010) and $0.8 million (at September 30, 2009), which are associated with these futures contracts have been reported in Level 1 as well. The derivative financial instruments reported in Level 2, at September 30, 2010 and 2009, consist of natural gas swap agreements used in the Company's Exploration and Production and Energy Marketing segments. The fair value of these swap agreements is based on an internal, discounted cash flow model that uses observable inputs (i.e. LIBOR based discount rates and basis differential information, if applicable, at active natural gas trading markets). At September 30, 2010 and 2009, the derivative financial instruments reported in Level 3 consist of all of the Exploration and Production segment's crude oil swap agreements. Hedging collateral deposits of $1.0 million associated with these oil swap agreements have been reported in Level 1 at September 30, 2010. The fair value of the crude oil swap agreements is based on an internal, discounted cash flow model that uses both observable (i.e. LIBOR based discount rates) and unobservable inputs (i.e. basis differential information of crude oil trading markets with low trading volume). Based on an assessment of the counterparties' credit risk, the fair market value of the price swap agreements reported as Level 2 and Level 3 assets have been reduced by $1.0 million and $0.9 million at September 30, 2010 and September 30, 2009, respectively. The fair market value of the price swap agreements reported as Level 2 and Level 3 liabilities at September 30, 2010 have been reduced by $0.3 million and the price swap agreements reported as Level 2 liabilities at September 30, 2009 have been reduced by less than $0.1 million based on an assessment of the Company's credit risk. 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 12 months ended September 30, 2010, no transfers in or out of Level 1 or Level 2 occurred.
 
Fair Value Measurements Using Unobservable Inputs (Level 3)
 
                                         
          Total Gains/Losses—
             
          Realized and Unrealized              
                Included in Other
    Transfer
       
    October 1,
    Included in
    Comprehensive Income
    In/(Out) of
    September 30,
 
    2009     Earnings     (Loss)     Level 3     2010  
    (Dollars in thousands)  
 
Derivative Financial Instruments(2)
  $ 26,969     $ (9,372 )(1)   $ (34,080 )   $     $ (16,483 )
                                         
 
 
(1) Amounts are reported in Operating Revenues in the Consolidated Statement of Income for the year ended September 30, 2010.
 
(2) Derivative Financial Instruments are shown on a net basis.
 
Fair Value Measurements Using Unobservable Inputs (Level 3)
 
                                         
          Total Gains/Losses —
             
          Realized and Unrealized              
                Included in Other
    Transfer
       
    October 1,
    Included in
    Comprehensive Income
    In/(Out) of
    September 30,
 
    2008     Earnings     (Loss)     Level 3     2009  
    (Dollars in thousands)  
 
Derivative Financial Instruments(2)
  $ 6,333     $ (59,180 )(1)   $ 87,147     $ (7,331 )(3)   $ 26,969  
                                         
 
 
(1) Amounts are reported in Operating Revenues in the Consolidated Statement of Income for the year ended September 30, 2009.
 
(2) Derivative Financial Instruments are shown on a net basis.
 
(3) These transfers occurred because the Company was able to obtain and utilize forward-looking, observable basis differential information for its hedges on southern California natural gas production.
Financial Instruments
Financial Instruments
Note G — Financial Instruments
 
Long-Term Debt
 
The fair market value of the Company's debt, as presented in the table below, was determined using a discounted cash flow model, which incorporates the Company's 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:
 
                                 
    At September 30  
    2010 Carrying
    2010 Fair
    2009 Carrying
    2009 Fair
 
    Amount     Value     Amount     Value  
    (Thousands)  
 
Long-Term Debt
  $ 1,249,000     $ 1,423,349     $ 1,249,000     $ 1,347,368  
                                 
 
The fair value amounts are not intended to reflect principal amounts that the Company will ultimately be required to pay. Carrying amounts for other financial instruments recorded on the Company's Consolidated Balance Sheets approximate fair value. The increase in the fair value of the Company's debt is attributable to a decrease in the estimated rate at which the Company could issue debt at September 30, 2010 relative to September 30, 2009.
 
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 $55.4 million and $54.2 million at September 30, 2010 and 2009, respectively. The fair value of the equity mutual fund was $17.3 million and $15.8 million at September 30, 2010 and 2009, respectively. The unrealized gain on the equity mutual fund at September 30, 2010 was negligible as the fair market value was approximately equal to the cost basis. The gross unrealized loss on this equity mutual fund was $1.0 million at September 30, 2009. The fair value of the stock of an insurance company was $5.0 million and $8.3 million at September 30, 2010 and 2009, respectively. The gross unrealized gain on this stock was $2.6 million and $5.9 million at September 30, 2010 and 2009, respectively. The insurance contracts and marketable equity securities are primarily informal funding mechanisms for various benefit obligations the Company has to certain employees.
 
Derivative Financial Instruments
 
The Company is exposed to certain risks relating to its ongoing business operations. The primary risk managed by using derivative instruments is commodity price risk in the Exploration and Production and Energy Marketing segments. The Company enters into futures contracts and over-the-counter swap agreements for natural gas and crude oil to manage the price risk associated with forecasted sales of gas and oil. The Company also enters into futures contracts and swaps to manage the risk associated with forecasted gas purchases, storage of gas, 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 Company's hedges do not typically exceed 3 years.
 
The Company has presented its net derivative assets and liabilities on its Consolidated Balance Sheet at September 30, 2010 and September 30, 2009 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
Contracts — at September 30,
2010
  Fair Value of
Derivative
Financial
Instruments
  $ 65,184     Fair Value of
Derivative
Financial
Instruments
  $ 20,160  
Commodity
Contracts — at September 30,
2009
  Fair Value of
Derivative
Financial
Instruments
  $ 44,817     Fair Value of
Derivative
Financial
Instruments
  $ 2,148  
 
The following table discloses the fair value of derivative contracts on a gross-contract basis as opposed to the net-contract basis presentation on the Consolidated Balance Sheet at September 30, 2010 and September 30, 2009.
 
         
Derivatives
       
Designated as
  Fair Values of Derivative Instruments
Hedging
  (Dollar Amounts in Thousands)
Instruments   Gross Asset Derivatives   Gross Liability Derivatives
 
    Fair Value   Fair Value
Commodity Contracts at September 30, 2010
  $77,837   $32,813
Commodity Contracts at September 30, 2009
  $63,601   $20,932
 
Cash Flow Hedges
 
For derivative instruments that are designated and qualify as a cash flow hedge, the effective portion of the gain or loss on the derivative is reported as a component of other comprehensive income (loss) and reclassified into earnings in the period or periods during which the hedged transaction affects earnings. Gains and losses on the derivative representing either hedge ineffectiveness or hedge components excluded from the assessment of effectiveness are recognized in current earnings.
 
As of September 30, 2010, the Company's 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
  37.5 Bcf (all short positions)
Crude Oil
  2,688,000 Bbls (all short positions)
 
As of September 30, 2010, the Company's 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 (6.1 Bcf short positions (forecasted storage withdrawals) and 0.1 Bcf long positions (forecasted storage injections))
 
As of September 30, 2010, the Company's Exploration and Production segment had $49.1 million ($28.9 million after tax) of gains included in the accumulated other comprehensive income (loss) balance. It is expected that $33.3 million ($19.6 million after tax) of these gains will be reclassified into the Consolidated Statement of Income within the next 12 months as the expected sales of the underlying commodities occur. See Note A, under Accumulated Other Comprehensive Income (Loss), for the after-tax gain pertaining to derivative financial instruments (Net Unrealized Gain (Loss) on Derivative Financial Instruments in Note A includes the Exploration and Production and Energy Marketing segments).
 
As of September 30, 2010, the Company's Energy Marketing segment had $6.5 million ($4.0 million after tax) of gains included in the accumulated other comprehensive income (loss) balance. It is expected that all of these gains will be reclassified into the Consolidated Statement of Income within the next 12 months as the sales and purchases of the underlying commodities occur. See Note A, under Accumulated Other Comprehensive Income (Loss), for the after-tax gain pertaining to derivative financial instruments (Net Unrealized Gain (Loss) on Derivative Financial Instruments in Note A includes the Exploration and Production and Energy Marketing segments).
 
 
                                                         
    The Effect of Derivative Financial Instruments on the Statement of Financial Performance for the
 
    Year Ended September 30, 2010 and 2009 (Dollar Amounts in Thousands)  
    Amount of
        Amount of
           
    Derivative Gain or
        Derivative Gain or
           
    (Loss) Recognized
    Location of
  (Loss) Reclassified
           
    in Other
    Derivative Gain or
  from Accumulated
        Derivative Gain or
 
    Comprehensive
    (Loss) Reclassified
  Other Comprehensive
    Location of
  (Loss) Recognized
 
    Income (Loss) on
    from Accumulated
  Income (Loss) on
    Derivative Gain or
  in the Consolidated
 
    the Consolidated
    Other Comprehensive
  the Consolidated
    (Loss) Recognized
  Statement of Income
 
    Statement of
    Income (Loss) on
  Balance Sheet into
    in the Consolidated
  (Ineffective
 
    Comprehensive
    the Consolidated
  the Consolidated
    Statement of Income
  Portion and Amount
 
    Income (Loss)
    Balance Sheet into
  Statement of Income
    (Ineffective
  Excluded from
 
Derivatives in Cash
  (Effective Portion)
    the Consolidated
  (Effective Portion)
    Portion and Amount
  Effectiveness Testing)
 
Flow Hedging
  for the Year Ended
    Statement of Income
  for the Year Ended
    Excluded from
  for the Year Ended
 
Relationships   September 30,     (Effective Portion)   September 30,     Effectiveness Testing)   September 30,  
    2010     2009         2010     2009         2010     2009  
 
Commodity Contracts — Exploration & Production segment
  $ 52,786     $ 110,883     Operating Revenue   $ 39,898     $ 91,808     Operating Revenue   $      —     $      —  
Commodity Contracts — Energy Marketing segment
  $ 11,200     $ 7,492     Purchased Gas   $ 52     $ 21,301     Operating Revenue   $     $  
Commodity Contracts — Pipeline & Storage Segment(1)
  $ 1,380     $ 652     Operating Revenue   $ 1,370     $ 1,952     Operating Revenue   $     $  
Commodity Contracts — All Other(1)
  $     $ 183     Purchased Gas   $     $ (681 )   Purchased Gas   $     $  
                                                         
Total
  $ 65,366     $ 119,210         $ 41,320     $ 114,380         $     $  
                                                         
 
 
(1) There were no open hedging positions at September 30, 2010 or 2009. As such there is no mention of these positions in the preceding sections of this footnote.
 
Fair value hedges
 
The Company's 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 Company's financial statements. As of September 30, 2010, the Company's Energy Marketing segment had fair value hedges covering approximately 15.3 Bcf (14.2 Bcf of fixed price sales commitments (all long positions), 0.9 Bcf of fixed price purchase commitments (all short positions), and 0.2 Bcf of storage hedges (all short positions)). For derivative instruments that are designated and qualify as a fair value hedge, the gain or loss on the derivative as well as the offsetting gain or loss on the hedged item attributable to the hedged risk completely offset each other in current earnings, as shown below.
 
                 
Consolidated Statement of Income   Gain/(Loss) on Derivative   Gain/(Loss) on Commitment
 
Operating Revenues
  $ (9,807,701 )   $ 9,807,701  
Purchased Gas
  $ 62,352     $ (62,352 )

 
                 
          Amount of
 
          Derivative Gain or
 
    Location of
    (Loss) Recognized
 
    Derivative Gain or
    in the Consolidated
 
    (Loss) Recognized
    Statement of Income
 
    in the Consolidated
    for the Year Ended
 
Derivatives in Fair Value Hedging Relationships   Statement of Income     September 30, 2010  
          (In thousands)  
 
Commodity Contracts — Energy Marketing segment(1)
    Operating Revenues     $ (9,808 )
Commodity Contracts — Energy Marketing segment(2)
    Purchased Gas     $ (144 )
Commodity Contracts — Energy Marketing segment(3)
    Purchased Gas     $ 207  
                 
            $ (9,745 )
                 
 
 
(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 Company's counterparties are financial institutions and energy traders. The Company has over-the-counter swap positions with eleven counterparties of which ten of the eleven counterparties are in a net gain position. On average, the Company had $6.5 million of credit exposure per counterparty in a gain position at September 30, 2010. The maximum credit exposure per counterparty at September 30, 2010 was $11.9 million. BP Energy Company (an affiliate of BP Corporation North America, Inc.) was one of the ten counterparties in a gain position. At September 30, 2010, the Company had an $11.3 million receivable with BP Energy Company. The Company considered the credit quality of BP Energy Company (as it does with all of its counterparties) in determining hedge effectiveness and believes the hedges remain effective. The Company had not received any collateral from these counterparties at September 30, 2010 since the Company's gain position on such derivative financial instruments had not exceeded the established thresholds at which the counterparties would be required to post collateral.
 
As of September 30, 2010, nine of the eleven counterparties to the Company's outstanding derivative instrument contracts (specifically the over-the-counter swaps) had a common credit-risk related contingency feature. In the event the Company's credit rating increases or falls below a certain threshold (the lower of the S&P or Moody's Debt Rating), the available credit extended to the Company would either increase or decrease. A decline in the Company's 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 Company's outstanding derivative instrument contracts were in a liability position and the Company's credit rating declined, then additional hedging collateral deposits would be required. At September 30, 2010, the fair market value of the derivative financial instrument assets with a credit-risk related contingency feature was $42.1 million according to the Company's internal model (discussed in Note F — Fair Value Measurements). At September 30, 2010, the fair market value of the derivative financial instrument liability with a credit-risk related contingency feature was $14.3 million according to the Company's internal model (discussed in Note F — Fair Value Measurements). For its over-the-counter crude oil swap agreements, which are in a liability position, the Company was required to post $1.0 million in hedging collateral deposits at September 30, 2010. This is discussed in Note A under Hedging Collateral Deposits.
 
For its exchange traded futures contracts which are in a liability position, the Company had posted $10.1 million in hedging collateral as of September 30, 2010. As these are exchange traded futures contracts, there are no specific credit-risk related contingency features. The Company posts hedging collateral based on open positions and margin requirements it has with its counterparties.
 
The Company's requirement to post hedging collateral deposits is based on the fair value determined by the Company's counterparties, which may differ from the Company's 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 A under Hedging Collateral Deposits.
Retirement Plan and Other Post-Retirement Benefits
Retirement Plan and Other Post-Retirement Benefits
Note H — Retirement Plan and Other Post-Retirement Benefits
 
The Company has a tax-qualified, noncontributory, defined-benefit retirement plan (Retirement Plan) that covers a majority of the full-time employees of the Company. The Retirement Plan covers certain non-collectively bargained employees hired before July 1, 2003 and certain collectively bargained employees hired before November 1, 2003. Certain non-collectively bargained employees hired after June 30, 2003 and certain collectively bargained employees hired after October 31, 2003 are eligible for a Retirement Savings Account benefit provided under the Company's defined contribution Tax-Deferred Savings Plans. Costs associated with the Retirement Savings Account were $0.6 million, $0.4 million and $0.2 million for the years ended September 30, 2010, 2009 and 2008, respectively. Costs associated with the Company's contributions to the Tax-Deferred Savings Plans, exclusive of the costs associated with the Retirement Savings Account, were $4.2 million, $4.1 million, and $4.0 million for the years ended September 30, 2010, 2009 and 2008, respectively.
 
The Company provides health care and life insurance benefits (other post-retirement benefits) for a majority of its retired employees. The other post-retirement benefits cover certain non-collectively bargained employees hired before January 1, 2003 and certain collectively bargained employees hired before October 31, 2003.
 
The Company's policy is to fund the Retirement Plan with at least an amount necessary to satisfy the minimum funding requirements of applicable laws and regulations and not more than the maximum amount deductible for federal income tax purposes. The Company has established VEBA trusts for its other post-retirement benefits. Contributions to the VEBA trusts are tax deductible, subject to limitations contained in the Internal Revenue Code and regulations and are made to fund employees' other post-retirement benefits, as well as benefits as they are paid to current retirees. In addition, the Company has established 401(h) accounts for its other post-retirement benefits. They are separate accounts within the Retirement Plan trust used to pay retiree medical benefits for the associated participants in the Retirement Plan. Although these accounts are in the Retirement Plan trust, for funding status purposes as shown below, the 401(h) accounts are included in Fair Value of Assets under Other Post-Retirement Benefits. Contributions are tax-deductible when made, subject to limitations contained in the Internal Revenue Code and regulations. Retirement Plan, VEBA trust and 401(h) account assets primarily consist of equity and fixed income investments or units in commingled funds or money market funds.
 
The expected return on plan assets, a component of net periodic benefit cost shown in the tables below, is applied to the market-related value of plan assets. The market-related value of plan assets is the market value as of the measurement date adjusted for variances between actual returns and expected returns (from previous years) that have not been reflected in net periodic benefit costs.
 
Reconciliations of the Benefit Obligations, Plan Assets and Funded Status, as well as the components of Net Periodic Benefit Cost and the Weighted Average Assumptions of the Retirement Plan and other post-retirement benefits are shown in the tables below. The date used to measure the Benefit Obligations, Plan Assets and Funded Status is September 30, 2010, September 30, 2009 and June 30, 2008, for fiscal year 2010, 2009 and 2008, respectively.
 
 
                                                 
    Retirement Plan     Other Post-Retirement Benefits  
    Year Ended September 30     Year Ended September 30  
    2010     2009     2008     2010     2009     2008  
    (Thousands)  
 
Change in Benefit Obligation
                                               
Benefit Obligation at Beginning of Period
  $ 831,496     $ 719,059     $ 742,519     $ 467,295     $ 411,545     $ 444,545  
Service Cost
    12,997       10,913       12,597       4,298       3,801       5,104  
Interest Cost
    44,308       46,836       44,949       25,017       27,499       27,081  
Plan Participants' Contributions
                      1,644       2,185       1,990  
Retiree Drug Subsidy Receipts
                      1,354       1,427       1,532  
Amendments(1)
                            (10,765 )     (31,874 )
Actuarial (Gain) Loss
    85,831       102,430       (34,189 )     (3,635 )     55,776       (14,390 )
Adjustment for Change in Measurement Date
          14,438                   7,825        
Benefits Paid
    (50,139 )     (62,180 )     (46,817 )     (23,566 )     (31,998 )     (22,443 )
                                                 
Benefit Obligation at End of Period
  $ 924,493     $ 831,496     $ 719,059     $ 472,407     $ 467,295     $ 411,545  
                                                 
Change in Plan Assets
                                               
Fair Value of Assets at Beginning of Period
  $ 563,881     $ 695,089     $ 765,144     $ 319,022     $ 377,640     $ 412,371  
Actual Return on Plan Assets
    61,625       (99,511 )     (39,206 )     30,478       (62,368 )     (43,478 )
Employer Contributions
    22,182       15,993       3,817       25,691       25,659       29,200  
Employer Contributions During Period from Measurement Date to Fiscal Year End
    N/A       N/A       12,151       N/A       N/A        
Plan Participants' Contributions
                      1,644       2,185       1,990  
Adjustment for Change in Measurement Date
          14,490                   7,904        
Benefits Paid
    (50,139 )     (62,180 )     (46,817 )     (23,566 )     (31,998 )     (22,443 )
                                                 
Fair Value of Assets at End of Period
  $ 597,549     $ 563,881     $ 695,089     $ 353,269     $ 319,022     $ 377,640  
                                                 
Net Amount Recognized at End of Period (Funded Status)
  $ (326,944 )   $ (267,615 )   $ (23,970 )   $ (119,138 )   $ (148,273 )   $ (33,905 )
                                                 
Amounts Recognized in the Balance Sheets Consist of:
                                               
Accrued Benefit Liability
  $ (326,944 )   $ (267,615 )   $ (23,970 )   $ (119,138 )   $ (148,273 )   $ (54,939 )
Prepaid Benefit Cost
                                  21,034  
                                                 
Net Amount Recognized at End of Period
  $ (326,944 )   $ (267,615 )   $ (23,970 )   $ (119,138 )   $ (148,273 )   $ (33,905 )
                                                 
Accumulated Benefit Obligation
  $ 843,526     $ 758,658     $ 659,004       N/A       N/A       N/A  
                                                 
                                                 

 

  Retirement Plan     Other Post-Retirement Benefits  
    Year Ended September 30     Year Ended September 30  
    2010     2009     2008     2010     2009     2008  
    (Thousands)  
 
Weighted Average Assumptions Used to Determine Benefit Obligation at September 30
                                               
Discount Rate
    4.75 %     5.50 %     6.75 %     4.75 %     5.50 %     6.75 %
Rate of Compensation Increase
    4.75 %     5.00 %     5.00 %     4.75 %     5.00 %     5.00 %
Components of Net Periodic Benefit Cost
                                               
Service Cost
  $ 12,997     $ 10,913     $ 12,597     $ 4,298     $ 3,801     $ 5,104  
Interest Cost
    44,308       46,836       44,949       25,017       27,499       27,081  
Expected Return on Plan Assets
    (58,342 )     (57,958 )     (55,000 )     (26,334 )     (31,615 )     (33,715 )
Amortization of Prior Service Cost
    655       732       808       (1,710 )     (1,074 )     4  
Amortization of Transition Amount
                      541       2,265       7,127  
Recognition of Actuarial Loss(2)
    21,641       5,676       11,064       25,881       9,271       2,927  
Net Amortization and Deferral for Regulatory Purposes
    (30 )     12,817       6,008       351       18,037       22,264  
                                                 
Net Periodic Benefit Cost
  $ 21,229     $ 19,016     $ 20,426     $ 28,044     $ 28,184     $ 30,792  
                                                 
Weighted Average Assumptions Used to Determine Net Periodic Benefit Cost at September 30
                                               
Discount Rate
    5.50 %     6.75 %     6.25 %     5.50 %     6.75 %     6.25 %
Expected Return on Plan Assets
    8.25 %     8.25 %     8.25 %     8.25 %     8.25 %     8.25 %
Rate of Compensation Increase
    5.00 %     5.00 %     5.00 %     5.00 %     5.00 %     5.00 %
 
 
(1) In fiscal 2008 and 2009, the Company passed amendments, for most of the subsidiaries, which increased the participant contributions for active employees at the time of the amendment. This decreased the benefit obligation.
 
(2) Distribution Corporation's New York jurisdiction calculates the amortization of the actuarial loss on a vintage year basis over 10 years, as mandated by the NYPSC. All the other subsidiaries of the Company utilize the corridor approach.
 
The Net Periodic Benefit Cost in the table above includes the effects of regulation. The Company recovers pension and other post-retirement benefit costs in its Utility and Pipeline and Storage segments in accordance with the applicable regulatory commission authorizations. Certain of those commission authorizations established tracking mechanisms which allow the Company to record the difference between the amount of pension and other post-retirement benefit costs recoverable in rates and the amounts of such costs as determined under the existing authoritative guidance as either a regulatory asset or liability, as appropriate. Any activity under the tracking mechanisms (including the amortization of pension and other post-retirement regulatory assets and liabilities) is reflected in the Net Amortization and Deferral for Regulatory Purposes line item above.
 
As noted above, through 2008, the Company used June 30th as the measurement date for financial reporting purposes. In 2009, in accordance with the current authoritative guidance for defined benefit pension and other postretirement plans, the Company began measuring the Plan's assets and liabilities for its pension and other post-retirement benefit plans as of September 30th, its fiscal year end. In making this change and as permitted by the current authoritative guidance, the Company recorded fifteen months of pension and post-retirement benefits expense during the fiscal year ended September 30, 2009. As allowed by the authoritative guidance, these costs were calculated using June 30, 2008 measurement date data. Three of those months pertained to the period of July 1, 2008 to September 30, 2008. The pension and other post-retirement benefit costs for that period amounted to $3.8 million and were recorded by the Company during the year ended September 30, 2009 as a $3.4 million increase to Other Regulatory Assets in the Company's Utility and Pipeline and Storage segments and a $0.4 million ($0.2 million after tax) adjustment to earnings reinvested in the business. In addition, for the Company's non-qualified benefit plan, benefit costs of $1.3 million were recorded by the Company during the year ended September 30, 2009 as a $0.4 million increase to Other Regulatory Assets in the Company's Utility segment and a $0.9 million ($0.6 million after tax) adjustment to earnings reinvested in the business.
 
 
The cumulative amounts recognized in accumulated other comprehensive income (loss), regulatory assets, and regulatory liabilities through fiscal 2010, the changes in such amounts during 2010, as well as the amounts expected to be recognized in net periodic benefit cost in fiscal 2011 are presented in the table below:
 
                         
          Other
       
    Retirement
    Post-Retirement
    Non-Qualified
 
    Plan     Benefits     Benefit Plans  
    (Thousands)  
 
Amounts Recognized in Accumulated Other Comprehensive Income (Loss), Regulatory Assets and Regulatory Liabilities(1)
                       
Net Actuarial Loss
  $ (385,522 )   $ (157,700 )   $ (33,949 )
Transition Obligation
          (1,487 )      
Prior Service (Cost) Credit
    (3,925 )     8,807        
                         
Net Amount Recognized
  $ (389,447 )   $ (150,380 )   $ (33,949 )
                         
Changes to Accumulated Other Comprehensive Income (Loss), Regulatory Assets and Regulatory Liabilities Recognized During Fiscal 2010(1)
                       
Increase in Net Actuarial Gain/(Loss)
  $ (60,907 )   $ 33,660     $ (9,258 )
Reduction in Transition Obligation
          540        
Prior Service (Cost) Credit
    656       (1,710 )      
                         
Net Change
  $ (60,251 )   $ 32,490     $ (9,258 )
                         
Amounts Expected to be Recognized in Net Periodic Benefit Cost in the Next Fiscal Year(1)
                       
Net Actuarial Loss
  $ (34,873 )   $ (23,793 )   $ (3,860 )
Transition Obligation
          (541 )      
Prior Service (Cost) Credit
    (589 )     1,710        
                         
Net Amount Expected to be Recognized
  $ (35,462 )   $ (22,624 )   $ (3,860 )
                         
 
 
(1) Amounts presented are shown before recognizing deferred taxes.
 
In order to adjust the funded status of its pension (tax-qualified and non-qualified) and other post-retirement benefit plans at September 30, 2010, the Company recorded an $11.8 million increase to Other Regulatory Assets in the Company's Utility and Pipeline and Storage segments and a $25.2 million (pre-tax) increase to Accumulated Other Comprehensive Loss.
 
The effect of the discount rate change for the Retirement Plan in 2010 was to increase the projected benefit obligation of the Retirement Plan by $75.1 million. In 2010, other actuarial experience increased the projected benefit obligation for the Retirement Plan by $10.8 million. The effect of the discount rate change for the Retirement Plan in 2009 was to increase the projected benefit obligation of the Retirement Plan by $102.6 million. The effect of the discount rate change for the Retirement Plan in 2008 was to decrease the projected benefit obligation of the Retirement Plan by $38.6 million.
 
The Company made cash contributions totaling $22.2 million to the Retirement Plan during the year ended September 30, 2010. The Company expects that the annual contribution to the Retirement Plan in 2011 will be in the range of $40.0 million to $45.0 million. 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 2011 in order to be in compliance with the Pension Protection Act of 2006.
 
The following benefit payments, which reflect expected future service, are expected to be paid during the next five years and the five years thereafter: $52.1 million in 2011; $52.9 million in 2012; $53.8 million in 2013; $54.9 million in 2014; $56.3 million in 2015; and $305.4 million in the five years thereafter.
 
In addition to the Retirement Plan discussed above, the Company also has Non-Qualified benefit plans that cover a group of management employees designated by the Chief Executive Officer of the Company. These plans provide for defined benefit payments upon retirement of the management employee, or to the spouse upon death of the management employee. The net periodic benefit cost associated with these plans were $7.4 million, $5.4 million and $5.2 million in 2010, 2009 and 2008, respectively. The accumulated benefit obligations for the plans were $41.8 million and $37.4 million at September 30, 2010 and 2009, respectively. The projected benefit obligations for the plans were $73.9 million and $64.6 million at September 30, 2010 and 2009, respectively. The actuarial valuations for the plans were determined based on a discount rate of 4.25%, 5.25% and 6.75% as of September 30, 2010, 2009 and 2008, respectively and a weighted average rate of compensation increase of 8.0%, 8.25% and 8.75% as of September 30, 2010, 2009 and 2008, respectively.
 
The effect of the discount rate change in 2010 was to increase the other post-retirement benefit obligation by $39.4 million. Other actuarial experience decreased the other post-retirement benefit obligation in 2010 by $43.1 million, primarily attributable to updated pharmaceutical drug rebate experience as well as updated claim costs assumptions based on experience.
 
The effect of the discount rate change in 2009 was to increase the other post-retirement benefit obligation by $60.9 million. Effective October 1, 2009, the Medicare Part B reimbursement trend, prescription drug trend and medical trend assumptions were changed. The effect of these assumption changes was to increase the other post-retirement benefit obligation by $27.0 million. Other actuarial experience decreased the other post-retirement benefit obligation in 2009 by $32.1 million.
 
The effect of the discount rate change in 2008 was to decrease the other post-retirement benefit obligation by $26.3 million. Effective July 1, 2008, the Medicare Part B reimbursement trend, prescription drug trend and medical trend assumptions were changed. The effect of these assumption changes was to increase the other post-retirement benefit obligation by $20.0 million. Other actuarial experience decreased the other post-retirement benefit obligation in 2008 by $8.1 million.
 
On December 8, 2003, the Medicare Prescription Drug, Improvement, and Modernization Act of 2003 (the Act) was signed into law. This Act introduced a prescription drug benefit under Medicare (Medicare Part D), as well as a federal subsidy to sponsors of retiree health care benefit plans that provide a benefit that is at least actuarially equivalent to Medicare Part D. Since the Company is assumed to continue to provide a prescription drug benefit to retirees in the point of service and indemnity plans that is at least actuarially equivalent to Medicare Part D, the impact of the Act was reflected as of December 8, 2003.
 
The estimated gross other post-retirement benefit payments and gross amount of Medicare Part D prescription drug subsidy receipts are as follows:
 
                 
    Benefit Payments   Subsidy Receipts
 
2011
  $ 25,375,000     $ (2,001,000 )
2012
  $ 26,795,000     $ (2,275,000 )
2013
  $ 28,116,000     $ (2,575,000 )
2014
  $ 29,520,000     $ (2,871,000 )
2015
  $ 31,002,000     $ (3,169,000 )
2016 through 2020
  $ 175,195,000     $ (20,370,000 )
 
                         
    2010   2009   2008
 
Rate of Increase for Pre Age 65 Participants
    7.82 %(1)     8.0 %(1)     9.0 %(2)
Rate of Increase for Post Age 65 Participants
    6.95 %(1)     7.0 %(1)     7.0 %(2)
Annual Rate of Increase in the Per Capita Cost of Covered Prescription Drug Benefits
    8.69 %(1)     9.0 %(1)     10.0 %(2)
Annual Rate of Increase in the Per Capita Medicare Part B Reimbursement
    6.95 %(1)     7.0 %(1)     7.0 %(2)
Annual Rate of Increase in the Per Capita Medicare Part D Subsidy
    7.60 %(1)     7.9 %(1)     10.0 %(2)
 
 
(1) It was assumed that this rate would gradually decline to 4.5% by 2028.
 
(2) It was assumed that this rate would gradually decline to 5.0% by 2018.
 
The health care cost trend rate assumptions used to calculate the per capita cost of covered medical care benefits have a significant effect on the amounts reported. If the health care cost trend rates were increased by 1% in each year, the other post-retirement benefit obligation as of October 1, 2010 would increase by $57.6 million. This 1% change would also have increased the aggregate of the service and interest cost components of net periodic post-retirement benefit cost for 2010 by $4.0 million. If the health care cost trend rates were decreased by 1% in each year, the other post-retirement benefit obligation as of October 1, 2010 would decrease by $48.6 million. This 1% change would also have decreased the aggregate of the service and interest cost components of net periodic post-retirement benefit cost for 2010 by $3.3 million.
 
The Company made cash contributions totaling $25.5 million to its VEBA trusts and 401(h) accounts during the year ended September 30, 2010. In addition, the Company made direct payments of $0.2 million to retirees not covered by the VEBA trusts and 401(h) accounts during the year ended September 30, 2010. The Company expects that the annual contribution to its VEBA trusts and 401(h) accounts in 2011 will be in the range of $25.0 million to $30.0 million.
 
Investment Valuation
 
The Retirement Plan assets and other post-retirement benefit assets are valued under the current fair value framework. See Note F "Fair Value Measurements" for further discussion regarding the definition and levels of fair value hierarchy established by the authoritative guidance.
 
The inputs or methodology used for valuing securities are not necessarily an indication of the risk associated with investing in those securities. Below is a listing of the major categories of plan assets held as of September 30, 2010, as well as the associated level within the fair value hierarchy in which the fair value measurements in their entirety fall (based on the lowest level input that is significant to the fair value measurement in its entirety). (Dollars in Thousands):  
 
 
                                 
    Total Fair Value
                   
    Amounts at
                   
    September 30, 2010     Level 1     Level 2     Level 3  
 
Retirement Plan Investments
                               
Equities
                               
Collective Trust Funds — Domestic
  $ 131,313     $     $ 131,313     $  
Collective Trust Funds — International
    72,612             72,612        
Common Stock — Domestic
    158,215       158,215              
Common Stock — International
    19,351       19,351              
Convertible Securities — Domestic
    32,911       4,403       28,189       319  
Convertible Securities — International
    2,175       548       1,627        
Preferred Stock
    765       765              
                                 
Total Equities
    417,342       183,282       233,741       319  
Fixed Income
                               
Collective Trust Funds — Domestic
    75,455             75,455        
Collective Trust Funds — International
    69,511             69,511        
Corporate Bonds — Domestic
    572             572        
Exchange Traded Funds
    17,911       17,911              
Other
    83             83        
                                 
Total Fixed Income
    163,532       17,911       145,621        
Real Estate
    5,812                   5,812  
Limited Partnerships
    232                   232  
Cash & Cash Equivalents
                               
Cash Held in Collective Trust Funds
    10,413             10,413        
Cash Held in Savings/Checking Accounts, Commercial Paper, etc. 
    123             123        
                                 
Total Cash & Cash Equivalents
    10,536             10,536        
                                 
Total Retirement Plan Investments
  $ 597,454     $ 201,193     $ 389,898     $ 6,363  
                                 
Accrued Income Receivable
    699                          
Accrued Administrative Costs
    (604 )                        
                                 
Total Retirement Plan Assets
  $ 597,549                          
                                 
 
 
                                 
    Total Fair Value
                   
    Amounts at
                   
    September 30, 2010     Level 1     Level 2     Level 3  
 
VEBA Investments
                               
Equities
                               
Collective Trust Funds — Domestic
  $ 217,637     $     $ 217,637     $  
Collective Trust Funds — International
    85,799             85,799        
                                 
Total Equities
    303,436             303,436        
Real Estate
    3,824                   3,824  
Cash Held in Collective Trust Funds
    7,622             7,622        
                                 
Total VEBA Investments
  $ 314,882     $     $ 311,058     $ 3,824  
                                 
Accrued Income Receivable
    600                          
Accrued Administrative Costs
    (196 )                        
Claims Incurred But Not Reported
    (1,736 )                        
Prepaid Federal Taxes
    2,866                          
Deferred Tax Asset
    2,230                          
                                 
Total Fair Value of VEBA Assets
  $ 318,646                          
                                 
401(h) Investments
                               
Equities
                               
Collective Trust Funds — Domestic
  $ 7,601     $     $ 7,601     $  
Collective Trust Funds — International
    4,203             4,203        
Common Stock — Domestic
    9,158       9,158              
Common Stock — International
    1,120       1,120              
Convertible Securities — Domestic
    1,905       255       1,632       18  
Convertible Securities — International
    126       32       94        
Preferred Stock
    45       45              
                                 
Total Equities
    24,158       10,610       13,530       18  
Fixed Income
                               
Collective Trust Funds — Domestic
    4,368             4,368        
Collective Trust Funds — International
    4,024             4,024        
Corporate Bonds — Domestic
    33             33        
Exchange Traded Funds
    1,037       1,037              
Other
    4             4        
                                 
Total Fixed Income
    9,466       1,037       8,429        
Real Estate
    336                   336  
Limited Partnerships
    13                   13  
Cash Held in Collective Trust Funds
    610             610        
                                 
Total 401(h) Investments
  $ 34,583     $ 11,647     $ 22,569     $ 367  
                                 
Accrued Income Receivable
    40                          
                                 
Total Fair Value of Assets
  $ 34,623                          
                                 
Total Other Post-Retirement Benefit Assets
  $ 353,269                          
                                 

 

Retirement Plan and 401(h) Account Investments:
 
Equities:  Level 1 equities consist of individual publicly traded stocks (common and preferred) and convertible securities. These are valued using quoted market values as of the end of the year. Level 2 equities consist primarily of investments in collective trusts. The fair value of such trusts is derived from the fair value of the underlying investments. In addition, there are Level 2 equities that consist of convertible securities, for which quoted market values are unavailable or are not used because the associated trading volumes are lower, that are valued using observable market data. Level 3 equities consist of investments in convertible securities where there are no readily obtainable market values. These investments are valued using unobservable market data.
 
Fixed Income:  Level 1 fixed income securities consist of exchange-traded bond funds and are valued using quoted market values as of the end of the year. Level 2 fixed income securities consist primarily of investments in collective trusts, corporate bonds and other investments (typically guaranteed investment contracts, collateralized mortgage obligations, asset backed securities, etc). The collective trusts are carried at the stated unit value of funds, which are derived from the fair value of the underlying investments. The corporate bonds and other investments are valued using observable market data. Level 3 fixed income securities typically consist of collateralized mortgage obligations, asset backed securities, and corporate/government bonds that are not actively traded. At September 30, 2010, there are no such investments.
 
Real Estate:  Level 3 real estate investments consist primarily of commercial and residential properties that are valued at the Plan's proportionate interest in the total current value of the underlying net assets of these investments. This fair value is determined using unobservable market data.
 
Limited Partnerships:  Level 3 limited partnerships consist of cash held in the partnerships and private equity holdings. The Plan's interest in these partnerships is valued based on the fair value as determined by the general partner or board of directors. The fair value of the private equity holdings is determined using unobservable market data.
 
Cash and Cash Equivalents:  The cash and cash equivalents in Level 2 consists of collective trusts that invest in various cash and money market investments as well as treasury bills, notes, and bonds. In addition, cash held in checking/savings accounts and commercial paper are included as well.
 
VEBA Investments:
 
Collective Trust Funds:  The fair value of collective trust funds classified as Level 2 are derived from the fair value of the underlying investments in equities (primarily publicly traded stocks).
 
Cash and Cash Equivalents:  The cash equivalents reported in Level 2 consists of an institutional fund that invests in high quality, short-term municipal instruments. This fund is valued at amortized cost, which the investment advisor has determined approximates fair value.
 
Real Estate:  Level 3 real estate investments consist primarily of commercial and residential properties that are valued at the VEBA's proportionate interest in the total current value of the underlying net assets of these investments. This fair value is determined using unobservable market data.
 
The preceding methods may produce a fair value calculation that may not be indicative of net realizable value or reflective of future fair values. Furthermore, although the Company believes its valuation methods are appropriate and consistent with other market participants, the use of different methodologies or assumptions to determine the fair value of certain financial instruments could result in a different fair value measurement at the reporting date.
 
The following tables provide a reconciliation of the beginning and ending balances of the Retirement Plan and other post-retirement benefit assets measured at fair value on a recurring basis where the determination of fair value includes significant unobservable inputs (Level 3). Note: For the year-ended September 30, 2010, there were no significant transfers in or out of Level 1 or Level 2. In addition, as shown in the following tables, there were no transfers in or out of Level 3.
 
                                                 
    Retirement Plan Level 3 Assets
 
    Year Ended September 30, 2010
 
    (Thousands of Dollars)  
    Equities     Fixed Income                    
                Collateralized
                   
    Convertible
          Mortgage
                   
    Securities
    Preferred
    Obligations
    Limited
    Real
       
    (Domestic)     Stock     (Part of Other)     Partnerships     Estate     Total  
 
Balance, Beginning of Year
  $ 733     $ 362     $ 542     $ 372     $ 7,518     $ 9,527  
Realized Gains/(Losses)
    50       (108 )     1       (1,495 )           (1,552 )
Unrealized Gains/(Losses)
    (4 )     (3 )     (24 )     1,510       (2,350 )     (871 )
Purchases, Sales, Issuances, and Settlements (Net)
    (460 )     (251 )     (519 )     (155 )     644       (741 )
                                                 
Balance at September 30, 2010 (End of Year)
  $ 319     $     $     $ 232     $ 5,812     $ 6,363  
                                                 
 
                                                         
    Other Post-Retirement Benefit Level 3 Assets
 
    Year Ended September 30, 2010
 
    (Thousands of Dollars)  
    VEBA
    401(h) Investments  
    Investments     Equities     Fixed Income                    
                      Collateralized
                   
          Convertible
          Mortgage
                Total
 
    Real
    Securities
    Preferred
    Obligations
    Limited
    Real
    401(h)
 
    Estate     (Domestic)     Stock     (Part of Other)     Partnerships     Estate     Investments  
 
Balance, Beginning of Year
  $ 3,816     $ 37     $ 18     $ 27     $ 19     $ 376     $ 477  
Realized Gains/(Losses)
          3       (6 )           (87 )           (90 )
Unrealized Gains/(Losses)
    8       5       3       3       90       (77 )     24  
Purchases, Sales, Issuances, and Settlements (Net)
          (27 )     (15 )     (30 )     (9 )     37       (44 )
                                                         
Balance at September 30, 2010 (End of Year)
  $ 3,824     $ 18     $     $     $ 13     $ 336     $ 367  
                                                         
 
The Company's Retirement Plan weighted average asset allocations (excluding the 401(h) accounts) at September 30, 2010, 2009 and 2008 by asset category are as follows:
 
                                 
          Percentage of Plan
 
    Target Allocation
    Assets at September 30  
Asset Category   2011     2010     2009     2008  
 
Equity Securities
    60-75 %     70 %     73 %     74 %
Fixed Income Securities
    20-35 %     27 %     21 %     23 %
Other
    0-15 %     3 %     6 %     3 %
                                 
Total
            100 %     100 %     100 %
                                 
 
The Company's weighted average asset allocations for its VEBA trusts and 401(h) accounts at September 30, 2010, 2009 and 2008 by asset category are as follows:
 
                                 
          Percentage of Plan
 
    Target Allocation
    Assets at September 30  
Asset Category   2011     2010     2009     2008  
 
Equity Securities
    85-100 %     93 %     93 %     93 %
Fixed Income Securities
    0-15 %     3 %     2 %     2 %
Other
    0-15 %     4 %     5 %     5 %
                                 
Total
            100 %     100 %     100 %
                                 
 
The Company's assumption regarding the expected long-term rate of return on plan assets is 8.25%. The return assumption reflects the anticipated long-term rate of return on the plan's current and future assets. The Company utilizes historical investment data, projected capital market conditions, and the plan's target asset class and investment manager allocations to set the assumption regarding the expected return on plan assets.
 
The long-term investment objective of the Retirement Plan trust, the VEBA trusts and the 401(h) accounts is to achieve the target total return in accordance with the Company's risk tolerance. Assets are diversified utilizing a mix of equities, fixed income and other securities (including real estate). Risk tolerance is established through consideration of plan liabilities, plan funded status and corporate financial condition. The assets of the Retirement Plan trusts, VEBA trusts and the 401(h) accounts have no significant concentrations of risk in any one country (other than the United States), industry or entity.
 
Investment managers are retained to manage separate pools of assets. Comparative market and peer group performance of individual managers and the total fund are monitored on a regular basis, and reviewed by the Company's Retirement Committee on at least a quarterly basis.
 
The discount rate which is used to present value the future benefit payment obligations of the Retirement Plan and the Company's other post-retirement benefits is 4.75% as of September 30, 2010. The discount rate which is used to present value the future benefit payment obligations of the Non-Qualified benefit plans is 4.25% as of September 30, 2010. The Company utilizes a yield curve model to determine the discount rate. The yield curve is a spot rate yield curve that provides a zero-coupon interest rate for each year into the future. Each year's anticipated benefit payments are discounted at the associated spot interest rate back to the measurement date. The discount rate is then determined based on the spot interest rate that results in the same present value when applied to the same anticipated benefit payments.
Commitments and Contingencies
Commitments and Contingencies
Note I — Commitments and Contingencies
 
Environmental Matters
 
The Company is subject to various federal, state and local laws and regulations relating to the protection of the environment. The Company has established procedures for the ongoing evaluation of its operations, to identify potential environmental exposures and to comply with regulatory policies and procedures.
 
It is the Company's policy to accrue estimated environmental clean-up costs (investigation and remediation) when such amounts can reasonably be estimated and it is probable that the Company will be required to incur such costs. At September 30, 2010, the Company has estimated its remaining clean-up costs related to former manufactured gas plant sites and third party waste disposal sites will be in the range of $17.3 million to $21.5 million. The minimum estimated liability of $17.3 million has been recorded on the Consolidated Balance Sheet at September 30, 2010. The Company expects to recover its environmental clean-up costs through rate recovery. Other than as discussed below, the Company is currently not aware of any material exposure to environmental liabilities. However, changes in environmental regulations, new information or other factors could adversely impact the Company.

 

 

(i)  Former Manufactured Gas Plant Sites
 
The Company has incurred investigation and/or clean-up costs at several former manufactured gas plant sites in New York and Pennsylvania. The Company continues to be responsible for future ongoing monitoring and long-term maintenance at two sites.
 
The Company has agreed with the NYDEC to remediate another former manufactured gas plant site located in New York. The Company has received approval from the NYDEC of a Remedial Design work plan for this site and has recorded an estimated minimum liability for remediation of this site of $14.7 million.
 
(ii)  Other
 
In June 2007, the NYDEC notified the Company, as well as a number of other companies, of their potential liability with respect to a remedial action at a waste disposal site in New York. The notification identified the Company as one of approximately 500 other companies considered to be PRPs related to this site and requested that the remedy the NYDEC proposed in a Record of Decision issued in March 2006 be performed. The estimated clean-up costs under the remedy selected by the NYDEC are estimated to be approximately $13.0 million if implemented. The Company participates in an organized group with other PRPs who are addressing this site.
 
In November 2010, the NYDEC notified the Company of its potential liability with respect to a remedial action at former industrial sites in New York. Along with the Company, notifications were sent to the City of Buffalo and the New York State Thruway Authority. Estimated clean-up costs associated with these sites have not been completed and the Company cannot estimate its liability, if any, regarding these sites at this time.
 
Other
 
The Company, in its Utility segment, Energy Marketing segment, and All Other category, has entered into contractual commitments in the ordinary course of business, including commitments to purchase gas, transportation, and storage service to meet customer gas supply needs. Substantially all of these contracts expire within the next five years. The future gas purchase, transportation and storage contract commitments during the next five years and thereafter are as follows: $380.1 million in 2011, $86.3 million in 2012, $51.6 million in 2013, $34.7 million in 2014, $19.8 million in 2015 and $14.5 million thereafter. Gas prices within the gas purchase contracts are variable based on NYMEX prices adjusted for basis. In the Utility segment, these costs are subject to state commission review, and are being recovered in customer rates. Management believes that, to the extent any stranded pipeline costs are generated by the unbundling of services in the Utility segment's service territory, such costs will be recoverable from customers.
 
The Company has entered into leases for the use of buildings, vehicles, construction tools, meters, computer equipment and other items. These leases are accounted for as operating leases. The future lease commitments during the next five years and thereafter are as follows: $5.1 million in 2011, $4.6 million in 2012, $3.5 million in 2013, $3.2 million in 2014, $2.8 million in 2015, and $8.2 million thereafter.
 
The Company is involved in other litigation arising in the normal course of business. In addition to the regulatory matters discussed in Note C — Regulatory Matters, the Company is involved in other regulatory matters arising in the normal course of business. These other litigation and regulatory matters may include, for example, negligence claims and tax, regulatory or other governmental audits, inspections, investigations and other proceedings. These matters may involve state and federal taxes, safety, compliance with regulations, rate base, cost of service and purchased gas cost issues, among other things. While these normal-course matters could have a material effect on earnings and cash flows in the period in which they are resolved, they are not expected to change materially the Company's present liquidity position, nor are they expected to have a material adverse effect on the financial condition of the Company.
Discontinued Operations
Discontinued Operations
Note J — 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 Company's landfill gas operations were maintained under the Company's wholly-owned subsidiary, Horizon LFG. The Company received approximately $38.0 million of proceeds from the sale. The sale resulted in the recognition of a gain of approximately $6.3 million, net of tax, during the fourth quarter of 2010. The decision to sell was based on progressing the Company's 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 Company's landfill gas operations:
 
                         
    Year Ended September 30  
    2010     2009     2008  
    (Thousands)  
 
Operating Revenues
  $ 9,919     $ 6,309     $ 3,524  
Operating Expenses
    8,933       10,705       883  
                         
Operating Income (Loss)
    986       (4,396 )     2,641  
Other Income
    4       8       29  
Interest Income
    2              
Interest Expense
    29       127       599  
                         
Income (Loss) before Income Taxes
    963       (4,515 )     2,071  
Income Tax Expense (Benefit)
    493       (1,739 )     250  
                         
Income (Loss) from Discontinued Operations
    470       (2,776 )     1,821  
Gain on Disposal, Net of Taxes of $4,024
    6,310              
                         
Income (Loss) from Discontinued Operations
  $ 6,780     $ (2,776 )   $ 1,821  
                         
 
Business Segment Information
Business Segment Information
Note K — 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 Company's operations into reportable segments is based upon a combination of factors including differences in products and services, regulatory environment and geographic factors.
 
The Utility segment operations are regulated by the NYPSC and the PaPUC and are carried out by Distribution Corporation. Distribution Corporation sells natural gas to retail customers and provides natural gas transportation services in western New York and northwestern Pennsylvania.
 
The Pipeline and Storage segment operations are regulated by the FERC for both Supply Corporation and Empire. Supply Corporation transports and stores natural gas for utilities (including Distribution Corporation), natural gas marketers (including NFR), exploration and production companies (including Seneca) and pipeline companies in the northeastern United States markets. Empire transports natural gas from the United States/Canadian border near Buffalo, New York into Central New York just north of Syracuse, New York. Empire's new facilities (the Empire Connector), which consists of a compressor station and a pipeline extension from near Rochester, New York to an interconnection near Corning, New York with the unaffiliated Millennium Pipeline, were placed into service on December 10, 2008. Empire transports gas to major industrial companies, utilities (including Distribution Corporation) and power producers.
 
The Exploration and Production segment, through Seneca, is engaged in exploration for, and development and purchase of, natural gas and oil reserves in California, in the Appalachian region of the United States, and in the shallow waters of the Gulf Coast region of Texas and Louisiana. Seneca's production is, for the most part, sold to purchasers located in the vicinity of its wells. As disclosed in Note M — Acquisition, on July 20, 2009, Seneca acquired Ivanhoe Energy's United States oil and gas operations for approximately $39.2 million (including cash acquired). Ivanhoe Energy's United States oil and gas operations were incorporated into the Company's consolidated financial statements for the period subsequent to the completion of the acquisition on July 20, 2009.
 
The Energy Marketing segment is comprised of NFR's operations. NFR markets natural gas to industrial, wholesale, commercial, public authority and residential customers primarily in western and central New York and northwestern Pennsylvania, offering competitively priced natural gas for its customers.
 
The data presented in the tables below reflect financial information for the segments and reconciliations to consolidated amounts. The accounting policies of the segments are the same as those described in Note A — Summary of Significant Accounting Policies. Sales of products or services between segments are billed at regulated rates or at market rates, as applicable. The Company evaluates segment performance based on income before discontinued operations, extraordinary items and cumulative effects of changes in accounting (when applicable). When these items are not applicable, the Company evaluates performance based on net income.
 
                                                                 
    Year Ended September 30, 2010
                            Corporate
   
        Pipeline
  Exploration
      Total
      and
   
        and
  and
  Energy
  Reportable
  All
  Intersegment
  Total
    Utility   Storage   Production   Marketing   Segments   Other   Eliminations   Consolidated
    (Thousands)
 
Revenue from External Customers
  $ 804,466     $ 138,905     $ 438,028     $ 344,802     $ 1,726,201     $ 33,428     $ 874     $ 1,760,503  
Intersegment Revenues
  $ 15,324     $ 79,978     $     $     $ 95,302     $ 2,315     $ (97,617 )   $  
Interest Income
  $ 2,144     $ 199     $ 980     $ 44     $ 3,367     $ 137     $ 225     $ 3,729  
Interest Expense
  $ 35,831     $ 26,328     $ 30,853     $ 27     $ 93,039     $ 2,152     $ (1,245 )   $ 93,946  
Depreciation, Depletion and Amortization
  $ 40,370     $ 35,930     $ 106,182     $ 42     $ 182,524     $ 7,907     $ 768     $ 191,199  
Income Tax Expense (Benefit)
  $ 31,858     $ 22,634     $ 78,875     $ 4,806     $ 138,173     $ 464     $ (1,410 )   $ 137,227  
Income from Unconsolidated Subsidiaries
  $     $     $     $     $     $ 2,488     $     $ 2,488  
Segment Profit: Income (Loss) from Continuing Operations
  $ 62,473     $ 36,703     $ 112,531     $ 8,816     $ 220,523     $ 3,396     $ (4,786 )   $ 219,133  
Expenditures for Additions to Long-Lived Assets from Continuing Operations
  $ 57,973     $ 37,894     $ 398,174     $ 407     $ 494,448     $ 6,694     $ 210     $ 501,352  
                                                                 
                                                                 
    At September 30, 2010
    (Thousands)
Segment Assets
  $ 2,071,530     $ 1,094,914     $ 1,539,705     $ 69,561     $ 4,775,710     $ 198,706     $ 131,209     $ 5,105,625  
 
                                                                 
    Year Ended September 30, 2009
                            Corporate
   
        Pipeline
  Exploration
      Total
      and
   
        and
  and
  Energy
  Reportable
  All
  Intersegment
  Total
    Utility   Storage   Production   Marketing   Segments   Other   Eliminations   Consolidated
    (Thousands)
 
Revenue from External Customers
  $ 1,097,550     $ 137,478     $ 382,758     $ 397,763     $ 2,015,549     $ 35,100     $ 894     $ 2,051,543  
Intersegment Revenues
  $ 15,474     $ 81,795     $     $ 558     $ 97,827     $     $ (97,827 )   $  
Interest Income
  $ 2,486     $ 995     $ 2,430     $ 79     $ 5,990     $ 583     $ (797 )   $ 5,776  
Interest Expense
  $ 32,417     $ 21,580     $ 33,368     $ 215     $ 87,580     $ 2,344     $ (3,135 )   $ 86,789  
Depreciation, Depletion and Amortization
  $ 39,675     $ 35,115     $ 90,816     $ 42     $ 165,648     $ 4,276     $ 696     $ 170,620  
Income Tax Expense (Benefit)
  $ 37,097     $ 30,579     $ (14,616 )   $ 4,470     $ 57,530     $ (3,482 )   $ (1,189 )   $ 52,859  
Income from Unconsolidated Subsidiaries
  $     $     $     $     $     $ 3,366     $     $ 3,366  
Significant Non-Cash Item: Impairment of Oil and Gas Producing Properties
  $     $     $ 182,811     $     $ 182,811     $     $     $ 182,811  
Significant Non-Cash Item: Impairment of Investment in Partnership
  $     $     $     $     $     $ 1,804 (1)   $     $ 1,804  
Segment Profit: Income (Loss) from Continuing Operations
  $ 58,664     $ 47,358     $ (10,238 )   $ 7,166     $ 102,950     $ 705     $ (171 )   $ 103,484  
Expenditures for Additions to Long-Lived Assets from Continuing Operations
  $ 56,178     $ 52,504     $ 223,223 (2)   $ 25     $ 331,930     $ 9,507     $ (47 )   $ 341,390  
                                                                 
                                                                 
    At September 30, 2009
    (Thousands)
 
Segment Assets
  $ 2,132,610     $ 1,046,372     $ 1,265,678     $ 52,469     $ 4,497,129     $ 210,809 (3)   $ 61,191     $ 4,769,129  
 
 
(1) Amount represents the impairment in the value of the Company's 50% investment in ESNE, a partnership that owns an 80-megawatt, combined cycle, natural gas-fired power plant in the town of North East, Pennsylvania.
 
(2) Amount includes the acquisition of Ivanhoe Energy's United States oil and gas operation for $34.9 million, net of cash acquired, and is discussed in Note M — Acquisition.
 
(3) Amount includes $28,761 of assets of the Company's landfill gas operations, which have been classified as discontinued operations as of September 30, 2010. (See Note J — Discontinued Operations).
 
                                                                 
    Year Ended September 30, 2008
                            Corporate
   
        Pipeline
  Exploration
      Total
      and
   
        and
  and
  Energy
  Reportable
  All
  Intersegment
  Total
    Utility   Storage   Production   Marketing   Segments   Other   Eliminations   Consolidated
    (Thousands)
 
Revenue from External Customers
  $ 1,194,657     $ 135,052     $ 466,760     $ 549,932     $ 2,346,401     $ 49,741     $ 695     $ 2,396,837  
Intersegment Revenues
  $ 15,612     $ 81,504     $     $ 1,300     $ 98,416     $ 9     $ (98,425 )   $  
Interest Income
  $ 1,836     $ 843     $ 10,921     $ 323     $ 13,923     $ 1,232     $ (4,340 )   $ 10,815  
Interest Expense
  $ 27,683     $ 13,783     $ 41,645     $ 175     $ 83,286     $ 3,183     $ (13,099 )   $ 73,370  
Depreciation, Depletion and Amortization
  $ 39,113     $ 32,871     $ 92,221     $ 42     $ 164,247     $ 4,910     $ 689     $ 169,846  
Income Tax Expense (Benefit)
  $ 36,303     $ 34,008     $ 92,686     $ 3,180     $ 166,177     $ 1,936     $ (441 )   $ 167,672  
Income from Unconsolidated Subsidiaries
  $     $     $     $     $     $ 6,303     $     $ 6,303  
Segment Profit: Income (Loss) from Continuing Operations
  $ 61,472     $ 54,148     $ 146,612     $ 5,889     $ 268,121     $ 3,958     $ (5,172 )   $ 266,907  
Expenditures for Additions to Long-Lived Assets from Continuing Operations
  $ 57,457     $ 165,520     $ 192,187     $ 39     $ 415,203     $ 1,354     $ (2,186 )   $ 414,371  
                                                                 
                                                                 
    At September 30, 2008
    (Thousands)
 
Segment Assets
  $ 1,643,665     $ 948,984     $ 1,416,120     $ 89,527     $ 4,098,296     $ 217,874 (1)   $ (185,983 )   $ 4,130,187  
 
 
(1) Amount includes $35,521 of assets of the Company's landfill gas operations, which have been classified as discontinued operations as of September 30, 2010. (See Note J — Discontinued Operations).
 
                         
    For the Year Ended September 30  
Geographic Information   2010     2009     2008  
    (Thousands)  
 
Revenues from External Customers(1):
                       
United States
  $ 1,760,503     $ 2,051,543     $ 2,396,837  
                         
 
                         
    At September 30  
    2010     2009     2008  
    (Thousands)  
 
Long-Lived Assets:
                       
United States
  $ 4,330,248     $ 3,963,398     $ 3,595,188  
Assets of Discontinued Operations
          28,761       35,521  
                         
    $ 4,330,248     $ 3,992,159     $ 3,630,709  
                         
 
 
(1) Revenue is based upon the country in which the sale originates. This table excludes revenues from discontinued operations of $9,919, $6,309 and $3,524 for September 30, 2010, 2009 and 2008, respectively.
Investments in Unconsolidated Subsidiaries
Investments in Unconsolidated Subsidiaries
Note L — Investments in Unconsolidated Subsidiaries
 
The Company's unconsolidated subsidiaries consist of equity method investments in Seneca Energy, Model City, and ESNE. The Company has 50% interests in each of these entities. Seneca Energy and Model City generate and sell electricity using methane gas obtained from landfills owned by outside parties. ESNE is an 80-megawatt, combined cycle, natural gas-fired 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 ESNE's major assets, such as the turbines.
 
During the quarter ended December 31, 2008, the Company recorded a pre-tax impairment of $1.8 million ($1.1 million on an after-tax basis) of its equity investment in ESNE due to a decline in the fair market value of ESNE. The impairment was driven by a significant decrease in "run time" for the plant given the economic downturn and the resulting decrease in demand for electric power.
 
A summary of the Company's investments in unconsolidated subsidiaries at September 30, 2010 and 2009 is as follows:
 
                 
    At September 30  
    2010     2009  
    (Thousands)  
 
Seneca Energy
  $ 11,007     $ 10,924  
Model City
    2,017       2,136  
ESNE
    1,804       1,880  
                 
    $ 14,828     $ 14,940  
                 
 
Acquisition
Acquisition
Note M — Acquisition
 
On July 20, 2009, the Company's wholly-owned subsidiary in the Exploration and Production segment, Seneca, acquired all of the shares of Ivanhoe Energy's United States oil and gas operations for approximately $39.2 million in cash (including cash acquired), of which $2.0 million was held in escrow at September 30, 2010 and 2009. Seneca placed this amount in escrow as part of the purchase price. Currently, the Company and Ivanhoe Energy are negotiating a final resolution to the issue of whether Ivanhoe Energy is entitled to some or all of the amount held in escrow. Ivanhoe Energy's United States oil and gas operations were incorporated into the Company's consolidated financial statements for the period subsequent to the completion of the acquisition on July 20, 2009. As of the acquisition date, these assets produced approximately 645 (595 net) barrels per day of oil in California and Texas. The purchase also included certain exploration acreage in California. This acquisition added to the Company's existing oil producing assets in the Midway Sunset Field in California. The acquisition consisted of approximately $37.1 million in property, plant and equipment, $6.2 million of current assets (including $2.0 million of cash held in escrow), $0.3 million of current liabilities and $3.8 million of deferred credits. Details of the acquisition are as follows (all figures in thousands):
 
         
Assets Acquired
  $ 43,282  
Liabilities Assumed
    (4,082 )
Cash Acquired at Acquisition
    (4,267 )
         
Cash Paid, Net of Cash Acquired
  $ 34,933  
         
Intangible Assets
Intangible Assets
Note N — Intangible Assets
 
As a result of the Empire and Toro acquisitions in 2003, the Company acquired certain intangible assets. In the case of the Empire acquisition, the intangible assets represent the fair value of various long-term transportation contracts with Empire's customers. These intangible assets are being amortized over the lives of the transportation contracts with no residual value at the end of the amortization period. The weighted-average amortization period for the gross carrying amount of the transportation contracts is 8 years. In the case of the Toro acquisition, the intangible assets represented the fair value of various long-term gas purchase contracts with the various landfills. On September 1, 2010, the Company sold its landfill gas operations in the states of Ohio, Michigan, Kentucky, Missouri, Maryland and Indiana and these operations have been presented as discontinued operations in the Company's financial statements as of September 30, 2010. Refer to Note J — Discontinued Operations for further details. Details of these intangible assets are as follows (in thousands):
 
                                 
          At September 30,
 
    At September 30, 2010     2009  
    Gross Carrying
    Accumulated
    Net Carrying
    Net Carrying
 
    Amount     Amortization     Amount     Amount  
 
Intangible Assets Subject to Amortization:
                               
Long-Term Transportation Contracts
  $ 4,701     $ (3,024 )   $ 1,677     $ 2,071  
Long-Term Gas Purchase Contracts
                      19,465  
                                 
    $ 4,701     $ (3,024 )   $ 1,677     $ 21,536  
                                 
Aggregate Amortization Expense:
                               
For the Year Ended September 30, 2010
  $ 394                          
For the Year Ended September 30, 2009
  $ 4,638 (1)                        
For the Year Ended September 30, 2008
  $ 2,662 (1)                        
 
 
(1) Amount includes amortization expense from discontinued operations of $4,186 and $1,593 for September 30, 2009 and 2008, respectively. At September 30, 2010, the 11 months of amortization expense for discontinued operations was $1,286.
 
In September 2009, the Company recorded a pre-tax impairment of $4.6 million in the value of certain long-lived assets in the All Other category due to the loss of the primary customer at one of Toro's landfill gas sites and the anticipated shut-down of the site. The impairment was comprised of a $2.6 million reduction in intangible assets related to long-term gas purchase contracts and a $2.0 million reduction in property, plant and equipment. The $2.6 million intangible assets impairment was recorded to Purchased Gas expense and the $2.0 million property, plant and equipment impairment was recorded to Depreciation, Depletion and Amortization expense on the Consolidated Statement of Income. The $2.6 million impairment of the intangible asset is included in amortization expense for the year ended September 30, 2009 in the table shown above. As noted above, the Company's landfill gas operations were sold in September 2010 and have been presented as discontinued operations on the Company's financial statements. Therefore, this impairment has been included in discontinued operations.
 
In conjunction with the sale of the Company's landfill gas operations, the carrying amount of intangible assets subject to amortization related to the long-term gas purchase contracts was reduced from a $31.9 million gross carrying amount ($19.5 million net carrying amount) at September 30, 2009 to zero at September 30, 2010. Aside from this change, the only activity with regard to intangible assets subject to amortization was amortization expense as shown in the table above. Amortization expense for the long-term transportation contracts is estimated to be $0.4 million annually for 2011, 2012, 2013 and 2014 and $0.1 million in 2015.
Quarterly Financial Data (unaudited)
Quarterly Financial Data (unaudited)
Note O — Quarterly Financial Data (unaudited)
 
In the opinion of management, the following quarterly information includes all adjustments necessary for a fair statement of the results of operations for such periods. Per common share amounts are calculated using the weighted average number of shares outstanding during each quarter. The total of all quarters may differ from the per common share amounts shown on the Consolidated Statements of Income. Those per common share amounts are based on the weighted average number of shares outstanding for the entire fiscal year. Because of the seasonal nature of the Company's heating business, there are substantial variations in operations reported on a quarterly basis.
                                                                         
                    Net
  Earnings from
       
            Income
  Income
  Income
  Continuing
       
            (Loss) from
  (Loss) from
  (Loss)
  Operations per
  Earnings per
Quarter
  Operating
  Operating
  Continuing
  Discontinued
  Available for
  Common Share   Common Share
Ended   Revenues   Income (Loss)   Operations   Operations   Common Stock   Basic   Diluted   Basic   Diluted
    (Thousands, except per common share amounts)
 
2010
                                                                       
9/30/2010
  $ 286,396     $ 73,995     $ 32,393     $ 6,009 (1)   $ 38,402 (1)   $ 0.40     $ 0.39     $ 0.47     $ 0.46  
6/30/2010
  $ 351,992     $ 89,188     $ 42,641     $ (57 )   $ 42,584     $ 0.52     $ 0.51     $ 0.52     $ 0.51  
3/31/2010
  $ 667,980     $ 151,631     $ 79,874     $ 554     $ 80,428     $ 0.98     $ 0.96     $ 0.99     $ 0.97  
12/31/2009
  $ 454,135     $ 125,637     $ 64,225     $ 274     $ 64,499     $ 0.80     $ 0.78     $ 0.80     $ 0.78  
2009
                                                                       
9/30/2009
  $ 276,795     $ 68,943     $ 29,943     $ (2,945 )(2)   $ 26,998 (2)   $ 0.37     $ 0.37     $ 0.34     $ 0.33  
6/30/2009
  $ 365,579     $ 87,472     $ 43,061     $ (157 )   $ 42,904     $ 0.54     $ 0.53     $ 0.54     $ 0.53  
3/31/2009
  $ 803,049     $ 137,818     $ 73,270     $ 214     $ 73,484     $ 0.92     $ 0.92     $ 0.92     $ 0.92  
12/31/2008
  $ 606,120     $ (66,639 )   $ (42,790 )(3)   $ 112     $ (42,678 )(3)   $ (0.54 )   $ (0.53 )   $ (0.54 )   $ (0.53 )
 
 
(1) Includes a $6.3 million gain on the sale of the Company's landfill gas operations.
 
(2) Includes a non-cash $4.6 million impairment charge ($2.8 million after tax) associated with landfill gas assets.
 
(3) Includes a non-cash $182.8 million impairment charge ($108.2 million after tax) associated with the Exploration and Production segment's oil and gas producing properties; a non-cash $1.8 million impairment charge ($1.1 million after tax) associated with an equity investment in the All Other category and a $2.3 million gain realized on life insurance policies in the Corporate category.
Supplementary Information for Oil and Gas Producing Activities (unaudited)
Supplementary Information for Oil and Gas Producing Activities (unaudited)
Note Q — Supplementary Information for Oil and Gas Producing Activities (unaudited)
 
As of September 30, 2010, the Company adopted the revisions to authoritative guidance related to oil and gas exploration and production activities that aligned the reserve estimation and disclosure requirements with the requirements of the SEC Modernization of Oil and Gas Reporting rule, which the Company also adopted. The new SEC rules require companies to value their year-end reserves using 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 following supplementary information is presented in accordance with the authoritative guidance regarding disclosures about oil and gas producing activities and related SEC accounting rules. All monetary amounts are expressed in U.S. dollars.
 
Capitalized Costs Relating to Oil and Gas Producing Activities
 
                 
    At September 30  
    2010     2009  
    (Thousands)  
 
Proved Properties(1)
  $ 2,267,009     $ 1,953,720  
Unproved Properties
    151,232       70,061  
                 
      2,418,241       2,023,781  
Less — Accumulated Depreciation, Depletion and Amortization
    1,094,377       990,284  
                 
    $ 1,323,864     $ 1,033,497  
                 
 
 
(1) Includes asset retirement costs of $69.8 million and $65.9 million at September 30, 2010 and 2009, respectively.
 
Costs related to unproved properties are excluded from amortization until proved reserves are found or it is determined that the unproved properties are impaired. All costs related to unproved properties are reviewed quarterly to determine if impairment has occurred. The amount of any impairment is transferred to the pool of capitalized costs being amortized. Following is a summary of costs excluded from amortization at September 30, 2010:
 
                                         
    Total
                         
    as of
                         
    September 30,
    Year Costs Incurred  
    2010     2010     2009     2008     Prior  
    (Thousands)  
 
Acquisition Costs
  $ 131,039     $ 75,130     $ 40,978     $ 6,135     $ 8,796  
Development Costs
    12,120       12,120                    
Exploration Costs
    7,017       7,017                    
Capitalized Interest
    1,056       1,056                    
                                         
    $ 151,232 (1)   $ 95,323     $ 40,978     $ 6,135     $ 8,796  
                                         
 
 
(1) Costs related to unproved properties excluded from amortization includes $137.2 million related to onshore properties and $14.0 million related to offshore properties at September 30, 2010.
 
Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities
 
                         
    Year Ended September 30  
    2010     2009     2008  
    (Thousands)  
 
United States
                       
Property Acquisition Costs:
                       
Proved
  $ 790     $ 35,803     $ 16,474  
Unproved
    80,221       44,528       8,449  
Exploration Costs
    75,155 (1)     11,724       56,274  
Development Costs
    234,094 (2)     125,109       106,975  
Asset Retirement Costs
    3,901       2,877       20,048  
                         
    $ 394,161     $ 220,041     $ 208,220  
                         
 
 
(1) Amount for 2010 includes $0.2 million of capitalized interest.
 
(2) Amount for 2010 includes $0.9 million of capitalized interest.
 
For the years ended September 30, 2010, 2009 and 2008, the Company spent $28.9 million, $24.2 million and $25.4 million, respectively, developing proved undeveloped reserves.
 
Results of Operations for Producing Activities
 
                         
    Year Ended September 30  
    2010     2009     2008  
    (Thousands, except per Mcfe amounts)  
 
United States
                       
Operating Revenues:
                       
Natural Gas (includes revenues from sales to affiliates of $253, $239 and $443, respectively)
  $ 152,163     $ 106,815     $ 216,623  
Oil, Condensate and Other Liquids
    233,569       174,356       305,887  
                         
Total Operating Revenues(1)
    385,732       281,171       522,510  
Production/Lifting Costs
    61,398       53,957       55,335  
Franchise/Ad Valorem Taxes
    10,592       8,657       11,350  
Accretion Expense
    5,444       5,437       4,056  
Depreciation, Depletion and Amortization ($2.10, $2.10 and $2.23 per Mcfe of production)
    104,092       89,307       91,093  
Impairment of Oil and Gas Producing Properties(2)
          182,811        
Income Tax Expense (Benefit)
    83,946       (27,055 )     144,922  
                         
Results of Operations for Producing Activities (excluding corporate overheads and interest charges)
  $ 120,260     $ (31,943 )   $ 215,754  
                         
 
 
(1) Exclusive of hedging gains and losses. See further discussion in Note G — Financial Instruments.
 
(2) See discussion of impairment in Note A — Summary of Significant Accounting Policies.
 
Reserve Quantity Information
 
The Company's proved oil and gas reserves are located in the United States. The Company's proved oil and gas reserve estimates are prepared by the Company's reservoir engineers who meet the qualifications of Reserve Estimator per the "Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserve Information" promulgated by the Society of Petroleum Engineers as of February 19, 2007. The Company maintains comprehensive internal reserve guidelines and a continuing education program designed to keep its staff up to date with current SEC regulations and guidance.
 
The Company's Vice President of Reservoir Engineering is the primary technical person responsible for overseeing the Company's reserve estimation process and engaging and overseeing the third party reserve audit. His qualifications include a Bachelor of Science Degree in Petroleum Engineering and over 25 years of Petroleum Engineering experience with both major and independent oil and gas companies. He has maintained oversight of the Company's reserve estimation process for the past seven years. He is a member of the Society of Petroleum Engineers and a Registered Professional Engineer in the State of Texas.
 
The Company maintains a system of internal controls over the reserve estimation process. Management reviews the price, heat content, lease operating cost and future investment assumptions used in the economic model to determine the reserves. The Vice President of Reservoir Engineering reviews and approves all new reserve assignments and significant reserve revisions. Access to the Reserve database is restricted. Significant changes to the reserve report are reviewed by senior management on a quarterly basis. Periodically, the Company's internal audit department assesses the design of these controls and performs testing to determine the effectiveness of such controls.
 
All of the Company's reserve estimates are audited annually by Netherland, Sewell and Associates, Inc. (NSAI). Since 1961, NSAI has evaluated gas and oil properties and independently certified petroleum reserve quantities in the United States and internationally under the Texas Board of Professional Engineers Registration No. F-002699. The primary technical persons (employed by NSAI) that are responsible for leading the audit include an engineer registered with the State of Texas (with 12 years of experience in petroleum engineering and six years of experience in the estimation and evaluation of reserves) and a Certified Petroleum Geologist and Geophysicist in the State of Texas (with 32 years of experience in petroleum geosciences and 21 years of experience in the estimation and evaluation of reserves).
 
The reliable technologies that were utilized in estimating the reserves include wire line open-hole log data, performance data, log cross sections, core data, and statistical analysis. The statistical method utilized production performance from both the Company's and competitor's wells. Geophysical data include data from the Company's wells, published documents, and state data-sites and were used to confirm continuity of the formation. Extension and discovery reserves added as a result of reliable technologies were not material.
 
                                 
    Gas MMcf  
    U. S.        
    Gulf
    West
             
    Coast
    Coast
    Appalachian
    Total
 
    Region     Region     Region     Company  
 
Proved Developed and Undeveloped Reserves:
                               
September 30, 2007
    25,136       73,175       107,078       205,389  
Extensions and Discoveries
    8,759             31,322       40,081  
Revisions of Previous Estimates
    2,156       566       (3,460 )     (738 )
Production
    (11,033 )     (4,039 )     (7,269 )     (22,341 )
Purchases of Minerals in Place
          4,539       727       5,266  
Sales of Minerals in Place
    (377 )     (1,381 )           (1,758 )
                                 
September 30, 2008
    24,641       72,860       128,398       225,899  
Extensions and Discoveries
    6,698       3,282       49,249       59,229  
Revisions of Previous Estimates
    9,407       488       (19,484 )     (9,589 )(1)
Production
    (9,886 )     (4,063 )     (8,335 )     (22,284 )
Purchases of Minerals in Place
          392             392  
Sales of Minerals in Place
    (4,693 )                 (4,693 )
                                 
September 30, 2009
    26,167       72,959       149,828       248,954  
Extensions and Discoveries
    2,881       269       189,979 (2)     193,129  
Revisions of Previous Estimates
    6,683       2,315       7,677       16,675  
Production
    (10,304 )     (3,819 )     (16,222 )(3)     (30,345 )
                                 
September 30, 2010
    25,427       71,724       331,262       428,413  
                                 
                                 
    Gas MMcf  
    U. S.        
    Gulf
    West
             
    Coast
    Coast
    Appalachian
    Total
 
    Region     Region     Region     Company  
 
Proved Developed Reserves:
                               
September 30, 2007
    25,136       66,017       96,674       187,827  
September 30, 2008
    18,242       68,453       115,824       202,519  
September 30, 2009
    18,051       67,603       120,579       206,233  
September 30, 2010
    19,293       66,178       210,817       296,288  
Proved Undeveloped Reserves:
                               
September 30, 2007
          7,158       10,404       17,562  
September 30, 2008
    6,399       4,407       12,574       23,380  
September 30, 2009
    8,116       5,356       29,249       42,721  
September 30, 2010
    6,134       5,546       120,445       132,125  
 
 
(1) During 2009, the Company made a downward revision of its proved developed and undeveloped reserves amounting to 9,589 MMcf. This was primarily attributable to a 19,484 MMcf reduction in the Appalachian region offset by a 9,407 MMcf increase in the Gulf Coast region. The reduction in the Appalachian region was mainly due to declining natural gas prices, which made certain reserves uneconomical. The improvement in the Gulf Coast region was due to improved performance of Gulf Coast properties.
 
(2) Extensions and discoveries include 182 Bcf of Marcellus Shale gas in the Appalachian Region.
 
(3) Production includes 7,180 MMcf from Marcellus Shale fields (which exceed 15% of total reserves).
 
                                 
    Oil Mbbl  
    U. S.        
    Gulf
    West
             
    Coast
    Coast
    Appalachian
    Total
 
    Region     Region     Region     Company  
 
Proved Developed and Undeveloped Reserves:
                               
September 30, 2007
    1,435       45,644       507       47,586  
Extensions and Discoveries
    298       471       58       827  
Revisions of Previous Estimates
    203       (34 )     (64 )     105  
Production
    (505 )     (2,460 )(1)     (105 )     (3,070 )
Purchases of Minerals in Place
          2,084             2,084  
Sales of Minerals in Place
    (73 )     (1,261 )           (1,334 )
                                 
September 30, 2008
    1,358       44,444       396       46,198  
Extensions and Discoveries
    302       896       15       1,213  
Revisions of Previous Estimates
    447       43       (41 )     449  
Production
    (640 )     (2,674 )(1)     (59 )     (3,373 )
Purchases of Minerals in Place
          2,115             2,115  
Sales of Minerals in Place
    (15 )                 (15 )
                                 
September 30, 2009
    1,452       44,824       311       46,587  
Extensions and Discoveries
    222       828       4       1,054  
Revisions of Previous Estimates
    332       484       2       818  
Production
    (502 )     (2,669 )(1)     (49 )     (3,220 )
                                 
September 30, 2010
    1,504       43,467       268       45,239  
                                 
Proved Developed Reserves:
                               
September 30, 2007
    1,435       36,509       483       38,427  
September 30, 2008
    1,313       37,224       357       38,894  
September 30, 2009
    1,194       37,711       285       39,190  
September 30, 2010
    1,066       36,353       263       37,682  
Proved Undeveloped Reserves:
                               
September 30, 2007
          9,135       24       9,159  
September 30, 2008
    45       7,220       39       7,304  
September 30, 2009
    258       7,113       26       7,397  
September 30, 2010
    438       7,114       5       7,557  
 
 
(1) The Midway Sunset North fields (which exceed 15% of total reserves) contributed 1,583 Mbbls, 1,680 Mbbls, and 1,543 Mbbls of production during 2008, 2009, and 2010, respectively.
 
The Company's proved undeveloped (PUD) reserves increased from 87 Bcfe at September 30, 2009 to 177 Bcfe at September 30, 2010. Undeveloped reserves in the Marcellus Shale increased from 11 Bcf at September 30, 2009 to 110 Bcf at September 30, 2010. There was a material increase in undeveloped reserves at September 30, 2010 as a result of its Marcellus Shale reserve additions. The increase in undeveloped reserves in the Marcellus Shale is partially attributable to the change in SEC regulations allowing the recognition of PUD reserves more than one direct offset location away from existing production with reasonable certainty using reliable technology. The Company's total PUD reserves are 25% of total proved reserves at September 30, 2010, up from 16% of total proved reserves at September 30, 2009.
 
The increase in PUD reserves in 2010 of 90 Bcfe is a result of 111 Bcfe in new PUD reserve additions (105 Bcfe from the Marcellus Shale), offset by 17 Bcfe in PUD conversions to developed reserves and 4 Bcfe in downward PUD revisions. The downward revisions were primarily from the removal of 51 PUD locations in the Upper Devonian play. This was the result of Seneca's decision in 2010 to significantly reduce its 5-year investment plan for the Upper Devonian as a result of lower forward gas price expectations. The Company invested $28.9 million during the year ended September 30, 2010 to convert 17 Bcfe of PUD reserves to developed reserves. This represents 19% of the PUD reserves booked at September 30, 2009. In 2011, the Company estimates that it will invest approximately $140 million to develop the PUD reserves. The Company is committed to developing its PUD reserves within five years of being recorded as PUD reserves as required by the SEC's final rule on Modernization of Oil and Gas Reporting.
 
At September 30, 2010, the Company does not have a material concentration of proved undeveloped reserves that have been on the books for more than five years at the corporate level or country level. All of the Company's proved reserves are in the United States. At the field level, only at the North Lost Hills Field in Kern County, California, does the Company have a material concentration of undeveloped reserves that have been on the books for more than five years. The Company has reduced the concentration of undeveloped reserves in this field from 61% of total field level reserves at September 30, 2005 to 24% of total field level reserves at September 30, 2010. The Company has been actively drilling undeveloped locations in this field for four out of the past five years, drilling 53 undeveloped locations and converting 3.1 million barrels of proved reserves from undeveloped to developed reserves. The undeveloped reserves in this field represent less than 2% of the Company's proved reserves at the corporate level. The Company is committed to drilling the remaining proved undeveloped locations within five years of being recorded as PUD reserves.
 
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves
 
The Company cautions that the following presentation of the standardized measure of discounted future net cash flows is intended to be neither a measure of the fair market value of the Company's oil and gas properties, nor an estimate of the present value of actual future cash flows to be obtained as a result of their development and production. It is based upon subjective estimates of proved reserves only and attributes no value to categories of reserves other than proved reserves, such as probable or possible reserves, or to unproved acreage. Furthermore, as a result of the SEC's final rule on Modernization of Oil and Gas Reporting (effective fiscal 2010), it is based on the 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 and costs adjusted only for existing contractual changes. It assumes an arbitrary discount rate of 10%. Thus, it gives no effect to future price and cost changes certain to occur under widely fluctuating political and economic conditions.
 
The standardized measure is intended instead to provide a means for comparing the value of the Company's proved reserves at a given time with those of other oil- and gas-producing companies than is provided by a simple comparison of raw proved reserve quantities.
 
                         
    Year Ended September 30  
    2010     2009     2008  
    (Thousands)  
 
United States
                       
Future Cash Inflows
  $ 5,273,605     $ 3,972,026     $ 5,845,214  
Less:
                       
Future Production Costs
    1,347,855       1,010,851       1,231,705  
Future Development Costs
    445,413       312,717       265,515  
Future Income Tax Expense at Applicable Statutory Rate
    1,186,567       916,466       1,645,351  
                         
Future Net Cash Flows
    2,293,770       1,731,992       2,702,643  
Less:
                       
10% Annual Discount for Estimated Timing of Cash Flows
    1,120,182       856,015       1,434,799  
                         
Standardized Measure of Discounted Future Net Cash Flows
  $ 1,173,588     $ 875,977     $ 1,267,844  
                         
 
The principal sources of change in the standardized measure of discounted future net cash flows were as follows:
 
                         
    Year Ended September 30  
    2010     2009     2008  
    (Thousands)  
 
United States
                       
Standardized Measure of Discounted Future
                       
Net Cash Flows at Beginning of Year
  $ 875,977     $ 1,267,844     $ 1,060,462  
Sales, Net of Production Costs
    (313,742 )     (218,557 )     (455,825 )
Net Changes in Prices, Net of Production Costs
    176,530       (699,217 )     509,705  
Purchases of Minerals in Place
          38,902       67,768  
Sales of Minerals in Place
          (20,141 )     (31,642 )
Extensions and Discoveries
    329,555       66,002       143,394  
Changes in Estimated Future Development Costs
    (17,353 )     (22,392 )     (100,684 )
Previously Estimated Development Costs Incurred
    47,539       53,285       65,156  
Net Change in Income Taxes at Applicable Statutory Rate
    (85,703 )     331,251       (119,585 )
Revisions of Previous Quantity Estimates
    46,246       (27,864 )     (3,936 )
Accretion of Discount and Other
    114,539       106,864       133,031  
                         
Standardized Measure of Discounted Future Net Cash Flows at End of Year
  $ 1,173,588     $ 875,977     $ 1,267,844  
                         


Schedule II - Valuation and Qualifying Accounts
Schedule II - Valuation and Qualifying Accounts
 
                                         
          Additions
                   
    Balance
    Charged
    Additions
          Balance
 
    at
    to
    Charged
          at
 
    Beginning
    Costs
    to
          End
 
    of
    and
    Other
          of
 
Description   Period     Expenses     Accounts(1)     Deductions(2)     Period  
 
Year Ended September 30, 2010
                                       
Allowance for Uncollectible Accounts
  $ 38,334     $ 15,422     $ 2,268     $ 25,063     $ 30,961  
                                         
Year Ended September 30, 2009
                                       
Allowance for Uncollectible Accounts
  $ 33,117     $ 31,464     $ 2,751     $ 28,998     $ 38,334  
                                         
Year Ended September 30, 2008
                                       
Allowance for Uncollectible Accounts
  $ 28,654     $ 27,274     $ 2,734     $ 25,545     $ 33,117  
                                         
 
 
(1) Represents the discount on accounts receivable purchased in accordance with the Utility segment's 2005 New York rate agreement.
 
(2) Amounts represent net accounts receivable written-off.