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Note A — Summary of Significant Accounting Policies
Principles of Consolidation
The Company consolidates all entities in which it has a controlling financial interest. The equity method is used to account for entities in which the Company has a non-controlling financial interest. 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.
During the quarter ended March 31, 2011, the Company sold its 50% equity method investments in Seneca Energy and Model City for $59.4 million, resulting in a gain of $50.9 million. Seneca Energy and Model City generate and sell electricity using methane gas obtained from landfills owned by outside parties.
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.
Reclassifications and Revisions
Certain prior year amounts have been reclassified to conform with current year presentation. This includes the reclassification of $63.7 million from Other Regulatory Liabilities to Other Regulatory Assets on the Consolidated Balance Sheet at September 30, 2011. This reclassification pertains to pension and post-retirement benefit regulatory asset and regulatory liability balances. The Company has switched from a “gross” presentation to a “net” presentation, which is consistent with the methodology used by the various regulators in analyzing such regulatory asset and liability balances. This reclassification did not impact the Consolidated Statement of Income and there was an immaterial impact to the Consolidated Statement of Cash Flows.
The Company also reclassified $26.6 million from Other Regulatory Assets to Other Current Assets and $13.8 million from Other Regulatory Liabilities to Other Accruals and Current Liabilities on the Consolidated Balance Sheet at September 30, 2011. The reclassification was made to distinguish long-term regulatory assets and liabilities from current regulatory assets and liabilities. Current regulatory assets are defined as assets recoverable from ratepayers over a twelve-month period. Current regulatory liabilities are defined as liabilities payable to ratepayers over a twelve-month period. These reclassifications did not impact the Consolidated Statement of Income and there was an immaterial impact to the Consolidated Statement of Cash Flows.
Revisions were made on the Consolidated Statement of Cash Flows for the years ended September 30, 2011 and September 30, 2010 to reflect non-cash investing activities embedded in Accounts Payable on the Consolidated Balance Sheets at September 30, 2011, September 30, 2010 and September 30, 2009. These revisions reduced the cash inflow related to Accounts Payable for the years ended September 30, 2011 and September 30, 2010 by $16.7 million and $12.7 million, respectively, and reduced capital expenditures by the same amounts. The effect of these revisions was to reduce Net Cash Provided by Operating Activities for the years ended September 30, 2011 and September 30, 2010 and to reduce Net Cash Used in Investing Activities for the years ended September 30, 2011 and September 30, 2010.
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 and Empire bill their 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 or Empire.
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.
In April 2011, the Company completed the sale of its off-shore oil and natural gas properties in the Gulf of Mexico. The Company received net proceeds of $55.4 million from this sale. The Company also eliminated the asset retirement obligation associated with its off-shore oil and gas properties. This obligation amounted to $37.5 million and was accounted for as a reduction of capitalized costs under the full cost method of accounting for oil and natural gas properties as well as a reduction of the asset retirement obligation. Asset retirement obligations are discussed further in Note B – Asset Retirement Obligations.
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. The natural gas and oil prices used to calculate the full cost ceiling 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, 2012, 2011, and 2010, estimated future net cash flows were increased by $128.4 million, $35.4 million and $65.4 million, respectively. At September 30, 2012, the ceiling exceeded the book value of the oil and gas properties by approximately $55.3 million.
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 |
|
|
2012 |
2011 |
|
(Thousands) |
|
Utility................................................................................................................................................................................................... |
$ 1,737,645
|
$ 1,695,702
|
Pipeline and Storage..................................................................................................................................................................... |
1,406,433 | 1,260,301 |
Exploration and Production........................................................................................................................................................ |
2,828,358 | 2,042,225 |
Energy Marketing........................................................................................................................................................................... |
2,865 | 2,095 |
All Other and Corporate............................................................................................................................................................... |
196,593 | 127,291 |
|
$ 6,171,894
|
$ 5,127,614
|
Average depreciation, depletion and amortization rates are as follows:
|
Year Ended September 30 |
||
|
2012 |
2011 |
2010 |
Utility............................................................................................................................................................................................ |
2.6% | 2.6% | 2.6% |
Pipeline and Storage.............................................................................................................................................................. |
2.9% | 3.1% | 3.0% |
Exploration and Production, per Mcfe(1)...................................................................................................................... |
$ 2.25
|
$ 2.17
|
$ 2.14
|
Energy Marketing.................................................................................................................................................................... |
3.6% | 2.5% | 2.9% |
All Other and Corporate........................................................................................................................................................ |
1.8% | 1.3% | 6.8% |
(1) | Amounts include depletion of oil and gas producing properties as well as depreciation of fixed assets. As disclosed in Note N — Supplementary Information for Oil and Gas Producing Properties, depletion of oil and gas producing properties amounted to $2.19, $2.12 and $2.10 per Mcfe of production in 2012, 2011 and 2010, respectively. |
Goodwill
The Company has recognized goodwill of $5.5 million as of September 30, 2012 and 2011 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, 2012, 2011 and 2010, 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 2012, 2011 or 2010.
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 2012, 2011 or 2010.
Accumulated Other Comprehensive Income (Loss)
The components of Accumulated Other Comprehensive Income (Loss) are as follows:
|
Year Ended September 30 |
|
|
2012 |
2011 |
|
(Thousands) |
|
Funded Status of the Pension and Other Post-Retirement Benefit Plans...................................................... |
$ (100,561)
|
$ (89,587)
|
Net Unrealized Gain (Loss) on Derivative Financial Instruments....................................................................... |
(1,602) | 40,979 |
Net Unrealized Gain on Securities Available for Sale............................................................................................... |
3,143 | 909 |
Accumulated Other Comprehensive Loss...................................................................................................................... |
$ (99,020)
|
$ (47,699)
|
At September 30, 2012, it is estimated that $10.6 million of unrealized gains on derivative financial instruments will be reclassified into the Consolidated Statement of Income during 2013 with $12.2 million of unrealized losses on derivative financial instruments being reclassified into the Consolidated Statement of Income in subsequent years. These instruments, which are classified as cash flow hedges, extend out to 2017.
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 credit was $0.4 million and $0.5 million at September 30, 2012 and 2011, respectively. The total amount for accumulated losses was $100.9 million and $90.0 million at September 30, 2012 and 2011, respectively.
Gas Stored Underground — Current
In the Utility segment, gas stored underground — current in the amount of $34.8 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 2012, 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 $46.0 million at September 30, 2012. 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.
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. At September 30, 2012, the remaining weighted average amortization period for such costs was approximately 4 years.
Income Taxes
The Company and its domestic subsidiaries file a consolidated federal income tax return. State tax returns are filed on a combined or separate basis depending on the applicable laws in the jurisdictions where tax returns are filed. 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.
The Company has accounts payable and accrued liabilities recorded on its Consolidated Balance Sheets that are related to capital expenditures. These amounts represent non-cash investing activities at the balance sheet date. Accordingly, they are excluded from the Consolidated Statement of Cash Flows when they are recorded as liabilities and included in the Consolidated Statement of Cash Flows when they are paid in the subsequent period. The following table summarizes the Company’s non-cash capital expenditures recorded as Accounts Payable and Other Accruals and Current Liabilities on the Consolidated Balance Sheet:
|
At September 30 |
|||
|
2012 |
2011 |
2010 |
2009 |
|
(Thousands) |
|||
Non-cash Capital Expenditures..................................................................................... |
$ 52,557
|
$ 111,947
|
$ 78,632
|
$ 20,231
|
Hedging Collateral Deposits
This is an account title for cash held in margin accounts funded by the Company to serve as collateral for hedging positions. At September 30, 2012, the Company had hedging collateral deposits of $0.4 million related to its exchange-traded futures contracts. At September 30, 2011, the Company had hedging collateral deposits of $5.5 million related to its exchange-traded futures contracts and $14.2 million related to its over-the-counter crude oil swap agreements. In accordance with its accounting policy, the Company does not offset hedging collateral deposits paid or received against related derivative financial instrument liability or asset balances.
Other Current Assets
The components of the Company’s Other Current Assets are as follows:
|
Year Ended September 30 |
|
|
2012 |
2011 |
|
(Thousands) |
|
Prepayments................................................................................................................................................................................ |
$ 8,316
|
$ 9,489
|
Prepaid Property and Other Taxes..................................................................................................................................... |
14,455 | 13,240 |
Federal Income Taxes Receivable..................................................................................................................................... |
268 | 385 |
State Income Taxes Receivable......................................................................................................................................... |
2,065 | 6,124 |
Fair Values of Firm Commitments..................................................................................................................................... |
1,291 | 9,096 |
Regulatory Assets..................................................................................................................................................................... |
29,726 | 26,589 |
|
$ 56,121
|
$ 64,923
|
Other Accruals and Current Liabilities
The components of the Company’s Other Accruals and Current Assets are as follows:
|
Year Ended September 30 |
|
|
2012 |
2011 |
|
(Thousands) |
|
Accrued Capital Expenditures.............................................................................................................................................. |
$ 36,460
|
$ 72,121
|
Regulatory Liabilities................................................................................................................................................................ |
38,253 | 29,368 |
Other................................................................................................................................................................................................ |
4,386 | 7,147 |
|
$ 79,099
|
$ 108,636
|
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, 2012 and 2011, customers in the balanced billing programs had advanced excess funds of $24.1 million and $19.6 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, 2012 and 2011, the Company had received customer security deposits amounting to $17.9 million and $17.3 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, SARs and restricted stock units. The diluted weighted average shares outstanding shown on the Consolidated Statements of Income reflects the potential dilution as a result of these securities as determined using the Treasury Stock Method. Stock options, SARs and restricted stock units that are antidilutive are excluded from the calculation of diluted earnings per common share. For 2012, there were 844,872 securities excluded as being antidilutive. For 2011, there were no securities excluded as being antidilutive. For 2010, 314,910 securities were excluded as being antidilutive.
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. 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. Restrictions on restricted stock awards generally lapse ratably over a period of not more than ten years after the date of each grant. Restricted stock units also are subject to restrictions on vesting and transferability. Restricted stock units represent the right to receive shares of common stock of the Company (or the equivalent value in cash or a combination of cash and shares of common stock of the Company, as determined by the Company) at the end of a specified time period. These restricted stock units do not entitle the participants to dividend and voting rights. The accounting for these restricted stock units is the same as the accounting for restricted share awards, except that the fair value at the date of grant of the restricted stock units (represented by the market value of Company common stock on the date of the award) must be reduced by the present value of forgone dividends over the vesting term of the award. The fair value of restricted stock units on the date of award is recorded as compensation expense over the vesting period.
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 does not have complex stock-based compensation awards.
Stock-based compensation expense for the years ended September 30, 2012, 2011 and 2010 was approximately $7.2 million, $6.7 million, and $4.4 million, respectively. Stock-based compensation expense is included in operation and maintenance expense on the Consolidated Statements of Income. The total income tax benefit related to stock-based compensation expense during the years ended September 30, 2012, 2011 and 2010 was approximately $2.9 million, $2.7 million and $1.8 million, respectively. There were no capitalized stock-based compensation costs during the years ended September 30, 2012, 2011 and 2010.
The Company realized tax benefits related to stock-based compensation of $14.2 million, $19.0 million, and $12.8 million for the fiscal years ended September 30, 2012, 2011 and 2010, respectively. The Company only recorded tax benefits of $0.6 million, $0.4 million, and $12.2 million related to the fiscal years ended September 30, 2012, 2011 and 2010, respectively, due to tax loss carryforwards.
For a summary of transactions during 2012 involving option shares, non-performance based SARs, performance based SARs, restricted share awards and restricted stock units for all plans, refer to Note E – Capitalization and Short-Term Borrowings.
Stock Options
The total intrinsic value of stock options exercised during the years ended September 30, 2012, 2011 and 2010 totaled approximately $13.5 million, $44.6 million, and $53.6 million, respectively. For 2012, 2011 and 2010, the amount of cash received by the Company from the exercise of such stock options was approximately $7.6 million, $9.5 million, and $34.5 million, respectively.
There were no stock options granted during the years ended September 30, 2012, 2011 and 2010. For the years ended September 30, 2012 and 2011, no stock options became fully vested. For the year ended September 30, 2010, 100,000 stock options became fully vested. The total fair value of the stock options that became vested during the year ended September 30, 2010 was approximately $0.7 million. There was no unrecognized compensation expense related to stock options at September 30, 2012.
Non-Performance Based SARs
The Company granted 166,000 and 195,000 non-performance based SARs during the years ended September 30, 2012 and 2011, respectively. The Company did not grant any non-performance based SARs during the year ended September 30, 2010. The SARs granted in 2012 will be settled in shares of common stock of the Company. The SARs granted in 2011 may be settled in cash, in shares of common stock of the Company, or in a combination of cash and shares of common stock of the Company, as determined by the Company. Non-performance based SARs are considered equity awards under the current authoritative guidance for stock-based compensation. The accounting for non-performance based SARs is the same as the accounting for stock options. The non-performance based SARs granted during the year ended September 30, 2012 vest annually in one-third increments and become exercisable on the third anniversary of the date of grant. The non-performance based SARs granted during the year ended September 30, 2011 vest and become exercisable annually in one-third increments. The weighted average grant date fair value of these non-performance based SARs granted during the years ended September 30, 2012 and 2011 were estimated on the date of grant using the same accounting treatment that is applied for stock options.
Participants in the stock option and award plans did not exercise any non-performance based SARs during the years ended September 30, 2012, 2011 and 2010. The weighted average grant date fair value of non-performance based SARs granted in 2012 and 2011 are $11.20 and $15.01, respectively. For the year ended September 30, 2012, 59,990 non-performance based SARs became fully vested. For the year ended September 30, 2011, no non-performance based SARs became fully vested. For the year ended September 30, 2010, 50,000 non-performance based SARs became fully vested. The total fair value of the non-performance based SARs that became vested during the year ended September 30, 2012 was approximately $0.9 million. 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, 2012, unrecognized compensation expense related to non-performance based SARs totaled approximately $1.1 million, which will be recognized over a weighted average period of 10.2 months.
The fair value of non-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 non-performance based SARs at the date of grant:
|
Year Ended September 30 |
||
|
2012 |
2011 |
|
Risk Free Interest Rate........................................................................................................................................................ |
1.59% | 2.94% | |
Expected Life (Years)............................................................................................................................................................ |
8.25 | 8.00 | |
Expected Volatility.................................................................................................................................................................. |
24.97% | 23.38% | |
Expected Dividend Yield (Quarterly).............................................................................................................................. |
0.64% | 0.55% |
The risk-free interest rate is based on the yield of a Treasury Note with a remaining term commensurate with the expected term of the non-performance based SARs. The expected life and expected volatility are based on historical experience.
For grants during the years ended September 30, 2012 and 2011, it was assumed that there would be no forfeitures, based on the vesting term and the number of grantees.
Performance Based SARs
The Company did not grant any performance based SARs during the years ended September 30, 2012 and 2011. The Company granted 520,500 performance based SARs during the year ended September 30, 2010. The accounting treatment for 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 year ended September 30, 2010 vest and become exercisable annually in one-third increments, provided that a performance condition is met. The performance condition for each fiscal year, generally stated, is an increase over the prior fiscal year of at least five percent in certain oil and natural gas production of the Exploration and Production segment. The weighted average grant date fair value of the performance based SARs granted during 2010 was estimated on the date of grant using the same accounting treatment that is applied for stock options, and assumes that the performance conditions specified will be achieved. If such conditions are not met or it is not considered probable that such conditions will be met, no compensation expense is recognized and any previously recognized compensation expense is reversed.
The weighted average grant date fair value of performance based SARs granted in 2010 is $12.06 per share. The total intrinsic value of performance based SARs exercised during the years ended September 30, 2012 and 2011 totaled less than $0.1 million and approximately $0.3 million, respectively. Participants in the stock option and award plans did not exercise any performance based SARs during the year ended September 30, 2010. For the years ended September 30, 2012, 2011 and 2010, 375,179, 376,819 and 203,324 performance based SARs became fully vested. The total fair value of the performance based SARs that became vested during each of the years ended September 30, 2012, 2011 and 2010 was approximately $2.9 million, $2.9 million and $0.8 million, respectively. As of September 30, 2012, unrecognized compensation expense related to performance based SARs totaled approximately $0.1 million, which will be recognized over a weighted average period of 3.0 months.
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 |
Risk Free Interest Rate........................................................................................................................................................ |
3.55% |
Expected Life (Years)............................................................................................................................................................ |
7.75 |
Expected Volatility.................................................................................................................................................................. |
23.25% |
Expected Dividend Yield (Quarterly).............................................................................................................................. |
0.64% |
The risk-free interest rate is based on the yield of a Treasury Note with a remaining term commensurate with the expected term of the performance based SARs. The expected life and expected volatility are based on historical experience.
For grants during the year ended September 30, 2010, it was assumed that there would be no forfeitures, based on the vesting term and the number of grantees.
Restricted Share Awards
The Company granted 41,525, 47,250, and 4,000 restricted share awards (non-vested stock as defined by the current accounting literature) during the years ended September 30, 2012, 2011 and 2010, respectively. The weighted average fair value of restricted share awards granted in 2012, 2011 and 2010 is $55.09 per share, $63.98 per share and $52.10 per share, respectively. As of September 30, 2012, unrecognized compensation expense related to restricted share awards totaled approximately $4.0 million, which will be recognized over a weighted average period of 2.4 years.
Restricted Stock Units
The Company granted 68,450 and 41,800 restricted stock units during the years ended September 30, 2012 and 2011, respectively. The weighted average fair value of restricted share units granted in 2012 and 2011 are $47.10 per share and $59.35 per share, respectively. As of September 30, 2012, unrecognized compensation expense related to restricted share awards totaled approximately $3.9 million, which will be recognized over a weighted average period of 2.0 years.
New Authoritative Accounting and Financial Reporting Guidance
In June 2011, the FASB issued authoritative guidance regarding the presentation of comprehensive income. The new guidance allows companies only two choices for presenting net income and other comprehensive income: in a single continuous statement, or in two separate, but consecutive, statements. The guidance eliminates the current option to report other comprehensive income and its components in the statement of changes in equity. This authoritative guidance will be effective as of the Company’s first quarter of fiscal 2013 and is not expected to have a significant impact on the Company’s financial statements.
In September 2011, the FASB issued revised authoritative guidance that simplifies the testing of goodwill for impairment. The revised guidance allows companies the option to perform a “qualitative” assessment to determine whether further impairment testing is necessary. The revised authoritative guidance is required to be effective for the Company’s annual impairment test performed in fiscal 2013. The Company has adopted the new provisions for fiscal 2012, as early adoption was permitted.
In December 2011, the FASB issued authoritative guidance requiring enhanced disclosures regarding offsetting assets and liabilities. Companies are required to disclose both gross information and net information about both instruments and transactions eligible for offset in the statement of financial position and instruments and transactions subject to an agreement similar to a master netting arrangement. This authoritative guidance will be effective as of the Company’s first quarter of fiscal 2014 and is not expected to have a significant impact on the Company’s financial statements.
|
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.
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, the future cash outflows associated with plugging and abandoning wells are excluded from the computation of the present value of estimated future net revenues for purposes of the full cost ceiling calculation.
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 obligations are shown below:
|
Year Ended September 30 |
||
|
2012 |
2011 |
2010 |
|
(Thousands) |
||
Balance at Beginning of Year................................................................................................................................ |
$ 75,731
|
$ 101,618
|
$ 91,373
|
Liabilities Incurred and Revisions of Estimates........................................................................................... |
41,653 | 10,346 | 16,140 |
Liabilities Settled.......................................................................................................................................................... |
(2,997) | (41,704) | (12,622) |
Accretion Expense...................................................................................................................................................... |
4,859 | 5,471 | 6,727 |
Balance at End of Year............................................................................................................................................ |
$ 119,246
|
$ 75,731
|
$ 101,618
|
|
Note C — Regulatory Matters
Regulatory Assets and Liabilities
The Company has recorded the following regulatory assets and liabilities:
|
At September 30 |
|
|
2012 |
2011 |
|
(Thousands) |
|
Regulatory Assets(1): |
|
|
Pension Costs(2) (Note H)................................................................................................................................................................ |
$ 344,228
|
$ 319,906
|
Post-Retirement Benefit Costs(2) (Note H).............................................................................................................................. |
154,415 | 124,423 |
Recoverable Future Taxes (Note D) ........................................................................................................................................... |
150,941 | 144,377 |
Environmental Site Remediation Costs(2) (Note I)............................................................................................................... |
17,843 | 20,095 |
NYPSC Assessment(3)...................................................................................................................................................................... |
17,420 | 15,063 |
Asset Retirement Obligations(2) (Note B).................................................................................................................................. |
26,942 | 13,860 |
Unamortized Debt Expense (Note A)........................................................................................................................................... |
3,997 | 5,090 |
Other(4)...................................................................................................................................................................................................... |
15,729 | 17,639 |
Total Regulatory Assets..................................................................................................................................................................... |
731,515 v |
660,453 |
Less: Amounts Included in Other Current Assets.................................................................................................................. |
(29,726) | (26,589) |
Total Long-Term Regulatory Assets.............................................................................................................................................. |
$ 701,789
|
$ 633,864
|
|
At September 30 |
|
|
2012 |
2011 |
|
(Thousands) |
|
Regulatory Liabilities: |
|
|
Cost of Removal Regulatory Liability......................................................................................................................................... |
$ 139,611
|
$ 135,940
|
Taxes Refundable to Customers (Note D)................................................................................................................................ |
66,392 | 65,543 |
Amounts Payable to Customers (See Regulatory Mechanisms in Note A)............................................................... |
19,964 | 15,519 |
Off-System Sales and Capacity Release Credits(5)........................................................................................................... |
16,262 | 7,675 |
Other(6)...................................................................................................................................................................................................... |
23,041 | 23,351 |
Total Regulatory Liabilities................................................................................................................................................................. |
265,270 | 248,028 |
Less: Amounts included in Current and Accrued Liabilities............................................................................................... |
(38,253) | (29,368) |
Total Long-Term Regulatory Liabilities.......................................................................................................................................... |
$ 227,017
|
$ 218,660
|
|
|
(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) |
Amounts are included in Other Current Assets on the Consolidated Balance Sheets at September 30, 2012 and September 30, 2011 since such amounts are expected to be recovered from ratepayers in the next 12 months. |
(4) |
$12,306 and $11,526 are included in Other Current Assets on the Consolidated Balance Sheets at September 30, 2012 and 2011, respectively, since such amounts are expected to be recovered from ratepayers in the next 12 months. $3,423 and $6,113 are included in Other Regulatory Assets on the Consolidated Balance Sheets at September 30, 2012 and 2011, respectively. |
(5) |
Amounts are included in Other Accruals and Current Liabilities on the Consolidated Balance Sheets at September 30, 2012 and September 30, 2011 since such amounts are expected to be passed back to ratepayers in the next 12 months. |
|
|
(6) |
$2,027 and $6,174 are included in Other Accruals and Current Liabilities on the Consolidated Balance Sheets at September 30, 2012 and 2011, respectively, since such amounts are expected to be recovered from ratepayers in the next 12 months. $21,014 and $17,177 are included in Other Regulatory Liabilities on the Consolidated Balance Sheets at September 30, 2012 and 2011, respectively. |
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.
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.
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.
Supply Corporation Rate Proceeding
On August 6, 2012, the FERC issued an order approving a “black box” Stipulation and Agreement that resolved the issues arising from the general rate filing that Supply Corporation filed on October 31, 2011. The Stipulation and Agreement provides for, among other things, (i) an increase in Supply Corporation’s base tariff rates effective May 1, 2012, (ii) implementation of a tracking mechanism to adjust fuel retention rates annually to reflect actual experience, replacing the previously fixed fuel retention rates, and (iii) the elimination of a past net regulatory liability associated with post-retirement benefits. Supply Corporation is not required to amortize the liability or otherwise pass it back to customers under the Stipulation and Agreement. Accordingly, the elimination of the past net regulatory liability, totaling $21.7 million, has been recorded as an increase to operating revenues for the quarter ended September 30, 2012.
|
Note D — Income Taxes
The components of federal and state income taxes included in the Consolidated Statements of Income are as follows:
|
Year Ended September 30 |
|||
|
2012 |
2011 |
2010 |
|
|
(Thousands) |
|||
Current Income Taxes — |
|
|
|
|
Federal............................................................................................................................................................................ |
$ (8)
|
$ (1,390)
|
$ 2,074
|
|
State................................................................................................................................................................................ |
6,412 | 1,520 | 4,991 | |
Deferred Income Taxes — |
|
|
|
|
Federal............................................................................................................................................................................ |
111,176 | 130,434 | 110,515 | |
State................................................................................................................................................................................ |
32,974 | 33,817 | 24,164 | |
|
150,554 | 164,381 | 141,744 | |
Deferred Investment Tax Credit......................................................................................................................... |
(581) | (697) | (697) | |
Total Income Taxes................................................................................................................................................... |
$ 149,973
|
$ 163,684
|
$ 141,047
|
|
Presented as Follows: |
|
|
|
|
Other Income............................................................................................................................................................... |
$ (581)
|
$ (697)
|
$ (697)
|
|
Income Tax Expense — Continuing Operations.......................................................................................... |
150,554 | 164,381 | 137,227 | |
Discontinued Operations — |
|
|
|
|
Income from Operations........................................................................................................................................ |
— |
— |
493 | |
Gain on Disposal........................................................................................................................................................ |
— |
— |
4,024 | |
Total Income Taxes................................................................................................................................................... |
$ 149,973
|
$ 163,684
|
$ 141,047
|
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 |
||
|
2012 |
2011 |
2010 |
|
(Thousands) |
||
U.S. Income Before Income Taxes................................................................................................................. |
$ 370,050
|
$ 422,086
|
$ 366,960
|
Income Tax Expense, Computed at U.S. Federal Statutory Rate of 35%................................... |
$ 129,518
|
$ 147,730
|
$ 128,436
|
Increase (Reduction) in Taxes Resulting from: |
|
|
|
State Income Taxes................................................................................................................................................ |
25,601 | 22,969 | 18,951 |
Miscellaneous............................................................................................................................................................. |
(5,146) | (7,015) | (6,340) |
Total Income Taxes.................................................................................................................................................. |
$ 149,973
|
$ 163,684
|
$ 141,047
|
Significant components of the Company’s deferred tax liabilities and assets were as follows:
|
At September 30 |
|
|
2012 |
2011 |
|
(Thousands) |
|
Deferred Tax Liabilities: |
|
|
Property, Plant and Equipment............................................................................................................................................... |
$ 1,333,574
|
$ 1,062,255
|
Pension and Other Post-Retirement Benefit Costs...................................................................................................... |
236,431 | 217,302 |
Other................................................................................................................................................................................................... |
43,294 | 70,389 |
Total Deferred Tax Liabilities.................................................................................................................................................... |
1,613,299 | 1,349,946 |
Deferred Tax Assets: |
|
|
Pension and Other Post-Retirement Benefit Costs...................................................................................................... |
(276,501) | (263,606) |
Tax Loss Carryforwards............................................................................................................................................................ |
(198,744) | (71,516) |
Other................................................................................................................................................................................................... |
(83,052) | (74,863) |
Total Deferred Tax Assets........................................................................................................................................................ |
(558,297) | (409,985) |
Total Net Deferred Income Taxes......................................................................................................................................... |
$ 1,055,002
|
$ 939,961
|
Presented as Follows: |
|
|
Deferred Tax Liability/(Asset) — Current.......................................................................................................................... |
$ (10,755)
|
$ (15,423)
|
Deferred Tax Liability — Non-Current................................................................................................................................. |
1,065,757 | 955,384 |
Total Net Deferred Income Taxes......................................................................................................................................... |
$ 1,055,002
|
$ 939,961
|
As a result of certain realization requirements of the authoritative guidance on stock-based compensation, the table of deferred tax liabilities and assets shown above does not include certain deferred tax assets that arose directly from excess tax deductions related to stock-based compensation. Cumulative tax benefits of $32.7 million and $19.1 million for the periods ending September 30, 2012 and September 30, 2011, respectively, relating to the excess stock-based compensation deductions will be recorded in Paid in Capital in future years when such tax benefits are realized.
Regulatory liabilities representing the reduction of previously recorded deferred income taxes associated with rate-regulated activities that are expected to be refundable to customers amounted to $66.4 million and $65.5 million at September 30, 2012 and 2011, 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 $150.9 million and $144.4 million at September 30, 2012 and 2011, 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, 2012 and 2011, and regulatory assets of $65.9 million and $60.5 million as of September 30, 2012 and 2011, respectively.
The following is a reconciliation of the change in unrecognized tax benefits:
|
Year Ended September 30 |
||
|
2012 |
2011 |
2010 |
|
(Thousands) |
||
Balance at Beginning of Year......................................................................................................................................... |
$ 7,766
|
$ 8,490
|
$ 8,721
|
Additions for Tax Positions Related to Current Year........................................................................................... |
1,600 | 80 | 699 |
Additions for Tax Positions of Prior Years................................................................................................................ |
2,751 | 107 | 45 |
Reductions for Tax Positions of Prior Years........................................................................................................... |
(947) | (911) | (975) |
Balance at End of Year..................................................................................................................................................... |
$ 11,170
|
$ 7,766
|
$ 8,490
|
The Company anticipates that during the next 12 months there will be additional Internal Revenue Service (IRS) guidance relative to its tax method of accounting for certain capitalized costs relating to its utility property and the IRS Appeals process will be resolved (see discussion below). This would result in an elimination of approximately $7.3 million of unrecognized tax benefits, which would not have a material impact on the effective tax rate. As of September 30, 2012, approximately $4.9 million of unrecognized tax benefits would favorably impact the effective tax rate, if recognized.
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 $0.3 million, $0.3 million and $0.3 million for fiscal 2012, 2011 and 2010, respectively. The Company has not accrued any penalties during fiscal 2012, 2011 and 2010.
The IRS is currently conducting examinations of the Company for fiscal 2011 and fiscal 2012 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 2009 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. Local IRS examiners proposed to disallow most of the tax accounting method change recorded by the Company in fiscal 2009 and fiscal 2010. The Company has filed protests for fiscal 2009 and fiscal 2010 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 principal subsidiaries operate mainly 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, 2012, the Company has a federal net operating loss (NOL) carryover of $565 million, which expires in varying amounts between 2023 and 2032. Approximately $23 million of this NOL is subject to certain annual limitations, and $84 million is attributable to excess tax deductions related to stock-based compensation as discussed above. In addition, the Company has state NOL carryovers in Pennsylvania, California and New York of $278 million, $155 million and $138 million, respectively, which begin to expire in varying amounts between 2029 and 2032. No valuation allowance was recorded on the federal or state NOL carryovers because of management’s determination that the amounts will be fully utilized during the carryforward period.
|
Note E — Capitalization and Short-Term Borrowings
Summary of Changes in Common Stock Equity
|
|
|
Earnings |
Accumulated |
|
|
|
|
Reinvested |
Other |
|
|
Common Stock |
Paid |
in |
Comprehensive |
|
|
|
In |
the |
Income |
|
|
Shares |
Amount |
Capital |
Business |
(Loss) |
|
(Thousands, except per share amounts) |
||||
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 | (44,985) |
Net Income Available for Common Stock....................................... |
|
|
|
258,402 |
|
Dividends Declared on Common Stock ($1.40 Per Share)...... |
|
|
|
(115,642) |
|
Other Comprehensive Loss, Net of Tax........................................... |
|
|
|
|
(2,714) |
Share-Based Payment Expense(2)...................................................... |
|
|
6,656 |
|
|
Common Stock Issued (Repurchased) Under Stock and Benefit Plans(1) |
738 | 738 | (1,526) |
|
|
Balance at September 30, 2011............................................................. |
82,813 | 82,813 | 650,749 | 1,206,022 | (47,699) |
Net Income Available for Common Stock....................................... |
|
|
|
220,077 |
|
Dividends Declared on Common Stock ($1.44 Per Share)...... |
|
|
|
(119,815) |
|
Other Comprehensive Loss, Net of Tax........................................... |
|
|
|
|
(51,321) |
Share-Based Payment Expense(2)...................................................... |
|
|
7,156 |
|
|
Common Stock Issued Under Stock and Benefit Plans(1)...... |
517 | 517 | 11,596 |
|
|
Balance at September 30, 2012............................................................ |
83,330 | $ 83,330
|
$ 669,501
|
$1,306,284(3) |
$ (99,020)
|
|
|
|
|
|
|
(1) |
Paid in Capital includes tax benefits of $1.0 million for September 30, 2012, tax costs of $1.2 million for September 30, 2011 and tax benefits of $13.2 million for September 30, 2010 associated with the exercise of stock options and/or performance based SARs. |
|
|
(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, 2012, $1.2 billion 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 2012, the Company issued 155,310 original issue shares of common stock for the Direct Stock Purchase and Dividend Reinvestment Plan.
During 2012, the Company issued 465,894 original issue shares of common stock as a result of stock option and SARs exercises and 41,525 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, SARs or restricted stock will often tender shares of common stock to the Company for payment of option exercise prices and/or applicable withholding taxes. During 2012, 161,021 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 2009 Non-Employee Director Equity Compensation Plan, as partial consideration for the directors’ services during the fiscal year. Under this program, the Company issued 15,755 original issue shares of common stock during 2012.
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 (an Acquiring Person) attempts to acquire the Company on terms not approved by the Board of Directors.
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
Transactions involving option shares for all plans are summarized as follows:
|
Number of Shares Subject to Option |
Weighted Average Exercise Price |
Weighted Average Remaining Contractual Life (Years) |
Aggregate Intrinsic Value |
|
(In thousands) |
|||
Outstanding at September 30, 2011......................................................................... |
1,758,961 | $ 31.38
|
|
|
Granted in 2012................................................................................................................. |
— |
$— |
|
|
Exercised in 2012............................................................................................................. |
(476,243) | $ 25.28
|
|
|
Forfeited in 2012............................................................................................................... |
— |
$ — |
|
|
Outstanding at September 30, 2012........................................................................ |
1,282,718 | $ 33.64
|
2.65 | $ 26,166
|
Option shares exercisable at September 30, 2012........................................... |
1,282,718 | $ 33.64
|
2.65 | $ 26,166
|
Option shares available for future grant at September 30, 2012(1)......... |
2,097,214 |
|
|
|
(1) |
Includes shares available for SARs and restricted stock grants. |
Transactions involving non-performance based SARs for all plans are summarized as follows:
|
Number of Shares Subject To Option |
Weighted Average Exercise Price |
Weighted Average Remaining Contractual Life (Years) |
Aggregate Intrinsic Value |
|
(In thousands) |
|||
Outstanding at September 30, 2011......................................................................... |
245,000 | $ 58.79
|
|
|
Granted in 2012................................................................................................................. |
166,000 | $ 55.09
|
|
|
Exercised in 2012............................................................................................................. |
— |
$— |
|
|
Forfeited in 2012............................................................................................................... |
— |
$— |
|
|
Outstanding at September 30, 2012........................................................................ |
411,000 | $ 57.30
|
8.20 | $ (1,339)
|
SARs exercisable at September 30, 2012............................................................ |
109,990 | $ 53.56
|
6.51 | $ 53
|
Transactions involving performance based SARs for all plans are summarized as follows:
|
Number of Shares Subject To Option |
Weighted Average Exercise Price |
Weighted Average Remaining Contractual Life (Years) |
Aggregate Intrinsic Value |
|
(In thousands) |
|||
Outstanding at September 30, 2011......................................................................... |
1,225,153 | $ 40.85
|
|
|
Granted in 2012................................................................................................................. |
— |
$— |
|
|
Exercised in 2012............................................................................................................. |
(2,000) | $ 29.88
|
|
|
Forfeited in 2012............................................................................................................... |
— |
$ — |
|
|
Canceled in 2012(1)......................................................................................................... |
(6,000) | $ 58.99
|
|
|
Outstanding at September 30, 2012........................................................................ |
1,217,153 | $ 40.78
|
6.68 | $ 16,140
|
SARs exercisable at September 30, 2012............................................................ |
1,039,309 | $ 38.80
|
6.56 | $ 15,837
|
(1) |
Shares were canceled during 2012 due to performance condition not being met. |
Restricted Share Awards
Transactions involving restricted shares for all plans are summarized as follows:
|
Number of Restricted Share Awards |
Weighted Average Fair Value per Award |
Restricted Share Awards Outstanding at September 30, 2011......................................................................... |
139,250 | $ 53.37
|
Granted in 2012....................................................................................................................................................................... |
41,525 | $ 55.09
|
Vested in 2012......................................................................................................................................................................... |
(18,740) | $ 59.74
|
Forfeited in 2012.................................................................................................................................................................... |
— |
$— |
Restricted Share Awards Outstanding at September 30, 2012......................................................................... |
162,035 | $ 53.07
|
Vesting restrictions for the outstanding shares of non-vested restricted stock at September 30, 2012 will lapse as follows: 2013 — 34,582 shares; 2014 — 34,601 shares; 2015 — 32,852 shares; 2016 — 5,000 shares; 2018 — 35,000 shares; and 2021 —20,000 shares.
Restricted Stock Units
Transactions involving restricted stock units for all plans are summarized as follows:
|
Number of Restricted Share Awards |
Weighted Average Fair Value per Award |
Restricted Stock Units Outstanding at September 30, 2011............................................................................. |
39,400 | $ 59.20
|
Granted in 2012....................................................................................................................................................................... |
68,450 | $ 47.10
|
Vested in 2012......................................................................................................................................................................... |
— |
$ — |
Forfeited in 2012.................................................................................................................................................................... |
(1,950) | $ 46.96
|
Restricted Stock Units Outstanding at September 30, 2012............................................................................. |
105,900 | $ 51.61
|
Vesting restrictions for the outstanding shares of non-vested restricted stock units at September 30, 2012 will lapse as follows: 2014 — 12,932 shares; 2015 — 35,300 shares; 2016 — 35,301 shares; and 2017 — 22,367 shares.
Redeemable Preferred Stock
As of September 30, 2012, 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 |
|
|
2012 |
2011 |
|
(Thousands) |
|
Medium-Term Notes(1): |
|
|
7.4% due March 2023 to June 2025...................................................................................................................................... |
$ 99,000
|
$ 249,000
|
Notes(1): |
|
|
4.90% to 8.75% due March 2013 to December 2021.................................................................................................... |
1,300,000 | 800,000 |
Total Long-Term Debt.................................................................................................................................................................... |
1,399,000 | 1,049,000 |
Less Current Portion(2)............................................................................................................................................................... |
250,000 | 150,000 |
|
$ 1,149,000
|
$ 899,000
|
(1) |
The Medium-Term Notes and Notes are unsecured. |
(2) |
Current Portion of Long-Term Debt at September 30, 2012 consists of $250.0 million of 5.25% notes that mature in March 2013. Current Portion of Long-Term Debt at September 30, 2011 consisted of $150.0 million of 6.70% medium-term notes that matured in November 2011. |
On December 1, 2011, the Company issued $500.0 million of 4.90% notes due December 1, 2021. After deducting underwriting discounts and commissions, the net proceeds to the Company amounted to $496.1 million. 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 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 refinancing short-term debt that was used to pay the $150.0 million due at the maturity of the Company’s 6.70% notes in November 2011.
In addition, the Company has $300.0 million of 6.50% notes that mature in April 2018 and $250.0 million of 8.75% notes that mature in May 2019. The holders of these 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, 2012, the aggregate principal amounts of long-term debt maturing during the next five years and thereafter are as follows: $250.0 million in 2013, zero for 2014 through 2017, and $1,149.0 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 totaled $335.0 million, are revocable at the option of the financial institutions and are reviewed on an annual basis. The Company anticipates that its uncommitted lines of credit generally will be renewed at amounts near current levels, 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 $750.0 million, which commitment extends through January 6, 2017.
At September 30, 2012, the Company had outstanding commercial paper and short-term notes payable to banks of $165.0 million and $6.0 million, respectively. The weighted average interest rate on the commercial paper was 0.50% and the weighted average interest rate on the short-term notes payable to banks was 0.60%. At September 30, 2011, the Company had $40.0 million in outstanding commercial paper, which had a weighted average interest rate of 0.43%.
Debt Restrictions
Under the committed credit facility, the Company agreed that its debt to capitalization ratio will not exceed .65 at the last day of any fiscal quarter through January 6, 2017. At September 30, 2012, the Company’s debt to capitalization ratio (as calculated under the facility) was .44. The constraints specified in the committed credit facility would have permitted an additional $2.07 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 exceeded .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, 2012, the Company would have been permitted to issue up to a maximum of $1.51 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 7.1%) of the Company’s long-term debt (as of September 30, 2012) 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 $750.0 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, 2012, the Company had no debt outstanding under the committed credit facility.
|
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 can 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, 2012 and 2011. Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement.
|
At Fair Value as of September 30, 2012 |
||||
Recurring Fair Value Measures |
Level 1 |
Level 2 |
Level 3 |
Netting Adjustments(1) |
Total |
|
(Dollars in thousands) |
||||
Assets: |
|
|
|
|
|
Cash Equivalents — Money Market Mutual Funds.............................................................. |
$ 46,113
|
$— |
$— |
$— |
$ 46,113
|
Derivative Financial Instruments: |
|
|
|
|
|
Commodity Futures Contracts — Gas...................................................................................... |
4,348 |
— |
— |
(2,760) | 1,588 |
Over the Counter Swaps — Gas.................................................................................................. |
— |
41,751 |
— |
(15,723) | 26,028 |
Over the Counter Swaps — Oil..................................................................................................... |
— |
— |
559 | (559) |
— |
Other Investments: |
|
|
|
|
|
Balanced Equity Mutual Fund......................................................................................................... |
24,767 |
— |
— |
— |
24,767 |
Common Stock — Financial Services Industry.................................................................... |
4,758 |
— |
— |
— |
4,758 |
Other Common Stock........................................................................................................................ |
272 |
— |
— |
— |
272 |
Hedging Collateral Deposits............................................................................................................ |
364 |
— |
— |
— |
364 |
Total............................................................................................................................................................ |
$ 80,622
|
$ 41,751
|
$ 559
|
$ (19,042)
|
$ 103,890
|
|
|
|
|
|
|
Liabilities: |
|
|
|
|
|
Derivative Financial Instruments: |
|
|
|
|
|
Commodity Futures Contracts — Gas...................................................................................... |
$ 2,760
|
$— |
$— |
$ (2,760)
|
$— |
Over the Counter Swaps — Gas.................................................................................................. |
— |
19,932 |
— |
(15,723) | 4,209 |
Over the Counter Swaps — Oil..................................................................................................... |
— |
654 | 20,223 | (559) | 20,318 |
Total............................................................................................................................................................ |
$ 2,760
|
$ 20,586
|
$ 20,223
|
$ (19,042)
|
$ 24,527
|
Total Net Assets/(Liabilities)............................................................................................................ |
$ 77,862
|
$ 21,165
|
$ (19,664)
|
$— |
$ 79,363
|
|
At Fair Value as of September 30, 2011 |
||||
Recurring Fair Value Measures |
Level 1 |
Level 2 |
Level 3 |
Netting Adjustments(1) |
Total |
|
(Dollars in thousands) |
||||
Assets: |
|
|
|
|
|
Cash Equivalents — Money Market Mutual Funds.............................................................. |
$ 32,444
|
$— |
$— |
$— |
$ 32,444
|
Derivative Financial Instruments: |
|
|
|
|
|
Commodity Futures Contracts — Gas...................................................................................... |
4,541 |
— |
— |
(4,541) |
— |
Over the Counter Swaps — Gas.................................................................................................. |
— |
75,292 |
— |
(179) | 75,113 |
Over the Counter Swaps — Oil..................................................................................................... |
— |
— |
10,420 | (9,448) | 972 |
Other Investments: |
|
|
|
|
|
Balanced Equity Mutual Fund......................................................................................................... |
19,882 |
— |
— |
— |
19,882 |
Common Stock — Financial Services Industry.................................................................... |
4,478 |
— |
— |
— |
4,478 |
Other Common Stock........................................................................................................................ |
226 |
— |
— |
— |
226 |
Hedging Collateral Deposits............................................................................................................ |
19,701 |
— |
— |
— |
19,701 |
Total............................................................................................................................................................ |
$ 81,272
|
$ 75,292
|
$ 10,420
|
$ (14,168)
|
$ 152,816
|
|
|
|
|
|
|
Liabilities: |
|
|
|
|
|
Derivative Financial Instruments: |
|
|
|
|
|
Commodity Futures Contracts — Gas...................................................................................... |
$ 7,833
|
$— |
$— |
$ (4,541)
|
$ 3,292
|
Over the Counter Swaps — Gas.................................................................................................. |
— |
179 |
— |
(179) |
— |
Over the Counter Swaps — Oil..................................................................................................... |
— |
— |
15,830 | (9,448) | 6,382 |
Total............................................................................................................................................................ |
$ 7,833
|
$ 179
|
$ 15,830
|
$ (14,168)
|
$ 9,674
|
Total Net Assets/(Liabilities)............................................................................................................ |
$ 73,439
|
$ 75,113
|
$ (5,410)
|
$— |
$ 143,142
|
(1) | Amounts represent the impact of legally-enforceable master netting arrangements that allow the Company to net gain and loss positions held with the same counterparties. |
Derivative Financial Instruments
At September 30, 2012 and 2011, 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 $0.4 million (at September 30, 2012) and $5.5 million (at September 30, 2011), which are associated with these futures contracts, have been reported in Level 1 as well. The derivative financial instruments reported in Level 2 consist of all of the natural gas price swap agreements used in the Company’s Exploration and Production and Energy Marketing segments at September 30, 2012 and 2011, and some of the crude oil price swap agreements used in the Company’s Exploration and Production segment at September 30, 2012. The fair value of the Level 2 price swap agreements is based on an internal, discounted cash flow model that uses observable inputs (i.e. LIBOR based discount rates and basis differential information, if applicable, at active natural gas and crude oil trading markets). The derivative financial instruments reported in Level 3 consist of the majority of the crude oil price swap agreements used in the Company’s Exploration and Production segment at September 30, 2012 and all of the crude oil price swap agreements used in the Company’s Exploration and Production segment at September 30, 2011. Hedging collateral deposits of $14.2 million associated with these crude oil price swap agreements have been reported in Level 1 at September 30, 2011. The fair value of the Level 3 crude oil price swap agreements is based on an internal, discounted cash flow model that uses both observable (i.e. LIBOR based discount rates) and unobservable inputs (i.e. basis differential information of crude oil trading markets with low trading volume).
The significant unobservable input used in the fair value measurement of the majority of the Company’s over-the-counter crude oil swaps is the basis differential between Midway Sunset oil and NYMEX contracts. Significant changes in the assumed basis differential could result in a significant change in the value of the derivative financial instruments. At September 30, 2012, it was assumed that Midway Sunset oil was 110.5% of NYMEX. This is based on a historical twelve month average of Midway Sunset oil sales verses NYMEX settlements. During this twelve-month period, the price of Midway Sunset oil ranged from 103.2% to 125.0% of NYMEX. If the basis differential between Midway Sunset oil and NYMEX contracts used in the fair value measurement calculation at September 30, 2012 had been 10 percentage points lower, the fair value of the Level 3 crude oil price swap agreements liability would have been approximately $19.4 million lower. If the basis differential between Midway Sunset oil and NYMEX contracts used in the fair value measurement at September 30, 2012 had been 10 percentage points higher, the fair value measurement of the Level 3 crude oil price swap agreements liability would have been approximately $19.4 million higher. These calculated amounts are based solely on basis differential changes and do not take into account any other changes to the fair value measurement calculation.
Based on an assessment of the counterparties’ credit risk, the fair market value of the price swap agreements reported as Level 2 assets (after netting arrangements) at September 30, 2012 has been reduced by $0.2 million and the fair market value of the price swap agreements reported as Level 2 and Level 3 assets (after netting arrangements) at September 30, 2011 have been reduced by $2.0 million. Based on an assessment of the Company’s credit risk, the fair market value of the price swap agreements reported as Level 2 and Level 3 liabilities (after netting arrangements) at September 30, 2012 has been reduced by $1.2 million and the fair market value of the price swap agreements reported as Level 3 liabilities (after netting arrangements) has not been reduced at September 30, 2011. 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 years ended September 30, 2012 and September 30, 2011, respectively. For the years ended September 30, 2012 and September 30, 2011, no transfers in or out of Level 1 or Level 2 occurred. There were no purchases or sales of derivative financial instruments during the periods presented in the tables below. All settlements of the derivative financial instruments are reflected in the Gains/Losses Realized and Included in Earnings column of the tables below.
Fair Value Measurements Using Unobservable Inputs (Level 3)
|
|
Total Gains/Losses |
|
|
|
|
|
|
Gains/(Losses) |
|
|
|
|
(Gains)/Losses |
Unrealized and |
|
|
|
October 1, 2011 |
Realized and Included in Earnings |
Included in Other Comprehensive Income (Loss) |
Transfer In/(Out) of Level 3 |
September 30, 2012 |
|
(Dollars in thousands) |
||||
Derivative Financial Instruments(2)…………….…... |
$ (5,410)
|
$ 46,174(1) |
$ (60,428)
|
$ — |
$ (19,664)
|
(1) Amounts are reported in Operating Revenues in the Consolidated Statement of Income for the year ended September 30, 2012.
(2) Derivative Financial Instruments are shown on a net basis.
Fair Value Measurements Using Unobservable Inputs (Level 3)
|
|
Total Gains/Losses |
|
|
|
|
|
|
Gains/(Losses) |
|
|
|
|
(Gains)/Losses |
Unrealized and |
|
|
|
October 1, 2010 |
Realized and Included in Earnings |
Included in Other Comprehensive Income (Loss) |
Transfer In/(Out) of Level 3 |
September 30, 2011 |
|
(Dollars in thousands) |
||||
Derivative Financial Instruments(2).............................. |
$ (16,483)
|
$ 41,354(1) |
$ (30,281)
|
$ — |
$ (5,410)
|
(1) Amounts are reported in Operating Revenues in the Consolidated Statement of Income for the year ended September 30, 2011.
(2) Derivative Financial Instruments are shown on a net basis.
|
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 |
|||
|
2012 Carrying Amount |
2012 Fair Value |
2011 Carrying Amount |
2011 Fair Value |
|
(Thousands) |
|||
Long-Term Debt.................................................................................................................... |
$ 1,399,000
|
$ 1,623,847
|
$ 1,049,000
|
$ 1,198,585
|
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 fair value of long-term debt was calculated using observable inputs (U.S. Treasuries/LIBOR for the risk-free component and company specific credit spread information – generally obtained from recent trade activity in the debt). As such, the Company considers the debt to be Level 2.
Temporary cash investments, notes payable to banks and commercial paper are stated at cost. Temporary cash investments are considered Level 1, while notes payable to banks and commercial paper are considered to be Level 2. Given the short-term nature of the notes payable to banks and commercial paper, the Company believes cost is a reasonable approximation of fair value.
Other Investments
Investments in life insurance are stated at their cash surrender values or net present value as discussed below. Investments in an equity mutual fund and the stock of an insurance company (marketable equity securities), as discussed below, are stated at fair value based on quoted market prices.
Other investments include cash surrender values of insurance contracts (net present value in the case of split-dollar collateral assignment arrangements) and marketable equity securities. The values of the insurance contracts amounted to $57.0 million and $54.8 million at September 30, 2012 and 2011, respectively. The fair value of the equity mutual fund was $24.8 million and $19.9 million at September 30, 2012 and 2011, respectively. The gross unrealized gain on this equity mutual fund was $2.6 million at September 30, 2012. The gross unrealized loss on this equity mutual fund was $0.7 million at September 30, 2011. The fair value of the stock of an insurance company was $4.8 million and $4.5 million at September 30, 2012 and 2011, respectively. The gross unrealized gain on this stock was $2.3 million and $2.1 million at September 30, 2012 and 2011, respectively. The insurance contracts and marketable equity securities are primarily informal funding mechanisms for various benefit obligations the Company has to certain employees.
Derivative Financial Instruments
The Company uses or has used derivative instruments to manage commodity price risk in the Exploration and Production, Energy Marketing and Pipeline and Storage segments. The Company enters into futures contracts and over-the-counter swap agreements for natural gas and crude oil to manage the price risk associated with forecasted sales of gas and oil. The Company also enters into futures contracts and swaps to manage the risk associated with forecasted gas purchases, forecasted gas sales, 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 does not typically exceed 5 years.
The Company has presented its net derivative assets and liabilities as “Fair Value of Derivative Financial Instruments” on its Consolidated Balance Sheets at September 30, 2012 and September 30, 2011. All of the derivative financial instruments reported on those line items related to commodity contracts as discussed in the paragraph above.
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, 2012, 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 |
133.5 Bcf (all short positions) |
Crude Oil |
2,316,000 Bbls (all short positions) |
As of September 30, 2012, 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, when applicable, 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 |
5.7 Bcf (all short positions (forecasted storage withdrawals)) |
As of September 30, 2012, the Company’s Exploration and Production segment had $0.9 million ($0.5 million after tax) of net unrealized hedging gains included in the accumulated other comprehensive income (loss) balance. It is expected that $21.9 million ($12.7 million after tax) of such unrealized gains will be reclassified into the Consolidated Statement of Income within the next 12 months as the expected sales of the underlying commodities occur. It is expected that unrealized losses will be reclassified into the Consolidated Statement of Income in subsequent periods as the expected sales of the underlying commodities occur.
As of September 30, 2012, the Company’s Energy Marketing segment had $2.8 million ($1.7 million after tax) of net hedging losses included in the accumulated other comprehensive income (loss) balance. It is expected that the full amount will be reclassified into the Consolidated Statement of Income within the next 12 months as the expected sales of the underlying commodity occurs.
As of September 30, 2012, the Company’s Pipeline and Storage segment had $0.7 million ($0.4 million after tax) of net hedging losses included in the accumulated other comprehensive income (loss) balance. It is expected that the full amount will be reclassified into the Consolidated Statement of Income within the next 12 months as the expected sales of the underlying commodity occurs.
Refer to Note A, under Accumulated Other Comprehensive Income (Loss), for the after-tax gain (loss) pertaining to derivative financial instruments for the Exploration and Production, Energy Marketing and Pipeline and Storage segments.
|
The Effect of Derivative Financial Instruments on the Statement of Financial Performance for the |
|||||||
|
Year Ended September 30, 2012 and 2011 (Dollar Amounts in Thousands) |
|||||||
|
Amount of |
|
Amount of |
|
|
|||
|
Derivative Gain or |
|
Derivative Gain or |
|
|
|||
|
(Loss) Recognized |
Location of |
(Loss) Reclassified |
Location of |
|
|||
|
in Other |
Derivative Gain or |
from Accumulated |
Derivative Gain or |
Derivative Gain or |
|||
|
Comprehensive |
(Loss) Reclassified |
Other Comprehensive |
(Loss) Recognized |
(Loss) Recognized |
|||
|
Income (Loss) on |
from Accumulated |
Income (Loss) on |
in the Consolidated |
in the Consolidated |
|||
|
the Consolidated |
Other Comprehensive |
the Consolidated |
Statement of |
Statement of Income |
|||
|
Statement of |
Income (Loss) on |
Balance Sheet into |
Income |
(Ineffective |
|||
|
Comprehensive |
the Consolidated |
the Consolidated |
(Ineffective Portion |
Portion and Amount |
|||
|
Income (Loss) |
Balance Sheet into |
Statement of Income |
and Amount |
Excluded from |
|||
Derivatives in Cash |
(Effective Portion) |
the Consolidated |
(Effective Portion) |
Excluded from |
Effectiveness Testing) |
|||
Flow Hedging |
for the Year Ended |
Statement of Income |
for the Year Ended |
Effectiveness |
for the Year Ended |
|||
Relationships |
September 30, |
(Effective Portion) |
September 30, |
Testing) |
September 30, |
|||
|
2012 |
2011 |
|
2012 |
2011 |
|
2012 |
2011 |
Commodity Contracts — Exploration & Production segment |
$ (11,776)
|
$ 24,713
|
Operating Revenue |
$ 54,777
|
$ 6,367
|
Not Applicable |
$— |
$— |
Commodity Contracts — Energy Marketing segment |
$ 4,725
|
$ 5,015
|
Purchased Gas |
$ 10,439
|
$ 8,608
|
Not Applicable |
$— |
$— |
Commodity Contracts — Pipeline & Storage segment(1) |
$ (197)
|
$ 510
|
Operating Revenue |
$ 475
|
$ 510
|
Not Applicable |
$— |
$— |
Total............................................ |
$ (7,248)
|
$ 30,238
|
|
$ 65,691
|
$ 15,485
|
|
$— |
$— |
(1) |
There were no open hedging positions at September 30, 2012 or 2011. |
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 certain 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, 2012, the Company’s Energy Marketing segment had fair value hedges covering approximately 10.2 Bcf (8.7 Bcf of fixed price sales commitments (all long positions), 1.1 Bcf of fixed price purchase commitments (all short positions) and 0.4 Bcf of commitments related to the withdrawal of storage gas (all short positions)). For derivative instruments that are designated and qualify as a fair value hedge, the gain or loss on the derivative as well as the offsetting gain or loss on the hedged item attributable to the hedged risk completely offset each other in current earnings, as shown below.
Consolidated Statement of Income |
Gain/(Loss) on Derivative |
Gain/(Loss) on Commitment |
Operating Revenues..................................................................................................................... |
$ 8,021,910
|
$ (8,021,910)
|
Purchased Gas................................................................................................................................ |
$ (1,235,817)
|
$ 1,235,817
|
Derivatives in Fair Value Hedging Relationships – Energy Marketing segment |
Location of Derivative Gain or (Loss) Recognized in the Consolidated Statement of Income |
Amount of Derivative Gain or (Loss) Recognized in the Consolidated Statement of Income for the Year Ended September 30, 2012 |
|
(In thousands) |
|
Commodity Contracts — Hedge of fixed price sales commitments of natural gas.... |
Operating Revenues |
$ 8,022
|
Commodity Contracts — Hedge of fixed price purchase commitments of natural gas |
Purchased Gas |
(1,261) |
Commodity Contracts — Hedge of natural gas held in storage............................................ |
Purchased Gas |
25 |
|
|
$ 6,786
|
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 twelve counterparties of which four are in a net gain position. On average, the Company had $6.4 million of credit exposure per counterparty in a gain position at September 30, 2012. The maximum credit exposure per counterparty in a gain position at September 30, 2012 was $11.0 million. As of September 30, 2012, the Company had not received any collateral from the counterparties. 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, nor had the counterparties’ credit ratings declined to levels at which the counterparties were required to post collateral.
As of September 30, 2012, ten of the twelve 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 (applicable debt ratings), 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 (or if the current liability were larger) and/or the Company’s credit rating declined, then additional hedging collateral deposits may be required. At September 30, 2012, the fair market value of the derivative financial instrument assets with a credit-risk related contingency feature was $14.0 million according to the Company’s internal model (discussed in Note F — Fair Value Measurements). At September 30, 2012, the fair market value of the derivative financial instrument liabilities with a credit-risk related contingency feature was $23.9 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 were in a liability position, the Company was not required to post any hedging collateral deposits at September 30, 2012.
For its exchange traded futures contracts which are in a liability position, the Company had posted $0.4 million in hedging collateral deposits as of September 30, 2012. 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.
|
Note H — Retirement Plan and Other Post-Retirement Benefits
The Company has a tax-qualified, noncontributory, defined-benefit retirement plan (Retirement Plan) that covers approximately half 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 $0.9 million, $0.7 million and $0.6 million for the years ended September 30, 2012, 2011 and 2010, 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 $4.3 million, $4.3 million, and $4.2 million for the years ended September 30, 2012, 2011 and 2010, 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.
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 for fiscal year 2012, 2011 and 2010.
|
Retirement Plan |
Other Post-Retirement Benefits |
||||
|
Year Ended September 30 |
Year Ended September 30 |
||||
|
2012 |
2011 |
2010 |
2012 |
2011 |
2010 |
|
(Thousands) |
|||||
Change in Benefit Obligation |
|
|
|
|
|
|
Benefit Obligation at Beginning of Period.. |
$ 949,777
|
$ 924,493
|
$ 831,496
|
$ 485,452
|
$ 472,407
|
$ 467,295
|
Service Cost........................................................... |
14,202 | 14,772 | 12,997 | 4,016 | 4,276 | 4,298 |
Interest Cost........................................................... |
41,526 | 42,676 | 44,308 | 21,315 | 21,884 | 25,017 |
Plan Participants’ Contributions...................... |
— |
— |
— |
1,956 | 1,963 | 1,644 |
Retiree Drug Subsidy Receipts...................... |
— |
— |
— |
1,528 | 1,532 | 1,354 |
Amendments(1)...................................................... |
— |
(1,764) |
— |
— |
(7,187) |
— |
Actuarial (Gain) Loss........................................... |
120,338 | 21,395 | 85,831 | 71,708 | 15,071 | (3,635) |
Benefits Paid........................................................... |
(55,099) | (51,795) | (50,139) | (24,712) | (24,494) | (23,566) |
Benefit Obligation at End of Period.............. |
$ 1,070,744
|
$ 949,777
|
$ 924,493
|
$ 561,263
|
$ 485,452
|
$ 472,407
|
Change in Plan Assets |
|
|
|
|
|
|
Fair Value of Assets at Beginning of Period |
$ 601,719
|
$ 597,549
|
$ 563,881
|
$ 351,990
|
$ 353,269
|
$ 319,022
|
Actual Return on Plan Assets......................... |
111,034 | 2,412 | 61,625 | 63,552 | (4,094) | 30,478 |
Employer Contributions...................................... |
44,022 | 53,553 | 22,182 | 21,348 | 25,346 | 25,691 |
Plan Participants’ Contributions...................... |
— |
— |
— |
1,956 | 1,963 | 1,644 |
Benefits Paid........................................................... |
(55,099) | (51,795) | (50,139) | (24,712) | (24,494) | (23,566) |
Fair Value of Assets at End of Period......... |
$ 701,676
|
$ 601,719
|
$ 597,549
|
$ 414,134
|
$ 351,990
|
$ 353,269
|
Net Amount Recognized at End of Period (Funded Status) |
$ (369,068)
|
$ (348,058)
|
$ (326,944)
|
$ (147,129)
|
$ (133,462)
|
$ (119,138)
|
Amounts Recognized in the Balance Sheets Consist of: |
|
|
|
|
|
|
Non-Current Liabilities......................................... |
$ (369,068)
|
$ (348,058)
|
$ (326,944)
|
$ (147,129)
|
$ (133,462)
|
$ (119,138)
|
Accumulated Benefit Obligation..................... |
$ 986,223
|
$ 874,595
|
$ 843,526
|
N/A |
N/A |
N/A |
Weighted Average Assumptions Used to Determine Benefit Obligation at September 30 |
|
|
|
|
|
|
Discount Rate......................................................... |
3.50% | 4.50% | 4.75% | 3.50% | 4.50% | 4.75% |
Rate of Compensation Increase.................... |
4.75% | 4.75% | 4.75% | 4.75% | 4.75% | 4.75% |
Components of Net Periodic Benefit Cost |
|
|
|
|
|
|
Service Cost........................................................... |
$ 14,202
|
$ 14,772
|
$ 12,997
|
$ 4,016
|
$ 4,276
|
$ 4,298
|
Interest Cost........................................................... |
41,526 | 42,676 | 44,308 | 21,315 | 21,884 | 25,017 |
Expected Return on Plan Assets................... |
(59,701) | (59,103) | (58,342) | (28,971) | (29,165) | (26,334) |
Amortization of Prior Service Cost............... |
269 | 588 | 655 | (2,138) | (1,710) | (1,710) |
Amortization of Transition Amount................ |
— |
— |
— |
10 | 541 | 541 |
Recognition of Actuarial Loss(2).................... |
39,615 | 34,873 | 21,641 | 24,057 | 23,794 | 25,881 |
Net Amortization and Deferral for Regulatory Purposes |
(6,900) | (2,311) | (30) | 6,162 | 10,490 | 351 |
Net Periodic Benefit Cost................................. |
$ 29,011
|
$ 31,495
|
$ 21,229
|
$ 24,451
|
$ 30,110
|
$ 28,044
|
Weighted Average Assumptions Used to Determine Net Periodic Benefit Cost at September 30 |
|
|
|
|
|
|
Discount Rate......................................................... |
4.50% | 4.75% | 5.50% | 4.50% | 4.75% | 5.50% |
Expected Return on Plan Assets................... |
8.25% | 8.25% | 8.25% | 8.25% | 8.25% | 8.25% |
Rate of Compensation Increase.................... |
4.75% | 4.75% | 5.00% | 4.75% | 4.75% | 5.00% |
(1) | In fiscal 2011, the Company passed an amendment which changed the definition of annual compensation prospectively to exclude certain bonuses paid by Seneca after September 30, 2011. This decreased the benefit obligation of the Retirement Plan. In fiscal 2011, the Company also increased the prescription drug co-payments for certain retired participants which decreased the benefit obligation of the other post-retirement benefits. |
(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.
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 $9.1 million, $8.6 million and $7.4 million in 2012, 2011 and 2010, respectively. The accumulated benefit obligations for the plans were $54.5 million, $46.0 million and $41.8 million at September 30, 2012, 2011 and 2010, respectively. The projected benefit obligations for the plans were $88.5 million, $79.2 million and $73.9 million at September 30, 2012, 2011 and 2010, respectively. The projected benefit obligations are recorded in Other Deferred Credits on the Consolidated Balance Sheets. The actuarial valuations for the plans were determined based on a discount rate of 2.50%, 3.75% and 4.25% as of September 30, 2012, 2011 and 2010, respectively and a weighted average rate of compensation increase of 7.75%, 8.0% and 8.0% as of September 30, 2012, 2011 and 2010, respectively.
The cumulative amounts recognized in accumulated other comprehensive income (loss), regulatory assets, and regulatory liabilities through fiscal 2012, the changes in such amounts during 2012, as well as the amounts expected to be recognized in net periodic benefit cost in fiscal 2013 are presented in the table below:
|
Retirement Plan |
Other Post-Retirement Benefits |
Non-Qualified Benefit Plans |
|
(Thousands) |
||
Amounts Recognized in Accumulated Other Comprehensive Income (Loss), Regulatory Assets and Regulatory Liabilities(1) |
|
|
|
Net Actuarial Loss.......................................................................................................................................... |
$ (458,125)
|
$ (195,305)
|
$ (40,770)
|
Transition Obligation....................................................................................................................................... |
— |
(8) |
— |
Prior Service (Cost) Credit......................................................................................................................... |
(1,304) | 11,217 |
— |
Net Amount Recognized.............................................................................................................................. |
$ (459,429)
|
$ (184,096)
|
$ (40,770)
|
Changes to Accumulated Other Comprehensive Income (Loss), Regulatory Assets and Regulatory Liabilities Recognized During Fiscal 2012(1) |
|
|
|
Increase in Actuarial Loss, excluding amortization(2).................................................................... |
$ (69,005)
|
$ (37,134)
|
$ (9,559)
|
Change due to Amortization of Actuarial Loss.................................................................................. |
39,615 | 24,057 | 4,363 |
Reduction in Transition Obligation........................................................................................................... |
— |
10 |
— |
Prior Service (Cost) Credit......................................................................................................................... |
269 | (2,138) |
— |
Net Change........................................................................................................................................................ |
$ (29,121)
|
$ (15,205)
|
$ (5,196)
|
Amounts Expected to be Recognized in Net Periodic Benefit Cost in the Next Fiscal Year(1) |
|
|
|
Net Actuarial Loss.......................................................................................................................................... |
$ (52,776)
|
$ (20,892)
|
$ (5,280)
|
Transition Obligation....................................................................................................................................... |
— |
(8) |
— |
Prior Service (Cost) Credit......................................................................................................................... |
(238) | 2,138 |
— |
Net Amount Expected to be Recognized............................................................................................. |
$ (53,014)
|
$ (18,762)
|
$ (5,280)
|
(1) | Amounts presented are shown before recognizing deferred taxes. |
(2) Amounts presented include the impact of actuarial gains/losses related to return on assets, as well as the Actuarial (Gain) Loss amounts presented in the Change in Benefit Obligation.
In order to adjust the funded status of its pension (tax-qualified and non-qualified) and other post-retirement benefit plans at September 30, 2012, the Company recorded a $32.2 million increase to Other Regulatory Assets in the Company’s Utility and Pipeline and Storage segments and a $17.3 million (pre-tax) increase to Accumulated Other Comprehensive Loss.
The effect of the discount rate change for the Retirement Plan in 2012 was to increase the projected benefit obligation of the Retirement Plan by $118.8 million. In 2012, other actuarial experience increased the projected benefit obligation for the Retirement Plan by $1.6 million. The effect of the discount rate change for the Retirement Plan in 2011 was to increase the projected benefit obligation of the Retirement Plan by $26.9 million. 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.
The Company made cash contributions totaling $44.0 million to the Retirement Plan during the year ended September 30, 2012. The Company expects that the annual contribution to the Retirement Plan in 2013 will be in the range of $30.0 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 2013 in order to be in compliance with the Pension Protection Act of 2006 (as impacted by the Moving Ahead for Progress in the 21st Century Act). In July 2012, the Surface Transportation Extension Act, which is also referred to as the Moving Ahead for Progress in the 21st Century Act (the Act), was passed by Congress and signed by the President. The Act included pension funding stabilization provisions. The Company is currently in the process of evaluating its future contributions in light of the provisions of the Act.
The following Retirement Plan benefit payments, which reflect expected future service, are expected to be paid by the Retirement Plan during the next five years and the five years thereafter: $55.9 million in 2013; $56.5 million in 2014; $57.3 million in 2015; $58.5 million in 2016; $59.6 million in 2017; and $315.2 million in the five years thereafter.
The effect of the discount rate change in 2012 was to increase the other post-retirement benefit obligation by $65.6 million. Other actuarial experience increased the other post-retirement benefit obligation in 2012 by $6.1 million.
The effect of the discount rate change in 2011 was to increase the other post-retirement benefit obligation by $14.5 million. Other actuarial experience decreased the other post-retirement benefit obligation in 2011 by $6.6 million, primarily attributable to the impact of the change in prescription drug co-payments as noted above.
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 Medicare Prescription Drug, Improvement, and Modernization Act of 2003 provides for 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 (dollars in thousands):
|
Benefit Payments |
Subsidy Receipts |
2013.......................................................................................................................................................................................... |
$ 26,559
|
$ (1,828)
|
2014.......................................................................................................................................................................................... |
$ 27,852
|
$ (2,021)
|
2015.......................................................................................................................................................................................... |
$ 29,154
|
$ (2,220)
|
2016.......................................................................................................................................................................................... |
$ 30,506
|
$ (2,420)
|
2017.......................................................................................................................................................................................... |
$ 31,859
|
$ (2,606)
|
2018 through 2022............................................................................................................................................................. |
$ 175,145
|
$ (15,964)
|
|
2012 |
|
2011 |
|
2010 |
|
Rate of Increase for Pre Age 65 Participants............................................................................................................ |
7.46% | (1) | 7.64% | (1) | 7.82% | (1) |
Rate of Increase for Post Age 65 Participants......................................................................................................... |
6.84% |
(1) |
6.89% |
(1) |
6.95% |
(1) |
Annual Rate of Increase in the Per Capita Cost of Covered Prescription Drug Benefits.................... |
8.08% |
(1) |
8.39% |
(1) |
8.69% |
(1) |
Annual Rate of Increase in the Per Capita Medicare Part B Reimbursement............................................. |
6.84% |
(1) |
6.89% |
(1) |
6.95% |
(1) |
Annual Rate of Increase in the Per Capita Medicare Part D Subsidy............................................................ |
7.13% |
(1) |
7.30% |
(1) |
7.60% |
(1) |
(1) It was assumed that this rate would gradually decline to 4.5% by 2028.
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, 2012 would increase by $69.7 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 2012 by $3.4 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, 2012 would decrease by $58.1 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 2012 by $2.8 million.
The Company made cash contributions totaling $21.2 million to its VEBA trusts and 401(h) accounts during the year ended September 30, 2012. In addition, the Company made direct payments of $0.1 million to retirees not covered by the VEBA trusts and 401(h) accounts during the year ended September 30, 2012. The Company expects that the annual contribution to its VEBA trusts and 401(h) accounts in 2013 will be in the range of $15.0 million to $20.0 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 methodologies 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, 2012 and 2011, 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, 2012 |
Level 1 |
Level 2 |
Level 3 |
Retirement Plan Investments |
|
|
|
|
Domestic Equities (1)......................................................................................................... |
$ 358,679
|
$ 231,978
|
$ 126,701
|
$ — |
International Equities (2).................................................................................................... |
96,451 | 2,090 | 94,361 |
— |
Domestic Fixed Income (3)............................................................................................. |
165,130 | 70,730 | 94,400 |
— |
International Fixed Income (4)........................................................................................ |
65,835 | 1,941 | 63,894 |
— |
Hedge Fund Investments................................................................................................. |
39,956 |
— |
— |
39,956 |
Real Estate.............................................................................................................................. |
6,170 |
— |
— |
6,170 |
Cash and Cash Equivalents .......................................................................................... |
12,874 |
— |
12,874 |
— |
Total Retirement Plan Investments.............................................................................. |
745,095 | 306,739 | 392,230 | 46,126 |
401(h) Investments............................................................................................................. |
(43,311) | (17,818) | (22,813) | (2,680) |
Total Retirement Plan Investments (excluding 401(h) Investments)........... |
$ 701,784
|
$ 288,921
|
$ 369,417
|
$ 43,446
|
Miscellaneous Accruals, Interest Receivables, and Non-Interest Cash..... |
(108) |
|
|
|
Total Retirement Plan Assets.......................................................................................... |
$ 701,676
|
|
|
|
|
Total Fair Value Amounts at September 30, 2011 |
Level 1 |
Level 2 |
Level 3 |
Retirement Plan Investments |
|
|
|
|
Domestic Equities (1)......................................................................................................... |
$ 313,193
|
$ 215,524
|
$ 97,669
|
$ — |
International Equities (2).................................................................................................... |
79,732 | 11,163 | 68,569 |
— |
Domestic Fixed Income (3)............................................................................................. |
146,587 | 77,657 | 68,930 |
— |
International Fixed Income (4)........................................................................................ |
43,153 | 887 | 42,266 |
— |
Hedge Fund Investments................................................................................................. |
39,296 |
— |
— |
39,296 |
Real Estate.............................................................................................................................. |
6,443 |
— |
— |
6,443 |
Cash and Cash Equivalents .......................................................................................... |
10,629 |
— |
10,629 |
— |
Total Retirement Plan Investments.............................................................................. |
639,033 | 305,231 | 288,063 | 45,739 |
401(h) Investments............................................................................................................. |
(37,176) | (17,744) | (16,773) | (2,659) |
Total Retirement Plan Investments (excluding 401(h) Investments)........... |
$ 601,857
|
$ 287,487
|
$ 271,290
|
$ 43,080
|
Miscellaneous Accruals, Interest Receivables, and Non-Interest Cash..... |
(138) |
|
|
|
Total Retirement Plan Assets.......................................................................................... |
$ 601,719
|
|
|
|
(a) | Domestic Equities include mostly collective trust funds, common stock, and exchange traded funds. |
(b) | International Equities include mostly collective trust funds and common stock. |
(c) | Domestic Fixed Income securities include mostly collective trust funds, corporate/government bonds and mortgages, and exchange traded funds. |
(d) | International Fixed Income securities includes mostly collective trust funds and exchange traded funds. |
|
Total Fair Value Amounts at September 30, 2012 |
Level 1 |
Level 2 |
Level 3 |
Other Post-Retirement Benefit Assets held in VEBA Trusts |
|
|
|
|
Collective Trust Funds — Domestic Equities............................................................ |
$ 179,059
|
$— |
$ 179,059
|
$— |
Collective Trust Funds — International Equities...................................................... |
66,590 |
— |
66,590 |
— |
Exchange Traded Funds — Fixed Income.................................................................. |
107,597 | 107,597 |
— |
— |
Real Estate................................................................................................................................ |
1,305 |
— |
— |
1,305 |
Cash Held in Collective Trust Funds............................................................................. |
16,397 |
— |
16,397 |
— |
Total VEBA Trust Investments.......................................................................................... |
370,948 | 107,597 | 262,046 | 1,305 |
401(h) Investments................................................................................................................ |
43,311 | 17,818 | 22,813 | 2,680 |
Total Investments (including 401(h) Investments).................................................. |
$ 414,259
|
$ 125,415
|
$ 284,859
|
$ 3,985
|
Miscellaneous Accruals (Including Current and Deferred Taxes, Claims Incurred But Not Reported, Administrative) |
(125) |
|
|
|
Total Other Post-Retirement Benefit Assets.............................................................. |
$ 414,134
|
|
|
|
|
Total Fair Value Amounts at September 30, 2011 |
Level 1 |
Level 2 |
Level 3 |
Other Post-Retirement Benefit Assets held in VEBA Trusts |
|
|
|
|
Collective Trust Funds — Domestic Equities............................................................ |
$ 148,451
|
$— |
$ 148,451
|
$— |
Collective Trust Funds — International Equities...................................................... |
55,411 |
— |
55,411 |
— |
Exchange Traded Funds — Fixed Income.................................................................. |
91,214 | 91,214 |
— |
— |
Real Estate................................................................................................................................ |
1,561 |
— |
— |
1,561 |
Cash Held in Collective Trust Funds............................................................................. |
12,890 |
— |
12,890 |
— |
Total VEBA Trust Investments.......................................................................................... |
309,527 | 91,214 | 216,752 | 1,561 |
401(h) Investments................................................................................................................ |
37,176 | 17,744 | 16,773 | 2,659 |
Total Investments (including 401(h) Investments).................................................. |
$ 346,703
|
$ 108,958
|
$ 233,525
|
$ 4,220
|
Miscellaneous Accruals (Including Current and Deferred Taxes, Claims Incurred But Not Reported, Administrative) |
5,287 |
|
|
|
Total Other Post-Retirement Benefit Assets.............................................................. |
$ 351,990
|
|
|
|
The fair values disclosed in the above tables 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, 2012, there was approximately $13.0 million transferred from Level 1 to Level 2, while for the year ended September 30, 2011, 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 |
|||||
|
(Thousands) |
|||||
|
Equity |
|
|
|
Excluding |
|
|
Convertible |
Hedge |
Limited |
Real |
401(h) |
|
|
Securities |
Funds |
Partnerships |
Estate |
Investments |
Total |
Balance at September 30, 2010....................................................... |
$ 337
|
$ — |
$ 245
|
$ 6,148
|
$ (367)
|
$ 6,363
|
Realized Gains/(Losses)...................................................................... |
53 |
— |
(4,846) | 20 | 278 | (4,495) |
Unrealized Gains/(Losses).................................................................. |
(36) | (789) | 4,853 | 159 | (268) | 3,919 |
Purchases, Sales, Issuances, and Settlements (Net).......... |
(354) | 40,085 | (252) | 116 | (2,302) | 37,293 |
Balance at September 30, 2011....................................................... |
— |
39,296 |
— |
6,443 | (2,659) | 43,080 |
Realized Gains/(Losses)...................................................................... |
— |
— |
— |
60 | (4) | 56 |
Unrealized Gains/(Losses).................................................................. |
— |
660 |
— |
(362) | (15) | 283 |
Purchases, Sales, Issuances, and Settlements (Net).......... |
— |
— |
— |
29 | (2) | 27 |
Balance at September 30, 2012 ..................................................... |
$ — |
$ 39,956
|
$ — |
$ 6,170
|
$ (2,680)
|
$ 43,446
|
|
|
|
|
|
|
|
|
|
Other Post-Retirement Benefit Level 3 Assets |
|||||||
|
|
(Thousands) |
|||||||
|
VEBA |
|
|
|
|||||
|
Trust |
|
Other |
|
|||||
|
Investments Real |
Including 401(h) |
Post-Retirement Benefit |
|
|||||
|
Estate |
Investments |
Investments |
|
|||||
Balance at September 30, 2010......................................................................... |
$ 3,824
|
$ 367
|
$ 4,191
|
|
|||||
Realized Gains/(Losses)........................................................................................ |
— |
(278) | (278) |
|
|||||
Unrealized Gains/(Losses).................................................................................... |
(2,263) | 268 | (1,995) |
|
|||||
Purchases, Sales, Issuances, and Settlements (Net)............................ |
— |
2,302 | 2,302 |
|
|||||
Balance at September 30, 2011......................................................................... |
1,561 | 2,659 | 4,220 |
|
|||||
Realized Gains/(Losses)........................................................................................ |
— |
4 | 4 |
|
|||||
Unrealized Gains/(Losses).................................................................................... |
(256) | 15 | (241) |
|
|||||
Purchases, Sales, Issuances, and Settlements (Net)............................ |
— |
2 | 2 |
|
|||||
Balance at September 30, 2012......................................................................... |
$ 1,305
|
$ 2,680
|
$ 3,985
|
|
|||||
|
|
|
|
|
The Company’s assumption regarding the expected long-term rate of return on plan assets is 8.0%, effective for fiscal 2013. 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). The target allocation for the Retirement Plan is 55-70% equity securities, 25-40% fixed income securities and 5-20% other. The target allocation for the VEBA trusts (including 401(h) accounts) is 60-75% equity securities, 25-40% fixed income securities and 0-15% other. 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 3.50% as of September 30, 2012. The discount rate which is used to present value the future benefit payment obligations of the Non-Qualified benefit plans is 2.50% as of September 30, 2012. 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.
|
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, 2012, 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 $15.4 million to $19.6 million. The minimum estimated liability of $15.4 million has been recorded in Other Deferred Credits on the Consolidated Balance Sheet at September 30, 2012. The Company expects to recover its environmental clean-up costs through rate recovery over a period of approximately 10 years. Other than as discussed below, the Company is currently not aware of any material exposure to environmental liabilities. However, changes in environmental laws and 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. In February 2009, the Company received approval from the NYDEC of a Remedial Design Work Plan (RDWP) for this site. In October 2010, the Company submitted a RDWP addendum to conduct additional Preliminary Design Investigation field activities necessary to design a successful remediation. An estimated minimum liability for remediation of this site of $14.0 million has been recorded.
(ii) Other
In November 2010, the NYDEC notified the Company of its potential liability with respect to a remedial action at a former industrial site 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 this site have not been completed and the Company cannot estimate its liability, if any, regarding remediation of this site at this time. In July 2011, the Company agreed to perform a limited scope of work at this site, which is pending.
Other
The Company, in its Utility segment, Energy Marketing segment, and Exploration and Production segment, 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. The majority 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: $278.1 million in 2013, $68.1 million in 2014, $64.1 million in 2015, $60.2 million in 2016, $32.3 million in 2017 and $66.6 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 compressors, drilling rigs, buildings, meters 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: $38.7 million in 2013, $37.0 million in 2014, $13.2 million in 2015, $5.8 million in 2016, $5.7 million in 2017, and $8.5 million thereafter.
The Company, in its Pipeline and Storage segment and All Other category, has entered into several contractual commitments associated with various pipeline and gathering system expansion projects. As of September 30, 2012, the future contractual commitments related to the expansion projects are $40.7 million in 2013. There are no contractual commitments extending beyond 2013.
The Company, in its Exploration and Production segment, has entered into contractual obligations associated with hydraulic fracturing and fuel. The future contract commitments during the next two years are as follows: $60.7 million in 2013 and $11.4 million in 2014.
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 other matters arising in the normal course of business could have a material effect on earnings and cash flows in the period in which they are resolved, an estimate of the possible loss or range of loss, if any, cannot be made at this time.
|
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 |
|
(Thousands) |
Operating Revenues........................................................................................................................................................... |
$ 9,919
|
Operating Expenses............................................................................................................................................................ |
8,933 |
Operating Income................................................................................................................................................................. |
986 |
Other Income.......................................................................................................................................................................... |
4 |
Interest Income..................................................................................................................................................................... |
2 |
Interest Expense................................................................................................................................................................... |
29 |
Income before Income Taxes......................................................................................................................................... |
963 |
Income Tax Expense........................................................................................................................................................... |
493 |
Income from Discontinued Operations....................................................................................................................... |
470 |
Gain on Disposal, Net of Taxes of $4,024............................................................................................................... |
6,310 |
Income from Discontinued Operations....................................................................................................................... |
$ 6,780
|
|
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 to major industrial companies, utilities (including Distribution Corporation) and power producers in New York State.
The Exploration and Production segment, through Seneca, is engaged in exploration for, and development and purchase of, natural gas and oil reserves in California, the Appalachian region of the United States and Kansas. The Company completed the sale of its off-shore oil and natural gas properties in April 2011 as a result of the segment’s increasing emphasis on the Marcellus Shale play within the Appalachian region. Seneca’s production is, for the most part, sold to purchasers located in the vicinity of its wells. In November 2010, the Company acquired oil and gas properties in the Covington Township area of Tioga County, Pennsylvania from EOG Resources, Inc. for approximately $24.1 million. In addition, the Company acquired two tracts of leasehold acreage in March 2010 for approximately $71.8 million. These tracts, consisting of approximately 18,000 net acres in Tioga and Potter Counties in Pennsylvania, are geographically similar to the Company’s existing Marcellus Shale acreage in the area.
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, 2012 |
|||||||
|
Utility |
Pipeline and Storage |
Exploration and Production |
Energy Marketing |
Total Reportable Segments |
All Other |
Corporate and Intersegment Eliminations |
Total Consolidated |
|
(Thousands) |
|||||||
Revenue from External Customers(1) |
$ 704,518
|
$ 172,312
|
$ 558,180
|
$ 186,579
|
$ 1,621,589
|
$ 4,307
|
$ 957
|
$ 1,626,853
|
Intersegment Revenues..................... |
$ 14,604
|
$ 86,963
|
$ — |
$ 1,425
|
$ 102,992
|
$ 16,771
|
$ (119,763)
|
$— |
Interest Income...................................... |
$ 2,765
|
$ 199
|
$ 1,493
|
$ 188
|
$ 4,645
|
$ 175
|
$ (1,131)
|
$ 3,689
|
Interest Expense.................................... |
$ 33,181
|
$ 25,603
|
$ 29,243
|
$ 41
|
$ 88,068
|
$ 1,738
|
$ (3,566)
|
$ 86,240
|
Depreciation, Depletion and Amortization |
$ 42,757
|
$ 38,182
|
$ 187,624
|
$ 90
|
$ 268,653
|
$ 2,091
|
$ 786
|
$ 271,530
|
Income Tax Expense (Benefit)........ |
$ 29,110
|
$ 37,655
|
$ 79,050
|
$ 1,933
|
$ 147,748
|
$ 4,335
|
$ (1,529)
|
$ 150,554
|
Segment Profit: Net Income (Loss) |
$ 58,590
|
$ 60,527
|
$ 96,498
|
$ 4,169
|
$ 219,784
|
$ 6,868
|
$ (6,575)
|
$ 220,077
|
Expenditures for Additions to Long-Lived Assets |
$ 58,284
|
$ 144,167
|
$ 693,810
|
$ 770
|
$ 897,031
|
$ 80,017
|
$ 346
|
$ 977,394
|
|
At September 30, 2012 |
|||||||
|
(Thousands) |
|||||||
Segment Assets......................... |
$ 2,070,413
|
$ 1,243,862
|
$ 2,367,485
|
$ 61,968
|
$ 5,743,728
|
$ 209,934
|
$ (18,520)
|
$ 5,935,142
|
|
Year Ended September 30, 2011 |
|||||||
|
Utility |
Pipeline and Storage |
Exploration and Production |
Energy Marketing |
Total Reportable Segments |
All Other |
Corporate and Intersegment Eliminations |
Total Consolidated |
|
(Thousands) |
|||||||
Revenue from External Customers(1) |
$ 835,853
|
$ 134,071
|
$ 519,035
|
$ 284,546
|
$ 1,773,505
|
$ 4,401
|
$ 936
|
$ 1,778,842
|
Intersegment Revenues..................... |
$ 16,642
|
$ 81,037
|
$ — |
$ 420
|
$ 98,099
|
$ 10,017
|
$ (108,116)
|
$— |
Interest Income...................................... |
$ 2,049
|
$ 324
|
$ (27)
|
$ 104
|
$ 2,450
|
$ 247
|
$ 219
|
$ 2,916
|
Interest Expense.................................... |
$ 34,440
|
$ 25,737
|
$ 17,402
|
$ 20
|
$ 77,599
|
$ 2,173
|
$ (1,651)
|
$ 78,121
|
Depreciation, Depletion and Amortization |
$ 40,808
|
$ 37,266
|
$ 146,806
|
$ 47
|
$ 224,927
|
$ 840
|
$ 760
|
$ 226,527
|
Income Tax Expense (Benefit)........ |
$ 33,325
|
$ 19,854
|
$ 89,034
|
$ 4,489
|
$ 146,702
|
$ 18,961
|
$ (1,282)
|
$ 164,381
|
Gain on Sale of Unconsolidated Subsidiaries |
$— |
$— |
$ — |
$— |
$— |
$50,879(2) |
$— |
$ 50,879
|
Segment Profit: Net Income (Loss) |
$ 63,228
|
$ 31,515
|
$ 124,189
|
$ 8,801
|
$ 227,733
|
$ 38,502
|
$ (7,833)
|
$ 258,402
|
Expenditures for Additions to Long-Lived Assets |
$ 58,398
|
$ 129,206
|
$ 648,815
|
$ 460
|
$ 836,879
|
$ 17,022
|
$ 285
|
$ 854,186
|
|
At September 30, 2011 |
|||||||
|
(Thousands) |
|||||||
Segment Assets......................... |
$ 2,001,546
|
$ 1,112,494
|
$ 1,885,014
|
$ 71,138
|
$ 5,070,192
|
$ 166,730
|
$ (15,838)
|
$ 5,221,084
|
|
Year Ended September 30, 2010 |
|||||||
|
Utility |
Pipeline and Storage |
Exploration and Production |
Energy Marketing |
Total Reportable Segments |
All Other |
Corporate and Intersegment Eliminations |
Total Consolidated |
|
(Thousands) |
|||||||
Revenue from External Customers(1) |
$ 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
|
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........................... |
$ 2,027,101
|
$ 1,080,772
|
$ 1,539,705
|
$ 69,561
|
$ 4,717,139
|
$ 198,706
|
$ 131,209
|
$ 5,047,054
|
(1) |
All Revenue from External Customers originated in the United States. |
|
|
(2) |
In February 2011, the Company sold its 50% equity method investments in Seneca Energy and Model City for $59.4 million, resulting in a gain of $50.9 million. |
|
|
|
|
|
|
||
|
|
||||
Geographic Information |
At September 30 |
||||
|
2012 |
2011 |
2010 |
||
|
(Thousands) |
||||
Long-Lived Assets: |
|
|
|
||
United States....................................................................................................................................................... |
$ 5,579,566
|
$ 4,809,183
|
$ 4,238,253
|
||
|
|
|
Note L — 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 Income |
Earnings per |
|
Quarter |
Operating |
Operating |
Available for |
Common Share |
|
Ended |
Revenues |
Income |
Common Stock |
Basic |
Diluted |
|
(Thousands, except per common share amounts) |
||||
2012 |
|
|
|
|
|
9/30/2012......................................................................................... |
$ 313,261
|
$ 107,265
|
$48,802(1) |
$ 0.59
|
$ 0.58
|
6/30/2012......................................................................................... |
$ 328,861
|
$ 90,293
|
$ 43,184
|
$ 0.52
|
$ 0.52
|
3/31/2012......................................................................................... |
$ 552,308
|
$ 132,097
|
$67,392(2) |
$ 0.81
|
$ 0.81
|
12/31/2011....................................................................................... |
$ 432,423
|
$ 118,394
|
$ 60,699
|
$ 0.73
|
$ 0.73
|
2011 |
|
|
|
|
|
9/30/2011......................................................................................... |
$ 286,034
|
$ 75,191
|
$ 37,356
|
$ 0.45
|
$ 0.45
|
6/30/2011......................................................................................... |
$ 380,979
|
$ 94,805
|
$ 46,891
|
$ 0.57
|
$ 0.56
|
3/31/2011......................................................................................... |
$ 660,881
|
$ 153,756
|
$115,611(3) |
$ 1.40
|
$ 1.38
|
12/31/2010...................................................................................... |
$ 450,948
|
$ 117,410
|
$ 58,544
|
$ 0.71
|
$ 0.70
|
(1)
(2)
(3) |
Includes $12.8 million of income associated with the elimination of Supply Corporation’s post-retirement regulatory liability as specified in Supply Corporation’s rate case settlement.
Includes a $4.0 million accrual of a natural gas impact fee related to wells drilled prior to 2012 that was first imposed by Pennsylvania in 2012. This fee was recorded in the Exploration and Production segment.
Includes a $31.4 million after tax gain on the sale of the Company’s 50% equity method investments in Seneca Energy and Model City.
|
|
Note N — 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 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. As discussed in Note A, the Company completed the sale of its off-shore oil and natural gas properties in the Gulf of Mexico in April 2011. With the completion of this sale, the Company no longer has any off-shore oil and gas properties.
Capitalized Costs Relating to Oil and Gas Producing Activities
|
At September 30 |
|
|
2012 |
2011 |
|
(Thousands) |
|
Proved Properties(1)..................................................................................................................................................................... |
$ 2,789,181
|
$ 2,010,662
|
Unproved Properties..................................................................................................................................................................... |
146,084 | 226,276 |
|
2,935,265 | 2,236,938 |
Less — Accumulated Depreciation, Depletion and Amortization............................................................................. |
681,798 | 499,671 |
|
$ 2,253,467
|
$ 1,737,267
|
(1) |
Includes asset retirement costs of $43.1 million and $32.7 million at September 30, 2012 and 2011, 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. Although the timing of the ultimate evaluation or disposition of the unproved properties cannot be determined, the Company expects the majority of its acquisition costs associated with unproved properties to be transferred into the amortization base by 2020. It expects the majority of its development and exploration costs associated with unproved properties to be transferred into the amortization base by 2014 or 2015. Following is a summary of costs excluded from amortization at September 30, 2012:
|
Total |
|
|||
|
as of |
|
|||
|
September 30, |
Year Costs Incurred |
|||
|
2012 |
2012 |
2011 |
2010 |
Prior |
|
(Thousands) |
||||
Acquisition Costs.............................................................................................................. |
$ 87,280
|
$ 6,195
|
$— |
$ 69,206
|
$ 11,879
|
Development Costs........................................................................................................ |
21,947 | 15,225 | 6,722 |
— |
— |
Exploration Costs............................................................................................................. |
33,891 | 33,891 |
— |
— |
— |
Capitalized Interest.......................................................................................................... |
2,966 | 2,966 |
— |
— |
— |
|
$ 146,084
|
$ 58,277
|
$ 6,722
|
$ 69,206
|
$ 11,879
|
Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities
|
Year Ended September 30 |
||
|
2012 |
2011 |
2010 |
United States |
(Thousands) |
||
Property Acquisition Costs: |
|
|
|
Proved.......................................................................................................................................................................... |
$ 13,095
|
$ 28,838
|
$ 790
|
Unproved.................................................................................................................................................................... |
13,867 | 20,012 | 80,221 |
Exploration Costs (1)............................................................................................................................................. |
84,624 | 62,651 |
75,155 |
Development Costs (2)........................................................................................................................................ |
576,397 | 531,372 | 234,094 |
Asset Retirement Costs...................................................................................................................................... |
10,344 | 12,087 | 3,901 |
|
$ 698,327
|
$ 654,960
|
$ 394,161
|
(1) |
Amounts for 2012, 2011 and 2010 include capitalized interest of $1.0 million, $0.8 million and $0.2 million, respectively. |
|
|
(2) |
Amounts for 2012, 2011 and 2010 include capitalized interest of $2.0 million, $0.7 million and $0.9 million, respectively. |
For the years ended September 30, 2012, 2011 and 2010, the Company spent $216.6 million, $199.2 million and $28.9 million, respectively, developing proved undeveloped reserves.
Results of Operations for Producing Activities
|
Year Ended September 30 |
||
|
2012 |
2011 |
2010 |
|
(Thousands, except per Mcfe amounts) |
||
United States |
|
|
|
Operating Revenues: |
|
|
|
Natural Gas (includes revenues from sales to affiliates of $1, $23 and $253, respectively) |
$ 181,544
|
$ 223,648
|
$ 152,163
|
Oil, Condensate and Other Liquids................................................................................................................... |
307,018 | 273,952 | 233,569 |
Total Operating Revenues(1)............................................................................................................................... |
488,562 | 497,600 | 385,732 |
Production/Lifting Costs........................................................................................................................................ |
83,361 | 73,250 | 61,398 |
Franchise/Ad Valorem Taxes............................................................................................................................... |
23,620 | 12,179 | 10,592 |
Accretion Expense................................................................................................................................................... |
3,084 | 3,668 | 5,444 |
Depreciation, Depletion and Amortization ($2.19, $2.12 and $2.10 per Mcfe of production) |
182,759 | 143,372 | 104,092 |
Income Tax Expense ............................................................................................................................................. |
81,904 | 110,117 | 83,946 |
Results of Operations for Producing Activities (excluding corporate overheads and interest charges) |
$ 113,834
|
$ 155,014
|
$ 120,260
|
(1) |
Exclusive of hedging gains and losses. See further discussion in Note G — Financial Instruments. |
|
|
Reserve Quantity Information
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 nine 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 that determines 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 a professional engineer registered with the State of Texas (with 14 years of experience in petroleum engineering and consulting at NSAI since 2004) and a professional geoscientist registered in the State of Texas (with 15 years of experience in petroleum geosciences and consulting at NSAI since 2008). NSAI was satisfied with the methods and procedures used by the Company to prepare its reserve estimates at September 30, 2012 and did not identify any problems which would cause it to take exception to those estimates.
The reliable technologies that were utilized in estimating the reserves include wire line open-hole log data, performance data, log cross sections, core data, 2D and 3D seismic data and statistical analysis. The statistical method utilized production performance from both the Company's and competitors’ wells. Geophysical data include data from the Company's wells, published documents, and state data-sites, and 2D and 3D seismic data. These were used to confirm continuity of the formation.
|
|
||||
|
Gas MMcf |
||||
|
U. S.
|
||||
|
Appalachian Region |
|
West Coast Region |
Gulf Coast Region |
Total Company |
Proved Developed and Undeveloped Reserves: |
|
|
|
|
|
September 30, 2009.................................................................................................................................. |
149,828 |
|
72,959 | 26,167 | 248,954 |
Extensions and Discoveries................................................................................................................. |
189,979 | (1) | 269 | 2,881 | 193,129 |
Revisions of Previous Estimates...................................................................................................... |
7,677 |
|
2,315 | 6,683 | 16,675 |
Production...................................................................................................................................................... |
(16,222) | (2) | (3,819) | (10,304) | (30,345) |
September 30, 2010.................................................................................................................................. |
331,262 |
|
71,724 | 25,427 | 428,413 |
Extensions and Discoveries................................................................................................................. |
249,047 | (1) | 195 | 158 | 249,400 |
Revisions of Previous Estimates...................................................................................................... |
24,486 |
|
526 | 1,373 | 26,385 |
Production...................................................................................................................................................... |
(42,979) | (2) | (3,447) | (4,041) | (50,467) |
Purchases of Minerals in Place........................................................................................................... |
44,790 |
|
— |
— |
44,790 |
Sales of Minerals in Place...................................................................................................................... |
— |
|
(682) | (22,917) | (23,599) |
September 30, 2011.................................................................................................................................. |
606,606 |
|
68,316 |
— |
674,922 |
Extensions and Discoveries................................................................................................................. |
435,460 | (1) | 638 |
— |
436,098 |
Revisions of Previous Estimates...................................................................................................... |
(53,992) |
|
(2,463) |
— |
(56,455) |
Production...................................................................................................................................................... |
(62,663) | (2) | (3,468) |
— |
(66,131) |
September 30, 2012.................................................................................................................................. |
925,411 |
|
63,023 |
— |
988,434 |
|
|
|
|
|
|
Proved Developed Reserves: |
|
|
|
|
|
September 30, 2009.................................................................................................................................. |
120,579 |
|
67,603 | 18,051 | 206,233 |
September 30, 2010.................................................................................................................................. |
210,817 |
|
66,178 | 19,293 | 296,288 |
September 30, 2011.................................................................................................................................. |
350,458 |
|
63,965 |
— |
414,423 |
September 30, 2012.................................................................................................................................. |
544,560 |
|
59,923 |
— |
604,483 |
Proved Undeveloped Reserves: |
|
|
|
|
|
September 30, 2009.................................................................................................................................. |
29,249 |
|
5,356 | 8,116 | 42,721 |
September 30, 2010.................................................................................................................................. |
120,445 |
|
5,546 | 6,134 | 132,125 |
September 30, 2011.................................................................................................................................. |
256,148 |
|
4,351 |
— |
260,499 |
September 30, 2012.................................................................................................................................. |
380,851 |
|
3,100 |
— |
383,951 |
(1) |
Extensions and discoveries include 182 Bcf (during 2010), 249 Bcf (during 2011) and 435 Bcf (during 2012), of Marcellus Shale gas in the Appalachian Region. |
|
|
(2) |
Production includes 7,180 MMcf (during 2010), 35,356 MMcf (during 2011) and 55,812 MMcf (during 2012), from Marcellus Shale fields (which exceed 15% of total reserves). |
|
Oil Mbbl |
|||
|
U. S. |
|
||
|
Appalachian Region |
West Coast Region |
Gulf Coast Region |
Total Company |
Proved Developed and Undeveloped Reserves: |
|
|
|
|
September 30, 2009......................................................................................................................................... |
311 | 44,824 | 1,452 | 46,587 |
Extensions and Discoveries........................................................................................................................ |
4 | 828 | 222 | 1,054 |
Revisions of Previous Estimates............................................................................................................. |
2 | 484 | 332 | 818 |
Production............................................................................................................................................................. |
(49) |
(2,669)(1) |
(502) | (3,220) |
September 30, 2010......................................................................................................................................... |
268 | 43,467 | 1,504 | 45,239 |
Extensions and Discoveries........................................................................................................................ |
10 | 756 | 1 | 767 |
Revisions of Previous Estimates............................................................................................................. |
46 | 1,909 | (339) | 1,616 |
Production............................................................................................................................................................. |
(45) | (2,628) | (187) | (2,860) |
Sales of Minerals in Place............................................................................................................................. |
— |
(438) | (979) | (1,417) |
September 30, 2011......................................................................................................................................... |
279 | 43,066 |
— |
43,345 |
Extensions and Discoveries........................................................................................................................ |
28 | 1,229 |
— |
1,257 |
Revisions of Previous Estimates............................................................................................................. |
35 | 1,095 |
— |
1,130 |
Production............................................................................................................................................................. |
(36) | (2,834) |
— |
(2,870) |
September 30, 2012......................................................................................................................................... |
306 | 42,556 |
— |
42,862 |
|
|
|
|
|
Proved Developed Reserves: |
|
|
|
|
September 30, 2009......................................................................................................................................... |
285 | 37,711 | 1,194 | 39,190 |
September 30, 2010......................................................................................................................................... |
263 | 36,353 | 1,066 | 37,682 |
September 30, 2011......................................................................................................................................... |
274 | 37,306 |
— |
37,580 |
September 30, 2012......................................................................................................................................... |
306 | 38,138 |
— |
38,444 |
Proved Undeveloped Reserves: |
|
|
|
|
September 30, 2009......................................................................................................................................... |
26 | 7,113 | 258 | 7,397 |
September 30, 2010......................................................................................................................................... |
5 | 7,114 | 438 | 7,557 |
September 30, 2011......................................................................................................................................... |
5 | 5,760 |
— |
5,765 |
September 30, 2012......................................................................................................................................... |
— |
4,418 |
— |
4,418 |
(1) |
The Midway Sunset North fields (which exceeded 15% of total reserves at September 30, 2010) contributed 1,543 Mbbls of production during 2010. As of September 30, 2012 and 2011, the Midway Sunset North fields were below 15% of total reserves. |
The Company’s proved undeveloped (PUD) reserves increased from 295 Bcfe at September 30, 2011 to 410 Bcfe at September 30, 2012. PUD reserves in the Marcellus Shale increased from 253 Bcf at September 30, 2011 to 381 Bcf at September 30, 2012. There was a material increase in PUD reserves at September 30, 2012 and 2011 as a result of Marcellus Shale reserve additions. The Company’s total PUD reserves are 33% of total proved reserves at September 30, 2012, up from 32% of total proved reserves at September 30, 2011.
The Company’s proved undeveloped (PUD) reserves increased from 177 Bcfe at September 30, 2010 to 295 Bcfe at September 30, 2011. PUD reserves in the Marcellus Shale increased from 110 Bcf at September 30, 2010 to 253 Bcf at September 30, 2011. There was a material increase in PUD reserves at September 30, 2011 and 2010 as a result of Marcellus Shale reserve additions. The Company’s total PUD reserves are 32% of total proved reserves at September 30, 2011, up from 25% of total proved reserves at September 30, 2010.
The increase in PUD reserves in 2012 of 115 Bcfe is a result of 289 Bcfe in new PUD reserve additions (286 Bcfe from the Marcellus Shale), offset by 97 Bcfe in PUD conversions to proved developed reserves, and 77 Bcfe in downward PUD revisions of previous estimates. The downward revisions were primarily from the removal of proved locations in the Marcellus Shale due to a significant decrease in trailing twelve-month average gas prices at Dominion South Point. The decrease in prices made the reserves uneconomic to develop. Of these downward revisions, the majority (66 Bcfe) were related to non-operated Marcellus activity, primarily in Clearfield County.
The increase in PUD reserves in 2011 of 118 Bcfe is a result of 212 Bcfe in new PUD reserve additions (209 Bcfe from the Marcellus Shale), offset by 83 Bcfe in PUD conversions to proved developed reserves, 10 Bcfe from sales of minerals in place and 2 Bcfe in downward PUD revisions of previous estimates. The downward revisions were primarily from the removal of proved locations in the Upper Devonian play. These locations are unlikely to be developed within a 5-year timeframe due to the Company’s focus on the Marcellus Shale and the better economic results there.
The Company is committed to developing its PUD reserves within five years as required by the SEC’s final rule on Modernization of Oil and Gas Reporting. In 2013, the Company estimates that it will invest approximately $160 million to develop its PUD reserves. The Company invested $217 million during the year ended September 30, 2012 to convert 97 Bcfe of September 30, 2011 PUD reserves to proved developed reserves. This represents 33% of the PUD reserves booked at September 30, 2011. The Company invested $146 million during the year ended September 30, 2011 to convert 83 Bcfe of September 30, 2010 PUD reserves to proved developed reserves. This represented 47% of the PUD reserves booked at September 30, 2010. The Company invested an additional $53 million during the year ended September 30, 2011 to develop the additional working interests in Covington area PUD wells that were acquired from EOG Resources during fiscal 2011.
At September 30, 2012, 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 PUD reserves that have been on the books for more than five years. The Company has reduced the concentration of PUD reserves in this field from 44% of total field level proved reserves at September 30, 2007 to 16% of total field level proved reserves at September 30, 2012. The PUD reserves in this field represent less than 1% of the Company's proved reserves at the corporate level. The economics of this project remain strong and the steam-flood project here is performing well. Drilling of the remaining proved undeveloped locations in this field is scheduled over the next three years as steam generation capacity is increased and the steam-flood here matures.
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 |
||
|
2012 |
2011 |
2010 |
|
(Thousands) |
||
United States |
|
|
|
Future Cash Inflows......................................................................................................................................... |
$ 7,373,129
|
$ 7,180,320
|
$ 5,273,605
|
Less: |
|
|
|
Future Production Costs................................................................................................................................ |
1,919,530 | 1,555,603 | 1,347,855 |
Future Development Costs.......................................................................................................................... |
619,573 | 636,745 | 445,413 |
Future Income Tax Expense at Applicable Statutory Rate............................................................ |
1,812,055 | 1,834,778 | 1,186,567 |
Future Net Cash Flows................................................................................................................................... |
3,021,971 | 3,153,194 | 2,293,770 |
Less: |
|
|
|
10% Annual Discount for Estimated Timing of Cash Flows.......................................................... |
1,552,180 | 1,629,037 | 1,120,182 |
Standardized Measure of Discounted Future Net Cash Flows..................................................... |
$ 1,469,791
|
$ 1,524,157
|
$ 1,173,588
|
The principal sources of change in the standardized measure of discounted future net cash flows were as follows:
|
Year Ended September 30 |
||
|
2012 |
2011 |
2010 |
|
(Thousands) |
||
United States |
|
|
|
Standardized Measure of Discounted Future |
|
|
|
Net Cash Flows at Beginning of Year................................................................................................ |
$ 1,524,157
|
$ 1,173,588
|
$ 875,977
|
Sales, Net of Production Costs............................................................................................................ |
(381,581) | (412,172) | (313,742) |
Net Changes in Prices, Net of Production Costs......................................................................... |
(385,019) | 404,445 | 176,530 |
Purchases of Minerals in Place............................................................................................................. |
— |
52,697 |
— |
Sales of Minerals in Place........................................................................................................................ |
— |
(73,633) |
— |
Extensions and Discoveries................................................................................................................... |
224,474 | 218,140 | 329,555 |
Changes in Estimated Future Development Costs..................................................................... |
29,627 | (85,191) | (17,353) |
Previously Estimated Development Costs Incurred................................................................... |
252,967 | 168,275 | 47,539 |
Net Change in Income Taxes at Applicable Statutory Rate..................................................... |
(19,280) | (249,773) | (85,703) |
Revisions of Previous Quantity Estimates..................................................................................... |
103,472 | 124,545 | 46,246 |
Accretion of Discount and Other.......................................................................................................... |
120,974 | 203,236 | 114,539 |
Standardized Measure of Discounted Future Net Cash Flows at End of Year............... |
$ 1,469,791
|
$ 1,524,157
|
$ 1,173,588
|
|
Schedule II — Valuation and Qualifying Accounts
Description |
Balance at Beginning of Period |
Additions Charged to Costs and Expenses |
Additions Charged to Other Accounts(1) |
Deductions(2) |
Balance at End of Period |
Year Ended September 30, 2012 |
|
|
|
|
|
Allowance for Uncollectible Accounts....................................................................... |
$ 31,039
|
$ 9,183
|
$ 1,946
|
$ 11,851
|
$ 30,317
|
Year Ended September 30, 2011 |
|
|
|
|
|
Allowance for Uncollectible Accounts....................................................................... |
$ 30,961
|
$ 11,974
|
$ 2,484
|
$ 14,380
|
$ 31,039
|
Year Ended September 30, 2010 |
|
|
|
|
|
Allowance for Uncollectible Accounts....................................................................... |
$ 38,334
|
$ 15,422
|
$ 2,268
|
$ 25,063
|
$ 30,961
|
|
|
(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. |
|
Principles of Consolidation
The Company consolidates all entities in which it has a controlling financial interest. The equity method is used to account for entities in which the Company has a non-controlling financial interest. 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.
During the quarter ended March 31, 2011, the Company sold its 50% equity method investments in Seneca Energy and Model City for $59.4 million, resulting in a gain of $50.9 million. Seneca Energy and Model City generate and sell electricity using methane gas obtained from landfills owned by outside parties.
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.
Reclassifications and Revisions
Certain prior year amounts have been reclassified to conform with current year presentation. This includes the reclassification of $63.7 million from Other Regulatory Liabilities to Other Regulatory Assets on the Consolidated Balance Sheet at September 30, 2011. This reclassification pertains to pension and post-retirement benefit regulatory asset and regulatory liability balances. The Company has switched from a “gross” presentation to a “net” presentation, which is consistent with the methodology used by the various regulators in analyzing such regulatory asset and liability balances. This reclassification did not impact the Consolidated Statement of Income and there was an immaterial impact to the Consolidated Statement of Cash Flows.
The Company also reclassified $26.6 million from Other Regulatory Assets to Other Current Assets and $13.8 million from Other Regulatory Liabilities to Other Accruals and Current Liabilities on the Consolidated Balance Sheet at September 30, 2011. The reclassification was made to distinguish long-term regulatory assets and liabilities from current regulatory assets and liabilities. Current regulatory assets are defined as assets recoverable from ratepayers over a twelve-month period. Current regulatory liabilities are defined as liabilities payable to ratepayers over a twelve-month period. These reclassifications did not impact the Consolidated Statement of Income and there was an immaterial impact to the Consolidated Statement of Cash Flows.
Revisions were made on the Consolidated Statement of Cash Flows for the years ended September 30, 2011 and September 30, 2010 to reflect non-cash investing activities embedded in Accounts Payable on the Consolidated Balance Sheets at September 30, 2011, September 30, 2010 and September 30, 2009. These revisions reduced the cash inflow related to Accounts Payable for the years ended September 30, 2011 and September 30, 2010 by $16.7 million and $12.7 million, respectively, and reduced capital expenditures by the same amounts. The effect of these revisions was to reduce Net Cash Provided by Operating Activities for the years ended September 30, 2011 and September 30, 2010 and to reduce Net Cash Used in Investing Activities for the years ended September 30, 2011 and September 30, 2010.
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 and Empire bill their 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 or Empire.
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.
In April 2011, the Company completed the sale of its off-shore oil and natural gas properties in the Gulf of Mexico. The Company received net proceeds of $55.4 million from this sale. The Company also eliminated the asset retirement obligation associated with its off-shore oil and gas properties. This obligation amounted to $37.5 million and was accounted for as a reduction of capitalized costs under the full cost method of accounting for oil and natural gas properties as well as a reduction of the asset retirement obligation. Asset retirement obligations are discussed further in Note B – Asset Retirement Obligations.
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. The natural gas and oil prices used to calculate the full cost ceiling 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, 2012, 2011, and 2010, estimated future net cash flows were increased by $128.4 million, $35.4 million and $65.4 million, respectively. At September 30, 2012, the ceiling exceeded the book value of the oil and gas properties by approximately $55.3 million.
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 |
|
|
2012 |
2011 |
|
(Thousands) |
|
Utility................................................................................................................................................................................................... |
$ 1,737,645
|
$ 1,695,702
|
Pipeline and Storage..................................................................................................................................................................... |
1,406,433 | 1,260,301 |
Exploration and Production........................................................................................................................................................ |
2,828,358 | 2,042,225 |
Energy Marketing........................................................................................................................................................................... |
2,865 | 2,095 |
All Other and Corporate............................................................................................................................................................... |
196,593 | 127,291 |
|
$ 6,171,894
|
$ 5,127,614
|
Average depreciation, depletion and amortization rates are as follows:
|
Year Ended September 30 |
||
|
2012 |
2011 |
2010 |
Utility............................................................................................................................................................................................ |
2.6% | 2.6% | 2.6% |
Pipeline and Storage.............................................................................................................................................................. |
2.9% | 3.1% | 3.0% |
Exploration and Production, per Mcfe(1)...................................................................................................................... |
$ 2.25
|
$ 2.17
|
$ 2.14
|
Energy Marketing.................................................................................................................................................................... |
3.6% | 2.5% | 2.9% |
All Other and Corporate........................................................................................................................................................ |
1.8% | 1.3% | 6.8% |
(1) | Amounts include depletion of oil and gas producing properties as well as depreciation of fixed assets. As disclosed in Note N — Supplementary Information for Oil and Gas Producing Properties, depletion of oil and gas producing properties amounted to $2.19, $2.12 and $2.10 per Mcfe of production in 2012, 2011 and 2010, respectively. |
Goodwill
The Company has recognized goodwill of $5.5 million as of September 30, 2012 and 2011 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, 2012, 2011 and 2010, 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 2012, 2011 or 2010.
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 2012, 2011 or 2010.
Accumulated Other Comprehensive Income (Loss)
The components of Accumulated Other Comprehensive Income (Loss) are as follows:
|
Year Ended September 30 |
|
|
2012 |
2011 |
|
(Thousands) |
|
Funded Status of the Pension and Other Post-Retirement Benefit Plans...................................................... |
$ (100,561)
|
$ (89,587)
|
Net Unrealized Gain (Loss) on Derivative Financial Instruments....................................................................... |
(1,602) | 40,979 |
Net Unrealized Gain on Securities Available for Sale............................................................................................... |
3,143 | 909 |
Accumulated Other Comprehensive Loss...................................................................................................................... |
$ (99,020)
|
$ (47,699)
|
At September 30, 2012, it is estimated that $10.6 million of unrealized gains on derivative financial instruments will be reclassified into the Consolidated Statement of Income during 2013 with $12.2 million of unrealized losses on derivative financial instruments being reclassified into the Consolidated Statement of Income in subsequent years. These instruments, which are classified as cash flow hedges, extend out to 2017.
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 credit was $0.4 million and $0.5 million at September 30, 2012 and 2011, respectively. The total amount for accumulated losses was $100.9 million and $90.0 million at September 30, 2012 and 2011, respectively.
Gas Stored Underground — Current
In the Utility segment, gas stored underground — current in the amount of $34.8 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 2012, 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 $46.0 million at September 30, 2012. 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.
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. At September 30, 2012, the remaining weighted average amortization period for such costs was approximately 4 years.
Income Taxes
The Company and its domestic subsidiaries file a consolidated federal income tax return. State tax returns are filed on a combined or separate basis depending on the applicable laws in the jurisdictions where tax returns are filed. 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.
The Company has accounts payable and accrued liabilities recorded on its Consolidated Balance Sheets that are related to capital expenditures. These amounts represent non-cash investing activities at the balance sheet date. Accordingly, they are excluded from the Consolidated Statement of Cash Flows when they are recorded as liabilities and included in the Consolidated Statement of Cash Flows when they are paid in the subsequent period. The following table summarizes the Company’s non-cash capital expenditures recorded as Accounts Payable and Other Accruals and Current Liabilities on the Consolidated Balance Sheet:
|
At September 30 |
|||
|
2012 |
2011 |
2010 |
2009 |
|
(Thousands) |
|||
Non-cash Capital Expenditures..................................................................................... |
$ 52,557
|
$ 111,947
|
$ 78,632
|
$ 20,231
|
Hedging Collateral Deposits
This is an account title for cash held in margin accounts funded by the Company to serve as collateral for hedging positions. At September 30, 2012, the Company had hedging collateral deposits of $0.4 million related to its exchange-traded futures contracts. At September 30, 2011, the Company had hedging collateral deposits of $5.5 million related to its exchange-traded futures contracts and $14.2 million related to its over-the-counter crude oil swap agreements. In accordance with its accounting policy, the Company does not offset hedging collateral deposits paid or received against related derivative financial instrument liability or asset balances.
Other Current Assets
The components of the Company’s Other Current Assets are as follows:
|
Year Ended September 30 |
|
|
2012 |
2011 |
|
(Thousands) |
|
Prepayments................................................................................................................................................................................ |
$ 8,316
|
$ 9,489
|
Prepaid Property and Other Taxes..................................................................................................................................... |
14,455 | 13,240 |
Federal Income Taxes Receivable..................................................................................................................................... |
268 | 385 |
State Income Taxes Receivable......................................................................................................................................... |
2,065 | 6,124 |
Fair Values of Firm Commitments..................................................................................................................................... |
1,291 | 9,096 |
Regulatory Assets..................................................................................................................................................................... |
29,726 | 26,589 |
|
$ 56,121
|
$ 64,923
|
Other Accruals and Current Liabilities
The components of the Company’s Other Accruals and Current Assets are as follows:
|
Year Ended September 30 |
|
|
2012 |
2011 |
|
(Thousands) |
|
Accrued Capital Expenditures.............................................................................................................................................. |
$ 36,460
|
$ 72,121
|
Regulatory Liabilities................................................................................................................................................................ |
38,253 | 29,368 |
Other................................................................................................................................................................................................ |
4,386 | 7,147 |
|
$ 79,099
|
$ 108,636
|
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, 2012 and 2011, customers in the balanced billing programs had advanced excess funds of $24.1 million and $19.6 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, 2012 and 2011, the Company had received customer security deposits amounting to $17.9 million and $17.3 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, SARs and restricted stock units. The diluted weighted average shares outstanding shown on the Consolidated Statements of Income reflects the potential dilution as a result of these securities as determined using the Treasury Stock Method. Stock options, SARs and restricted stock units that are antidilutive are excluded from the calculation of diluted earnings per common share. For 2012, there were 844,872 securities excluded as being antidilutive. For 2011, there were no securities excluded as being antidilutive. For 2010, 314,910 securities were excluded as being antidilutive.
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. 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. Restrictions on restricted stock awards generally lapse ratably over a period of not more than ten years after the date of each grant. Restricted stock units also are subject to restrictions on vesting and transferability. Restricted stock units represent the right to receive shares of common stock of the Company (or the equivalent value in cash or a combination of cash and shares of common stock of the Company, as determined by the Company) at the end of a specified time period. These restricted stock units do not entitle the participants to dividend and voting rights. The accounting for these restricted stock units is the same as the accounting for restricted share awards, except that the fair value at the date of grant of the restricted stock units (represented by the market value of Company common stock on the date of the award) must be reduced by the present value of forgone dividends over the vesting term of the award. The fair value of restricted stock units on the date of award is recorded as compensation expense over the vesting period.
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 does not have complex stock-based compensation awards.
Stock-based compensation expense for the years ended September 30, 2012, 2011 and 2010 was approximately $7.2 million, $6.7 million, and $4.4 million, respectively. Stock-based compensation expense is included in operation and maintenance expense on the Consolidated Statements of Income. The total income tax benefit related to stock-based compensation expense during the years ended September 30, 2012, 2011 and 2010 was approximately $2.9 million, $2.7 million and $1.8 million, respectively. There were no capitalized stock-based compensation costs during the years ended September 30, 2012, 2011 and 2010.
The Company realized tax benefits related to stock-based compensation of $14.2 million, $19.0 million, and $12.8 million for the fiscal years ended September 30, 2012, 2011 and 2010, respectively. The Company only recorded tax benefits of $0.6 million, $0.4 million, and $12.2 million related to the fiscal years ended September 30, 2012, 2011 and 2010, respectively, due to tax loss carryforwards.
For a summary of transactions during 2012 involving option shares, non-performance based SARs, performance based SARs, restricted share awards and restricted stock units for all plans, refer to Note E – Capitalization and Short-Term Borrowings.
Stock Options
The total intrinsic value of stock options exercised during the years ended September 30, 2012, 2011 and 2010 totaled approximately $13.5 million, $44.6 million, and $53.6 million, respectively. For 2012, 2011 and 2010, the amount of cash received by the Company from the exercise of such stock options was approximately $7.6 million, $9.5 million, and $34.5 million, respectively.
There were no stock options granted during the years ended September 30, 2012, 2011 and 2010. For the years ended September 30, 2012 and 2011, no stock options became fully vested. For the year ended September 30, 2010, 100,000 stock options became fully vested. The total fair value of the stock options that became vested during the year ended September 30, 2010 was approximately $0.7 million. There was no unrecognized compensation expense related to stock options at September 30, 2012.
Non-Performance Based SARs
The Company granted 166,000 and 195,000 non-performance based SARs during the years ended September 30, 2012 and 2011, respectively. The Company did not grant any non-performance based SARs during the year ended September 30, 2010. The SARs granted in 2012 will be settled in shares of common stock of the Company. The SARs granted in 2011 may be settled in cash, in shares of common stock of the Company, or in a combination of cash and shares of common stock of the Company, as determined by the Company. Non-performance based SARs are considered equity awards under the current authoritative guidance for stock-based compensation. The accounting for non-performance based SARs is the same as the accounting for stock options. The non-performance based SARs granted during the year ended September 30, 2012 vest annually in one-third increments and become exercisable on the third anniversary of the date of grant. The non-performance based SARs granted during the year ended September 30, 2011 vest and become exercisable annually in one-third increments. The weighted average grant date fair value of these non-performance based SARs granted during the years ended September 30, 2012 and 2011 were estimated on the date of grant using the same accounting treatment that is applied for stock options.
Participants in the stock option and award plans did not exercise any non-performance based SARs during the years ended September 30, 2012, 2011 and 2010. The weighted average grant date fair value of non-performance based SARs granted in 2012 and 2011 are $11.20 and $15.01, respectively. For the year ended September 30, 2012, 59,990 non-performance based SARs became fully vested. For the year ended September 30, 2011, no non-performance based SARs became fully vested. For the year ended September 30, 2010, 50,000 non-performance based SARs became fully vested. The total fair value of the non-performance based SARs that became vested during the year ended September 30, 2012 was approximately $0.9 million. 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, 2012, unrecognized compensation expense related to non-performance based SARs totaled approximately $1.1 million, which will be recognized over a weighted average period of 10.2 months.
The fair value of non-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 non-performance based SARs at the date of grant:
|
Year Ended September 30 |
||
|
2012 |
2011 |
|
Risk Free Interest Rate........................................................................................................................................................ |
1.59% | 2.94% | |
Expected Life (Years)............................................................................................................................................................ |
8.25 | 8.00 | |
Expected Volatility.................................................................................................................................................................. |
24.97% | 23.38% | |
Expected Dividend Yield (Quarterly).............................................................................................................................. |
0.64% | 0.55% |
The risk-free interest rate is based on the yield of a Treasury Note with a remaining term commensurate with the expected term of the non-performance based SARs. The expected life and expected volatility are based on historical experience.
For grants during the years ended September 30, 2012 and 2011, it was assumed that there would be no forfeitures, based on the vesting term and the number of grantees.
Performance Based SARs
The Company did not grant any performance based SARs during the years ended September 30, 2012 and 2011. The Company granted 520,500 performance based SARs during the year ended September 30, 2010. The accounting treatment for 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 year ended September 30, 2010 vest and become exercisable annually in one-third increments, provided that a performance condition is met. The performance condition for each fiscal year, generally stated, is an increase over the prior fiscal year of at least five percent in certain oil and natural gas production of the Exploration and Production segment. The weighted average grant date fair value of the performance based SARs granted during 2010 was estimated on the date of grant using the same accounting treatment that is applied for stock options, and assumes that the performance conditions specified will be achieved. If such conditions are not met or it is not considered probable that such conditions will be met, no compensation expense is recognized and any previously recognized compensation expense is reversed.
The weighted average grant date fair value of performance based SARs granted in 2010 is $12.06 per share. The total intrinsic value of performance based SARs exercised during the years ended September 30, 2012 and 2011 totaled less than $0.1 million and approximately $0.3 million, respectively. Participants in the stock option and award plans did not exercise any performance based SARs during the year ended September 30, 2010. For the years ended September 30, 2012, 2011 and 2010, 375,179, 376,819 and 203,324 performance based SARs became fully vested. The total fair value of the performance based SARs that became vested during each of the years ended September 30, 2012, 2011 and 2010 was approximately $2.9 million, $2.9 million and $0.8 million, respectively. As of September 30, 2012, unrecognized compensation expense related to performance based SARs totaled approximately $0.1 million, which will be recognized over a weighted average period of 3.0 months.
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 |
Risk Free Interest Rate........................................................................................................................................................ |
3.55% |
Expected Life (Years)............................................................................................................................................................ |
7.75 |
Expected Volatility.................................................................................................................................................................. |
23.25% |
Expected Dividend Yield (Quarterly).............................................................................................................................. |
0.64% |
The risk-free interest rate is based on the yield of a Treasury Note with a remaining term commensurate with the expected term of the performance based SARs. The expected life and expected volatility are based on historical experience.
For grants during the year ended September 30, 2010, it was assumed that there would be no forfeitures, based on the vesting term and the number of grantees.
Restricted Share Awards
The Company granted 41,525, 47,250, and 4,000 restricted share awards (non-vested stock as defined by the current accounting literature) during the years ended September 30, 2012, 2011 and 2010, respectively. The weighted average fair value of restricted share awards granted in 2012, 2011 and 2010 is $55.09 per share, $63.98 per share and $52.10 per share, respectively. As of September 30, 2012, unrecognized compensation expense related to restricted share awards totaled approximately $4.0 million, which will be recognized over a weighted average period of 2.4 years.
Restricted Stock Units
The Company granted 68,450 and 41,800 restricted stock units during the years ended September 30, 2012 and 2011, respectively. The weighted average fair value of restricted share units granted in 2012 and 2011 are $47.10 per share and $59.35 per share, respectively. As of September 30, 2012, unrecognized compensation expense related to restricted share awards totaled approximately $3.9 million, which will be recognized over a weighted average period of 2.0 years.
New Authoritative Accounting and Financial Reporting Guidance
In June 2011, the FASB issued authoritative guidance regarding the presentation of comprehensive income. The new guidance allows companies only two choices for presenting net income and other comprehensive income: in a single continuous statement, or in two separate, but consecutive, statements. The guidance eliminates the current option to report other comprehensive income and its components in the statement of changes in equity. This authoritative guidance will be effective as of the Company’s first quarter of fiscal 2013 and is not expected to have a significant impact on the Company’s financial statements.
In September 2011, the FASB issued revised authoritative guidance that simplifies the testing of goodwill for impairment. The revised guidance allows companies the option to perform a “qualitative” assessment to determine whether further impairment testing is necessary. The revised authoritative guidance is required to be effective for the Company’s annual impairment test performed in fiscal 2013. The Company has adopted the new provisions for fiscal 2012, as early adoption was permitted.
In December 2011, the FASB issued authoritative guidance requiring enhanced disclosures regarding offsetting assets and liabilities. Companies are required to disclose both gross information and net information about both instruments and transactions eligible for offset in the statement of financial position and instruments and transactions subject to an agreement similar to a master netting arrangement. This authoritative guidance will be effective as of the Company’s first quarter of fiscal 2014 and is not expected to have a significant impact on the Company’s financial statements.
|
|
As of September 30 |
|
|
2012 |
2011 |
|
(Thousands) |
|
Utility................................................................................................................................................................................................... |
$ 1,737,645
|
$ 1,695,702
|
Pipeline and Storage..................................................................................................................................................................... |
1,406,433 | 1,260,301 |
Exploration and Production........................................................................................................................................................ |
2,828,358 | 2,042,225 |
Energy Marketing........................................................................................................................................................................... |
2,865 | 2,095 |
All Other and Corporate............................................................................................................................................................... |
196,593 | 127,291 |
|
$ 6,171,894
|
$ 5,127,614
|
|
Year Ended September 30 |
||
|
2012 |
2011 |
2010 |
Utility............................................................................................................................................................................................ |
2.6% | 2.6% | 2.6% |
Pipeline and Storage.............................................................................................................................................................. |
2.9% | 3.1% | 3.0% |
Exploration and Production, per Mcfe(1)...................................................................................................................... |
$ 2.25
|
$ 2.17
|
$ 2.14
|
Energy Marketing.................................................................................................................................................................... |
3.6% | 2.5% | 2.9% |
All Other and Corporate........................................................................................................................................................ |
1.8% | 1.3% | 6.8% |
(1) | Amounts include depletion of oil and gas producing properties as well as depreciation of fixed assets. As disclosed in Note N — Supplementary Information for Oil and Gas Producing Properties, depletion of oil and gas producing properties amounted to $2.19, $2.12 and $2.10 per Mcfe of production in 2012, 2011 and 2010, respectively. |
|
Year Ended September 30 |
|
|
2012 |
2011 |
|
(Thousands) |
|
Funded Status of the Pension and Other Post-Retirement Benefit Plans...................................................... |
$ (100,561)
|
$ (89,587)
|
Net Unrealized Gain (Loss) on Derivative Financial Instruments....................................................................... |
(1,602) | 40,979 |
Net Unrealized Gain on Securities Available for Sale............................................................................................... |
3,143 | 909 |
Accumulated Other Comprehensive Loss...................................................................................................................... |
$ (99,020)
|
$ (47,699)
|
|
At September 30 |
|||
|
2012 |
2011 |
2010 |
2009 |
|
(Thousands) |
|||
Non-cash Capital Expenditures..................................................................................... |
$ 52,557
|
$ 111,947
|
$ 78,632
|
$ 20,231
|
|
Year Ended September 30 |
|
|
2012 |
2011 |
|
(Thousands) |
|
Prepayments................................................................................................................................................................................ |
$ 8,316
|
$ 9,489
|
Prepaid Property and Other Taxes..................................................................................................................................... |
14,455 | 13,240 |
Federal Income Taxes Receivable..................................................................................................................................... |
268 | 385 |
State Income Taxes Receivable......................................................................................................................................... |
2,065 | 6,124 |
Fair Values of Firm Commitments..................................................................................................................................... |
1,291 | 9,096 |
Regulatory Assets..................................................................................................................................................................... |
29,726 | 26,589 |
|
$ 56,121
|
$ 64,923
|
|
Year Ended September 30 |
|
|
2012 |
2011 |
|
(Thousands) |
|
Accrued Capital Expenditures.............................................................................................................................................. |
$ 36,460
|
$ 72,121
|
Regulatory Liabilities................................................................................................................................................................ |
38,253 | 29,368 |
Other................................................................................................................................................................................................ |
4,386 | 7,147 |
|
$ 79,099
|
$ 108,636
|
|
Year Ended September 30 |
||
|
2012 |
2011 |
|
Risk Free Interest Rate........................................................................................................................................................ |
1.59% | 2.94% | |
Expected Life (Years)............................................................................................................................................................ |
8.25 | 8.00 | |
Expected Volatility.................................................................................................................................................................. |
24.97% | 23.38% | |
Expected Dividend Yield (Quarterly).............................................................................................................................. |
0.64% | 0.55% |
|
Year Ended September 30 |
|
2010 |
Risk Free Interest Rate........................................................................................................................................................ |
3.55% |
Expected Life (Years)............................................................................................................................................................ |
7.75 |
Expected Volatility.................................................................................................................................................................. |
23.25% |
Expected Dividend Yield (Quarterly).............................................................................................................................. |
0.64% |
|
|
Year Ended September 30 |
||
|
2012 |
2011 |
2010 |
|
(Thousands) |
||
Balance at Beginning of Year................................................................................................................................ |
$ 75,731
|
$ 101,618
|
$ 91,373
|
Liabilities Incurred and Revisions of Estimates........................................................................................... |
41,653 | 10,346 | 16,140 |
Liabilities Settled.......................................................................................................................................................... |
(2,997) | (41,704) | (12,622) |
Accretion Expense...................................................................................................................................................... |
4,859 | 5,471 | 6,727 |
Balance at End of Year............................................................................................................................................ |
$ 119,246
|
$ 75,731
|
$ 101,618
|
|
|
At September 30 |
|
|
2012 |
2011 |
|
(Thousands) |
|
Regulatory Assets(1): |
|
|
Pension Costs(2) (Note H)................................................................................................................................................................ |
$ 344,228
|
$ 319,906
|
Post-Retirement Benefit Costs(2) (Note H).............................................................................................................................. |
154,415 | 124,423 |
Recoverable Future Taxes (Note D) ........................................................................................................................................... |
150,941 | 144,377 |
Environmental Site Remediation Costs(2) (Note I)............................................................................................................... |
17,843 | 20,095 |
NYPSC Assessment(3)...................................................................................................................................................................... |
17,420 | 15,063 |
Asset Retirement Obligations(2) (Note B).................................................................................................................................. |
26,942 | 13,860 |
Unamortized Debt Expense (Note A)........................................................................................................................................... |
3,997 | 5,090 |
Other(4)...................................................................................................................................................................................................... |
15,729 | 17,639 |
Total Regulatory Assets..................................................................................................................................................................... |
731,515 v |
660,453 |
Less: Amounts Included in Other Current Assets.................................................................................................................. |
(29,726) | (26,589) |
Total Long-Term Regulatory Assets.............................................................................................................................................. |
$ 701,789
|
$ 633,864
|
|
At September 30 |
|
|
2012 |
2011 |
|
(Thousands) |
|
Regulatory Liabilities: |
|
|
Cost of Removal Regulatory Liability......................................................................................................................................... |
$ 139,611
|
$ 135,940
|
Taxes Refundable to Customers (Note D)................................................................................................................................ |
66,392 | 65,543 |
Amounts Payable to Customers (See Regulatory Mechanisms in Note A)............................................................... |
19,964 | 15,519 |
Off-System Sales and Capacity Release Credits(5)........................................................................................................... |
16,262 | 7,675 |
Other(6)...................................................................................................................................................................................................... |
23,041 | 23,351 |
Total Regulatory Liabilities................................................................................................................................................................. |
265,270 | 248,028 |
Less: Amounts included in Current and Accrued Liabilities............................................................................................... |
(38,253) | (29,368) |
Total Long-Term Regulatory Liabilities.......................................................................................................................................... |
$ 227,017
|
$ 218,660
|
|
|
(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) |
Amounts are included in Other Current Assets on the Consolidated Balance Sheets at September 30, 2012 and September 30, 2011 since such amounts are expected to be recovered from ratepayers in the next 12 months. |
(4) |
$12,306 and $11,526 are included in Other Current Assets on the Consolidated Balance Sheets at September 30, 2012 and 2011, respectively, since such amounts are expected to be recovered from ratepayers in the next 12 months. $3,423 and $6,113 are included in Other Regulatory Assets on the Consolidated Balance Sheets at September 30, 2012 and 2011, respectively. |
(5) |
Amounts are included in Other Accruals and Current Liabilities on the Consolidated Balance Sheets at September 30, 2012 and September 30, 2011 since such amounts are expected to be passed back to ratepayers in the next 12 months. |
|
|
(6) |
$2,027 and $6,174 are included in Other Accruals and Current Liabilities on the Consolidated Balance Sheets at September 30, 2012 and 2011, respectively, since such amounts are expected to be recovered from ratepayers in the next 12 months. $21,014 and $17,177 are included in Other Regulatory Liabilities on the Consolidated Balance Sheets at September 30, 2012 and 2011, respectively. |
|
|
Year Ended September 30 |
|||
|
2012 |
2011 |
2010 |
|
|
(Thousands) |
|||
Current Income Taxes — |
|
|
|
|
Federal............................................................................................................................................................................ |
$ (8)
|
$ (1,390)
|
$ 2,074
|
|
State................................................................................................................................................................................ |
6,412 | 1,520 | 4,991 | |
Deferred Income Taxes — |
|
|
|
|
Federal............................................................................................................................................................................ |
111,176 | 130,434 | 110,515 | |
State................................................................................................................................................................................ |
32,974 | 33,817 | 24,164 | |
|
150,554 | 164,381 | 141,744 | |
Deferred Investment Tax Credit......................................................................................................................... |
(581) | (697) | (697) | |
Total Income Taxes................................................................................................................................................... |
$ 149,973
|
$ 163,684
|
$ 141,047
|
|
Presented as Follows: |
|
|
|
|
Other Income............................................................................................................................................................... |
$ (581)
|
$ (697)
|
$ (697)
|
|
Income Tax Expense — Continuing Operations.......................................................................................... |
150,554 | 164,381 | 137,227 | |
Discontinued Operations — |
|
|
|
|
Income from Operations........................................................................................................................................ |
— |
— |
493 | |
Gain on Disposal........................................................................................................................................................ |
— |
— |
4,024 | |
Total Income Taxes................................................................................................................................................... |
$ 149,973
|
$ 163,684
|
$ 141,047
|
|
Year Ended September 30 |
||
|
2012 |
2011 |
2010 |
|
(Thousands) |
||
U.S. Income Before Income Taxes................................................................................................................. |
$ 370,050
|
$ 422,086
|
$ 366,960
|
Income Tax Expense, Computed at U.S. Federal Statutory Rate of 35%................................... |
$ 129,518
|
$ 147,730
|
$ 128,436
|
Increase (Reduction) in Taxes Resulting from: |
|
|
|
State Income Taxes................................................................................................................................................ |
25,601 | 22,969 | 18,951 |
Miscellaneous............................................................................................................................................................. |
(5,146) | (7,015) | (6,340) |
Total Income Taxes.................................................................................................................................................. |
$ 149,973
|
$ 163,684
|
$ 141,047
|
|
At September 30 |
|
|
2012 |
2011 |
|
(Thousands) |
|
Deferred Tax Liabilities: |
|
|
Property, Plant and Equipment............................................................................................................................................... |
$ 1,333,574
|
$ 1,062,255
|
Pension and Other Post-Retirement Benefit Costs...................................................................................................... |
236,431 | 217,302 |
Other................................................................................................................................................................................................... |
43,294 | 70,389 |
Total Deferred Tax Liabilities.................................................................................................................................................... |
1,613,299 | 1,349,946 |
Deferred Tax Assets: |
|
|
Pension and Other Post-Retirement Benefit Costs...................................................................................................... |
(276,501) | (263,606) |
Tax Loss Carryforwards............................................................................................................................................................ |
(198,744) | (71,516) |
Other................................................................................................................................................................................................... |
(83,052) | (74,863) |
Total Deferred Tax Assets........................................................................................................................................................ |
(558,297) | (409,985) |
Total Net Deferred Income Taxes......................................................................................................................................... |
$ 1,055,002
|
$ 939,961
|
Presented as Follows: |
|
|
Deferred Tax Liability/(Asset) — Current.......................................................................................................................... |
$ (10,755)
|
$ (15,423)
|
Deferred Tax Liability — Non-Current................................................................................................................................. |
1,065,757 | 955,384 |
Total Net Deferred Income Taxes......................................................................................................................................... |
$ 1,055,002
|
$ 939,961
|
|
Year Ended September 30 |
||
|
2012 |
2011 |
2010 |
|
(Thousands) |
||
Balance at Beginning of Year......................................................................................................................................... |
$ 7,766
|
$ 8,490
|
$ 8,721
|
Additions for Tax Positions Related to Current Year........................................................................................... |
1,600 | 80 | 699 |
Additions for Tax Positions of Prior Years................................................................................................................ |
2,751 | 107 | 45 |
Reductions for Tax Positions of Prior Years........................................................................................................... |
(947) | (911) | (975) |
Balance at End of Year..................................................................................................................................................... |
$ 11,170
|
$ 7,766
|
$ 8,490
|
|
|
|
|
Earnings |
Accumulated |
|
|
|
|
Reinvested |
Other |
|
|
Common Stock |
Paid |
in |
Comprehensive |
|
|
|
In |
the |
Income |
|
|
Shares |
Amount |
Capital |
Business |
(Loss) |
|
(Thousands, except per share amounts) |
||||
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 | (44,985) |
Net Income Available for Common Stock....................................... |
|
|
|
258,402 |
|
Dividends Declared on Common Stock ($1.40 Per Share)...... |
|
|
|
(115,642) |
|
Other Comprehensive Loss, Net of Tax........................................... |
|
|
|
|
(2,714) |
Share-Based Payment Expense(2)...................................................... |
|
|
6,656 |
|
|
Common Stock Issued (Repurchased) Under Stock and Benefit Plans(1) |
738 | 738 | (1,526) |
|
|
Balance at September 30, 2011............................................................. |
82,813 | 82,813 | 650,749 | 1,206,022 | (47,699) |
Net Income Available for Common Stock....................................... |
|
|
|
220,077 |
|
Dividends Declared on Common Stock ($1.44 Per Share)...... |
|
|
|
(119,815) |
|
Other Comprehensive Loss, Net of Tax........................................... |
|
|
|
|
(51,321) |
Share-Based Payment Expense(2)...................................................... |
|
|
7,156 |
|
|
Common Stock Issued Under Stock and Benefit Plans(1)...... |
517 | 517 | 11,596 |
|
|
Balance at September 30, 2012............................................................ |
83,330 | $ 83,330
|
$ 669,501
|
$1,306,284(3) |
$ (99,020)
|
|
|
|
|
|
|
(1) |
Paid in Capital includes tax benefits of $1.0 million for September 30, 2012, tax costs of $1.2 million for September 30, 2011 and tax benefits of $13.2 million for September 30, 2010 associated with the exercise of stock options and/or performance based SARs. |
|
|
(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, 2012, $1.2 billion of accumulated earnings was free of such limitations. |
|
At September 30 |
|
|
2012 |
2011 |
|
(Thousands) |
|
Medium-Term Notes(1): |
|
|
7.4% due March 2023 to June 2025...................................................................................................................................... |
$ 99,000
|
$ 249,000
|
Notes(1): |
|
|
4.90% to 8.75% due March 2013 to December 2021.................................................................................................... |
1,300,000 | 800,000 |
Total Long-Term Debt.................................................................................................................................................................... |
1,399,000 | 1,049,000 |
Less Current Portion(2)............................................................................................................................................................... |
250,000 | 150,000 |
|
$ 1,149,000
|
$ 899,000
|
(1) |
The Medium-Term Notes and Notes are unsecured. |
(2) |
Current Portion of Long-Term Debt at September 30, 2012 consists of $250.0 million of 5.25% notes that mature in March 2013. Current Portion of Long-Term Debt at September 30, 2011 consisted of $150.0 million of 6.70% medium-term notes that matured in November 2011. |
|
Number of Restricted Share Awards |
Weighted Average Fair Value per Award |
Restricted Share Awards Outstanding at September 30, 2011......................................................................... |
139,250 | $ 53.37
|
Granted in 2012....................................................................................................................................................................... |
41,525 | $ 55.09
|
Vested in 2012......................................................................................................................................................................... |
(18,740) | $ 59.74
|
Forfeited in 2012.................................................................................................................................................................... |
— |
$— |
Restricted Share Awards Outstanding at September 30, 2012......................................................................... |
162,035 | $ 53.07
|
|
Number of Shares Subject To Option |
Weighted Average Exercise Price |
Weighted Average Remaining Contractual Life (Years) |
Aggregate Intrinsic Value |
|
(In thousands) |
|||
Outstanding at September 30, 2011......................................................................... |
245,000 | $ 58.79
|
|
|
Granted in 2012................................................................................................................. |
166,000 | $ 55.09
|
|
|
Exercised in 2012............................................................................................................. |
— |
$— |
|
|
Forfeited in 2012............................................................................................................... |
— |
$— |
|
|
Outstanding at September 30, 2012........................................................................ |
411,000 | $ 57.30
|
8.20 | $ (1,339)
|
SARs exercisable at September 30, 2012............................................................ |
109,990 | $ 53.56
|
6.51 | $ 53
|
|
Number of Shares Subject to Option |
Weighted Average Exercise Price |
Weighted Average Remaining Contractual Life (Years) |
Aggregate Intrinsic Value |
|
(In thousands) |
|||
Outstanding at September 30, 2011......................................................................... |
1,758,961 | $ 31.38
|
|
|
Granted in 2012................................................................................................................. |
— |
$— |
|
|
Exercised in 2012............................................................................................................. |
(476,243) | $ 25.28
|
|
|
Forfeited in 2012............................................................................................................... |
— |
$ — |
|
|
Outstanding at September 30, 2012........................................................................ |
1,282,718 | $ 33.64
|
2.65 | $ 26,166
|
Option shares exercisable at September 30, 2012........................................... |
1,282,718 | $ 33.64
|
2.65 | $ 26,166
|
Option shares available for future grant at September 30, 2012(1)......... |
2,097,214 |
|
|
|
(1) |
Includes shares available for SARs and restricted stock grants. |
|
Number of Restricted Share Awards |
Weighted Average Fair Value per Award |
Restricted Stock Units Outstanding at September 30, 2011............................................................................. |
39,400 | $ 59.20
|
Granted in 2012....................................................................................................................................................................... |
68,450 | $ 47.10
|
Vested in 2012......................................................................................................................................................................... |
— |
$ — |
Forfeited in 2012.................................................................................................................................................................... |
(1,950) | $ 46.96
|
Restricted Stock Units Outstanding at September 30, 2012............................................................................. |
105,900 | $ 51.61
|
|
Number of Shares Subject To Option |
Weighted Average Exercise Price |
Weighted Average Remaining Contractual Life (Years) |
Aggregate Intrinsic Value |
|
(In thousands) |
|||
Outstanding at September 30, 2011......................................................................... |
1,225,153 | $ 40.85
|
|
|
Granted in 2012................................................................................................................. |
— |
$— |
|
|
Exercised in 2012............................................................................................................. |
(2,000) | $ 29.88
|
|
|
Forfeited in 2012............................................................................................................... |
— |
$ — |
|
|
Canceled in 2012(1)......................................................................................................... |
(6,000) | $ 58.99
|
|
|
Outstanding at September 30, 2012........................................................................ |
1,217,153 | $ 40.78
|
6.68 | $ 16,140
|
SARs exercisable at September 30, 2012............................................................ |
1,039,309 | $ 38.80
|
6.56 | $ 15,837
|
(1) |
Shares were canceled during 2012 due to performance condition not being met. |
|
|
At Fair Value as of September 30, 2012 |
||||
Recurring Fair Value Measures |
Level 1 |
Level 2 |
Level 3 |
Netting Adjustments(1) |
Total |
|
(Dollars in thousands) |
||||
Assets: |
|
|
|
|
|
Cash Equivalents — Money Market Mutual Funds.............................................................. |
$ 46,113
|
$— |
$— |
$— |
$ 46,113
|
Derivative Financial Instruments: |
|
|
|
|
|
Commodity Futures Contracts — Gas...................................................................................... |
4,348 |
— |
— |
(2,760) | 1,588 |
Over the Counter Swaps — Gas.................................................................................................. |
— |
41,751 |
— |
(15,723) | 26,028 |
Over the Counter Swaps — Oil..................................................................................................... |
— |
— |
559 | (559) |
— |
Other Investments: |
|
|
|
|
|
Balanced Equity Mutual Fund......................................................................................................... |
24,767 |
— |
— |
— |
24,767 |
Common Stock — Financial Services Industry.................................................................... |
4,758 |
— |
— |
— |
4,758 |
Other Common Stock........................................................................................................................ |
272 |
— |
— |
— |
272 |
Hedging Collateral Deposits............................................................................................................ |
364 |
— |
— |
— |
364 |
Total............................................................................................................................................................ |
$ 80,622
|
$ 41,751
|
$ 559
|
$ (19,042)
|
$ 103,890
|
|
|
|
|
|
|
Liabilities: |
|
|
|
|
|
Derivative Financial Instruments: |
|
|
|
|
|
Commodity Futures Contracts — Gas...................................................................................... |
$ 2,760
|
$— |
$— |
$ (2,760)
|
$— |
Over the Counter Swaps — Gas.................................................................................................. |
— |
19,932 |
— |
(15,723) | 4,209 |
Over the Counter Swaps — Oil..................................................................................................... |
— |
654 | 20,223 | (559) | 20,318 |
Total............................................................................................................................................................ |
$ 2,760
|
$ 20,586
|
$ 20,223
|
$ (19,042)
|
$ 24,527
|
Total Net Assets/(Liabilities)............................................................................................................ |
$ 77,862
|
$ 21,165
|
$ (19,664)
|
$— |
$ 79,363
|
|
At Fair Value as of September 30, 2011 |
||||
Recurring Fair Value Measures |
Level 1 |
Level 2 |
Level 3 |
Netting Adjustments(1) |
Total |
|
(Dollars in thousands) |
||||
Assets: |
|
|
|
|
|
Cash Equivalents — Money Market Mutual Funds.............................................................. |
$ 32,444
|
$— |
$— |
$— |
$ 32,444
|
Derivative Financial Instruments: |
|
|
|
|
|
Commodity Futures Contracts — Gas...................................................................................... |
4,541 |
— |
— |
(4,541) |
— |
Over the Counter Swaps — Gas.................................................................................................. |
— |
75,292 |
— |
(179) | 75,113 |
Over the Counter Swaps — Oil..................................................................................................... |
— |
— |
10,420 | (9,448) | 972 |
Other Investments: |
|
|
|
|
|
Balanced Equity Mutual Fund......................................................................................................... |
19,882 |
— |
— |
— |
19,882 |
Common Stock — Financial Services Industry.................................................................... |
4,478 |
— |
— |
— |
4,478 |
Other Common Stock........................................................................................................................ |
226 |
— |
— |
— |
226 |
Hedging Collateral Deposits............................................................................................................ |
19,701 |
— |
— |
— |
19,701 |
Total............................................................................................................................................................ |
$ 81,272
|
$ 75,292
|
$ 10,420
|
$ (14,168)
|
$ 152,816
|
|
|
|
|
|
|
Liabilities: |
|
|
|
|
|
Derivative Financial Instruments: |
|
|
|
|
|
Commodity Futures Contracts — Gas...................................................................................... |
$ 7,833
|
$— |
$— |
$ (4,541)
|
$ 3,292
|
Over the Counter Swaps — Gas.................................................................................................. |
— |
179 |
— |
(179) |
— |
Over the Counter Swaps — Oil..................................................................................................... |
— |
— |
15,830 | (9,448) | 6,382 |
Total............................................................................................................................................................ |
$ 7,833
|
$ 179
|
$ 15,830
|
$ (14,168)
|
$ 9,674
|
Total Net Assets/(Liabilities)............................................................................................................ |
$ 73,439
|
$ 75,113
|
$ (5,410)
|
$— |
$ 143,142
|
(1) | Amounts represent the impact of legally-enforceable master netting arrangements that allow the Company to net gain and loss positions held with the same counterparties. |
Fair Value Measurements Using Unobservable Inputs (Level 3)
|
|
Total Gains/Losses |
|
|
|
|
|
|
Gains/(Losses) |
|
|
|
|
(Gains)/Losses |
Unrealized and |
|
|
|
October 1, 2011 |
Realized and Included in Earnings |
Included in Other Comprehensive Income (Loss) |
Transfer In/(Out) of Level 3 |
September 30, 2012 |
|
(Dollars in thousands) |
||||
Derivative Financial Instruments(2)…………….…... |
$ (5,410)
|
$ 46,174(1) |
$ (60,428)
|
$— |
$ (19,664)
|
(1) Amounts are reported in Operating Revenues in the Consolidated Statement of Income for the year ended September 30, 2012.
(2) Derivative Financial Instruments are shown on a net basis.
Fair Value Measurements Using Unobservable Inputs (Level 3)
|
|
Total Gains/Losses |
|
|
|
|
|
|
Gains/(Losses) |
|
|
|
|
(Gains)/Losses |
Unrealized and |
|
|
|
October 1, 2010 |
Realized and Included in Earnings |
Included in Other Comprehensive Income (Loss) |
Transfer In/(Out) of Level 3 |
September 30, 2011 |
|
(Dollars in thousands) |
||||
Derivative Financial Instruments(2).............................. |
$ (16,483)
|
$ 41,354(1) |
$ (30,281)
|
$— |
$ (5,410)
|
(1) Amounts are reported in Operating Revenues in the Consolidated Statement of Income for the year ended September 30, 2011.
(2) Derivative Financial Instruments are shown on a net basis.
|
|
At September 30 |
|||
|
2012 Carrying Amount |
2012 Fair Value |
2011 Carrying Amount |
2011 Fair Value |
|
(Thousands) |
|||
Long-Term Debt.................................................................................................................... |
$ 1,399,000
|
$ 1,623,847
|
$ 1,049,000
|
$ 1,198,585
|
|
The Effect of Derivative Financial Instruments on the Statement of Financial Performance for the |
|||||||
|
Year Ended September 30, 2012 and 2011 (Dollar Amounts in Thousands) |
|||||||
|
Amount of |
|
Amount of |
|
|
|||
|
Derivative Gain or |
|
Derivative Gain or |
|
|
|||
|
(Loss) Recognized |
Location of |
(Loss) Reclassified |
Location of |
|
|||
|
in Other |
Derivative Gain or |
from Accumulated |
Derivative Gain or |
Derivative Gain or |
|||
|
Comprehensive |
(Loss) Reclassified |
Other Comprehensive |
(Loss) Recognized |
(Loss) Recognized |
|||
|
Income (Loss) on |
from Accumulated |
Income (Loss) on |
in the Consolidated |
in the Consolidated |
|||
|
the Consolidated |
Other Comprehensive |
the Consolidated |
Statement of |
Statement of Income |
|||
|
Statement of |
Income (Loss) on |
Balance Sheet into |
Income |
(Ineffective |
|||
|
Comprehensive |
the Consolidated |
the Consolidated |
(Ineffective Portion |
Portion and Amount |
|||
|
Income (Loss) |
Balance Sheet into |
Statement of Income |
and Amount |
Excluded from |
|||
Derivatives in Cash |
(Effective Portion) |
the Consolidated |
(Effective Portion) |
Excluded from |
Effectiveness Testing) |
|||
Flow Hedging |
for the Year Ended |
Statement of Income |
for the Year Ended |
Effectiveness |
for the Year Ended |
|||
Relationships |
September 30, |
(Effective Portion) |
September 30, |
Testing) |
September 30, |
|||
|
2012 |
2011 |
|
2012 |
2011 |
|
2012 |
2011 |
Commodity Contracts — Exploration & Production segment |
$ (11,776)
|
$ 24,713
|
Operating Revenue |
$ 54,777
|
$ 6,367
|
Not Applicable |
$— |
$— |
Commodity Contracts — Energy Marketing segment |
$ 4,725
|
$ 5,015
|
Purchased Gas |
$ 10,439
|
$ 8,608
|
Not Applicable |
$— |
$— |
Commodity Contracts — Pipeline & Storage segment(1) |
$ (197)
|
$ 510
|
Operating Revenue |
$ 475
|
$ 510
|
Not Applicable |
$— |
$— |
Total............................................ |
$ (7,248)
|
$ 30,238
|
|
$ 65,691
|
$ 15,485
|
|
$— |
$— |
(1) |
There were no open hedging positions at September 30, 2012 or 2011. |
Consolidated Statement of Income |
Gain/(Loss) on Derivative |
Gain/(Loss) on Commitment |
Operating Revenues..................................................................................................................... |
$ 8,021,910
|
$ (8,021,910)
|
Purchased Gas................................................................................................................................ |
$ (1,235,817)
|
$ 1,235,817
|
Derivatives in Fair Value Hedging Relationships – Energy Marketing segment |
Location of Derivative Gain or (Loss) Recognized in the Consolidated Statement of Income |
Amount of Derivative Gain or (Loss) Recognized in the Consolidated Statement of Income for the Year Ended September 30, 2012 |
|
(In thousands) |
|
Commodity Contracts — Hedge of fixed price sales commitments of natural gas.... |
Operating Revenues |
$ 8,022
|
Commodity Contracts — Hedge of fixed price purchase commitments of natural gas |
Purchased Gas |
(1,261) |
Commodity Contracts — Hedge of natural gas held in storage............................................ |
Purchased Gas |
25 |
|
|
$ 6,786
|
|
|
Retirement Plan |
Other Post-Retirement Benefits |
||||
|
Year Ended September 30 |
Year Ended September 30 |
||||
|
2012 |
2011 |
2010 |
2012 |
2011 |
2010 |
|
(Thousands) |
|||||
Change in Benefit Obligation |
|
|
|
|
|
|
Benefit Obligation at Beginning of Period.. |
$ 949,777
|
$ 924,493
|
$ 831,496
|
$ 485,452
|
$ 472,407
|
$ 467,295
|
Service Cost........................................................... |
14,202 | 14,772 | 12,997 | 4,016 | 4,276 | 4,298 |
Interest Cost........................................................... |
41,526 | 42,676 | 44,308 | 21,315 | 21,884 | 25,017 |
Plan Participants’ Contributions...................... |
— |
— |
— |
1,956 | 1,963 | 1,644 |
Retiree Drug Subsidy Receipts...................... |
— |
— |
— |
1,528 | 1,532 | 1,354 |
Amendments(1)...................................................... |
— |
(1,764) |
— |
— |
(7,187) |
— |
Actuarial (Gain) Loss........................................... |
120,338 | 21,395 | 85,831 | 71,708 | 15,071 | (3,635) |
Benefits Paid........................................................... |
(55,099) | (51,795) | (50,139) | (24,712) | (24,494) | (23,566) |
Benefit Obligation at End of Period.............. |
$ 1,070,744
|
$ 949,777
|
$ 924,493
|
$ 561,263
|
$ 485,452
|
$ 472,407
|
Change in Plan Assets |
|
|
|
|
|
|
Fair Value of Assets at Beginning of Period |
$ 601,719
|
$ 597,549
|
$ 563,881
|
$ 351,990
|
$ 353,269
|
$ 319,022
|
Actual Return on Plan Assets......................... |
111,034 | 2,412 | 61,625 | 63,552 | (4,094) | 30,478 |
Employer Contributions...................................... |
44,022 | 53,553 | 22,182 | 21,348 | 25,346 | 25,691 |
Plan Participants’ Contributions...................... |
— |
— |
— |
1,956 | 1,963 | 1,644 |
Benefits Paid........................................................... |
(55,099) | (51,795) | (50,139) | (24,712) | (24,494) | (23,566) |
Fair Value of Assets at End of Period......... |
$ 701,676
|
$ 601,719
|
$ 597,549
|
$ 414,134
|
$ 351,990
|
$ 353,269
|
Net Amount Recognized at End of Period (Funded Status) |
$ (369,068)
|
$ (348,058)
|
$ (326,944)
|
$ (147,129)
|
$ (133,462)
|
$ (119,138)
|
Amounts Recognized in the Balance Sheets Consist of: |
|
|
|
|
|
|
Non-Current Liabilities......................................... |
$ (369,068)
|
$ (348,058)
|
$ (326,944)
|
$ (147,129)
|
$ (133,462)
|
$ (119,138)
|
Accumulated Benefit Obligation..................... |
$ 986,223
|
$ 874,595
|
$ 843,526
|
N/A |
N/A |
N/A |
Weighted Average Assumptions Used to Determine Benefit Obligation at September 30 |
|
|
|
|
|
|
Discount Rate......................................................... |
3.50% | 4.50% | 4.75% | 3.50% | 4.50% | 4.75% |
Rate of Compensation Increase.................... |
4.75% | 4.75% | 4.75% | 4.75% | 4.75% | 4.75% |
Components of Net Periodic Benefit Cost |
|
|
|
|
|
|
Service Cost........................................................... |
$ 14,202
|
$ 14,772
|
$ 12,997
|
$ 4,016
|
$ 4,276
|
$ 4,298
|
Interest Cost........................................................... |
41,526 | 42,676 | 44,308 | 21,315 | 21,884 | 25,017 |
Expected Return on Plan Assets................... |
(59,701) | (59,103) | (58,342) | (28,971) | (29,165) | (26,334) |
Amortization of Prior Service Cost............... |
269 | 588 | 655 | (2,138) | (1,710) | (1,710) |
Amortization of Transition Amount................ |
— |
— |
— |
10 | 541 | 541 |
Recognition of Actuarial Loss(2).................... |
39,615 | 34,873 | 21,641 | 24,057 | 23,794 | 25,881 |
Net Amortization and Deferral for Regulatory Purposes |
(6,900) | (2,311) | (30) | 6,162 | 10,490 | 351 |
Net Periodic Benefit Cost................................. |
$ 29,011
|
$ 31,495
|
$ 21,229
|
$ 24,451
|
$ 30,110
|
$ 28,044
|
Weighted Average Assumptions Used to Determine Net Periodic Benefit Cost at September 30 |
|
|
|
|
|
|
Discount Rate......................................................... |
4.50% | 4.75% | 5.50% | 4.50% | 4.75% | 5.50% |
Expected Return on Plan Assets................... |
8.25% | 8.25% | 8.25% | 8.25% | 8.25% | 8.25% |
Rate of Compensation Increase.................... |
4.75% | 4.75% | 5.00% | 4.75% | 4.75% | 5.00% |
(1) | In fiscal 2011, the Company passed an amendment which changed the definition of annual compensation prospectively to exclude certain bonuses paid by Seneca after September 30, 2011. This decreased the benefit obligation of the Retirement Plan. In fiscal 2011, the Company also increased the prescription drug co-payments for certain retired participants which decreased the benefit obligation of the other post-retirement benefits. |
(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.
|
Retirement Plan |
Other Post-Retirement Benefits |
Non-Qualified Benefit Plans |
|
(Thousands) |
||
Amounts Recognized in Accumulated Other Comprehensive Income (Loss), Regulatory Assets and Regulatory Liabilities(1) |
|
|
|
Net Actuarial Loss.......................................................................................................................................... |
$ (458,125)
|
$ (195,305)
|
$ (40,770)
|
Transition Obligation....................................................................................................................................... |
— |
(8) |
— |
Prior Service (Cost) Credit......................................................................................................................... |
(1,304) | 11,217 |
— |
Net Amount Recognized.............................................................................................................................. |
$ (459,429)
|
$ (184,096)
|
$ (40,770)
|
Changes to Accumulated Other Comprehensive Income (Loss), Regulatory Assets and Regulatory Liabilities Recognized During Fiscal 2012(1) |
|
|
|
Increase in Actuarial Loss, excluding amortization(2).................................................................... |
$ (69,005)
|
$ (37,134)
|
$ (9,559)
|
Change due to Amortization of Actuarial Loss.................................................................................. |
39,615 | 24,057 | 4,363 |
Reduction in Transition Obligation........................................................................................................... |
— |
10 |
— |
Prior Service (Cost) Credit......................................................................................................................... |
269 | (2,138) |
— |
Net Change........................................................................................................................................................ |
$ (29,121)
|
$ (15,205)
|
$ (5,196)
|
Amounts Expected to be Recognized in Net Periodic Benefit Cost in the Next Fiscal Year(1) |
|
|
|
Net Actuarial Loss.......................................................................................................................................... |
$ (52,776)
|
$ (20,892)
|
$ (5,280)
|
Transition Obligation....................................................................................................................................... |
— |
(8) |
— |
Prior Service (Cost) Credit......................................................................................................................... |
(238) | 2,138 |
— |
Net Amount Expected to be Recognized............................................................................................. |
$ (53,014)
|
$ (18,762)
|
$ (5,280)
|
(1) | Amounts presented are shown before recognizing deferred taxes. |
(2) Amounts presented include the impact of actuarial gains/losses related to return on assets, as well as the Actuarial (Gain) Loss amounts presented in the Change in Benefit Obligation.
|
Benefit Payments |
Subsidy Receipts |
2013.......................................................................................................................................................................................... |
$ 26,559
|
$ (1,828)
|
2014.......................................................................................................................................................................................... |
$ 27,852
|
$ (2,021)
|
2015.......................................................................................................................................................................................... |
$ 29,154
|
$ (2,220)
|
2016.......................................................................................................................................................................................... |
$ 30,506
|
$ (2,420)
|
2017.......................................................................................................................................................................................... |
$ 31,859
|
$ (2,606)
|
2018 through 2022............................................................................................................................................................. |
$ 175,145
|
$ (15,964)
|
|
2012 |
|
2011 |
|
2010 |
|
Rate of Increase for Pre Age 65 Participants............................................................................................................ |
7.46% | (1) | 7.64% | (1) | 7.82% | (1) |
Rate of Increase for Post Age 65 Participants......................................................................................................... |
6.84% |
(1) |
6.89% |
(1) |
6.95% |
(1) |
Annual Rate of Increase in the Per Capita Cost of Covered Prescription Drug Benefits.................... |
8.08% |
(1) |
8.39% |
(1) |
8.69% |
(1) |
Annual Rate of Increase in the Per Capita Medicare Part B Reimbursement............................................. |
6.84% |
(1) |
6.89% |
(1) |
6.95% |
(1) |
Annual Rate of Increase in the Per Capita Medicare Part D Subsidy............................................................ |
7.13% |
(1) |
7.30% |
(1) |
7.60% |
(1) |
(1) It was assumed that this rate would gradually decline to 4.5% by 2028.
|
Total Fair Value Amounts at September 30, 2012 |
Level 1 |
Level 2 |
Level 3 |
Retirement Plan Investments |
|
|
|
|
Domestic Equities (1)......................................................................................................... |
$ 358,679
|
$ 231,978
|
$ 126,701
|
$— |
International Equities (2).................................................................................................... |
96,451 | 2,090 | 94,361 |
— |
Domestic Fixed Income (3)............................................................................................. |
165,130 | 70,730 | 94,400 |
— |
International Fixed Income (4)........................................................................................ |
65,835 | 1,941 | 63,894 |
— |
Hedge Fund Investments................................................................................................. |
39,956 |
— |
— |
39,956 |
Real Estate.............................................................................................................................. |
6,170 |
— |
— |
6,170 |
Cash and Cash Equivalents .......................................................................................... |
12,874 |
— |
12,874 |
— |
Total Retirement Plan Investments.............................................................................. |
745,095 | 306,739 | 392,230 | 46,126 |
401(h) Investments............................................................................................................. |
(43,311) | (17,818) | (22,813) | (2,680) |
Total Retirement Plan Investments (excluding 401(h) Investments)........... |
$ 701,784
|
$ 288,921
|
$ 369,417
|
$ 43,446
|
Miscellaneous Accruals, Interest Receivables, and Non-Interest Cash..... |
(108) |
|
|
|
Total Retirement Plan Assets.......................................................................................... |
$ 701,676
|
|
|
|
|
Total Fair Value Amounts at September 30, 2011 |
Level 1 |
Level 2 |
Level 3 |
Retirement Plan Investments |
|
|
|
|
Domestic Equities (1)......................................................................................................... |
$ 313,193
|
$ 215,524
|
$ 97,669
|
$— |
International Equities (2).................................................................................................... |
79,732 | 11,163 | 68,569 |
— |
Domestic Fixed Income (3)............................................................................................. |
146,587 | 77,657 | 68,930 |
— |
International Fixed Income (4)........................................................................................ |
43,153 | 887 | 42,266 |
— |
Hedge Fund Investments................................................................................................. |
39,296 |
— |
— |
39,296 |
Real Estate.............................................................................................................................. |
6,443 |
— |
— |
6,443 |
Cash and Cash Equivalents .......................................................................................... |
10,629 |
— |
10,629 |
— |
Total Retirement Plan Investments.............................................................................. |
639,033 | 305,231 | 288,063 | 45,739 |
401(h) Investments............................................................................................................. |
(37,176) | (17,744) | (16,773) | (2,659) |
Total Retirement Plan Investments (excluding 401(h) Investments)........... |
$ 601,857
|
$ 287,487
|
$ 271,290
|
$ 43,080
|
Miscellaneous Accruals, Interest Receivables, and Non-Interest Cash..... |
(138) |
|
|
|
Total Retirement Plan Assets.......................................................................................... |
$ 601,719
|
|
|
|
(a) | Domestic Equities include mostly collective trust funds, common stock, and exchange traded funds. |
(b) | International Equities include mostly collective trust funds and common stock. |
(c) | Domestic Fixed Income securities include mostly collective trust funds, corporate/government bonds and mortgages, and exchange traded funds. |
(d) | International Fixed Income securities includes mostly collective trust funds and exchange traded funds. |
|
||||||
|
Retirement Plan Level 3 Assets |
|||||
|
(Thousands) |
|||||
|
Equity |
|
|
|
Excluding |
|
|
Convertible |
Hedge |
Limited |
Real |
401(h) |
|
|
Securities |
Funds |
Partnerships |
Estate |
Investments |
Total |
Balance at September 30, 2010....................................................... |
$ 337
|
$— |
$ 245
|
$ 6,148
|
$ (367)
|
$ 6,363
|
Realized Gains/(Losses)...................................................................... |
53 |
— |
(4,846) | 20 | 278 | (4,495) |
Unrealized Gains/(Losses).................................................................. |
(36) | (789) | 4,853 | 159 | (268) | 3,919 |
Purchases, Sales, Issuances, and Settlements (Net).......... |
(354) | 40,085 | (252) | 116 | (2,302) | 37,293 |
Balance at September 30, 2011....................................................... |
— |
39,296 |
— |
6,443 | (2,659) | 43,080 |
Realized Gains/(Losses)...................................................................... |
— |
— |
— |
60 | (4) | 56 |
Unrealized Gains/(Losses).................................................................. |
— |
660 |
— |
(362) | (15) | 283 |
Purchases, Sales, Issuances, and Settlements (Net).......... |
— |
— |
— |
29 | (2) | 27 |
Balance at September 30, 2012 ..................................................... |
$— |
$ 39,956
|
$— |
$ 6,170
|
$ (2,680)
|
$ 43,446
|
|
|
|
|
|
|
|
|
Total Fair Value Amounts at September 30, 2012 |
Level 1 |
Level 2 |
Level 3 |
Other Post-Retirement Benefit Assets held in VEBA Trusts |
|
|
|
|
Collective Trust Funds — Domestic Equities............................................................ |
$ 179,059
|
$— |
$ 179,059
|
$— |
Collective Trust Funds — International Equities...................................................... |
66,590 |
— |
66,590 |
— |
Exchange Traded Funds — Fixed Income.................................................................. |
107,597 | 107,597 |
— |
— |
Real Estate................................................................................................................................ |
1,305 |
— |
— |
1,305 |
Cash Held in Collective Trust Funds............................................................................. |
16,397 |
— |
16,397 |
— |
Total VEBA Trust Investments.......................................................................................... |
370,948 | 107,597 | 262,046 | 1,305 |
401(h) Investments................................................................................................................ |
43,311 | 17,818 | 22,813 | 2,680 |
Total Investments (including 401(h) Investments).................................................. |
$ 414,259
|
$ 125,415
|
$ 284,859
|
$ 3,985
|
Miscellaneous Accruals (Including Current and Deferred Taxes, Claims Incurred But Not Reported, Administrative) |
(125) |
|
|
|
Total Other Post-Retirement Benefit Assets.............................................................. |
$ 414,134
|
|
|
|
|
Total Fair Value Amounts at September 30, 2011 |
Level 1 |
Level 2 |
Level 3 |
Other Post-Retirement Benefit Assets held in VEBA Trusts |
|
|
|
|
Collective Trust Funds — Domestic Equities............................................................ |
$ 148,451
|
$— |
$ 148,451
|
$— |
Collective Trust Funds — International Equities...................................................... |
55,411 |
— |
55,411 |
— |
Exchange Traded Funds — Fixed Income.................................................................. |
91,214 | 91,214 |
— |
— |
Real Estate................................................................................................................................ |
1,561 |
— |
— |
1,561 |
Cash Held in Collective Trust Funds............................................................................. |
12,890 |
— |
12,890 |
— |
Total VEBA Trust Investments.......................................................................................... |
309,527 | 91,214 | 216,752 | 1,561 |
401(h) Investments................................................................................................................ |
37,176 | 17,744 | 16,773 | 2,659 |
Total Investments (including 401(h) Investments).................................................. |
$ 346,703
|
$ 108,958
|
$ 233,525
|
$ 4,220
|
Miscellaneous Accruals (Including Current and Deferred Taxes, Claims Incurred But Not Reported, Administrative) |
5,287 |
|
|
|
Total Other Post-Retirement Benefit Assets.............................................................. |
$ 351,990
|
|
|
|
|
|
Other Post-Retirement Benefit Level 3 Assets |
|||||||
|
|
(Thousands) |
|||||||
|
VEBA |
|
|
|
|||||
|
Trust |
|
Other |
|
|||||
|
Investments Real |
Including 401(h) |
Post-Retirement Benefit |
|
|||||
|
Estate |
Investments |
Investments |
|
|||||
Balance at September 30, 2010......................................................................... |
$ 3,824
|
$ 367
|
$ 4,191
|
|
|||||
Realized Gains/(Losses)........................................................................................ |
— |
(278) | (278) |
|
|||||
Unrealized Gains/(Losses).................................................................................... |
(2,263) | 268 | (1,995) |
|
|||||
Purchases, Sales, Issuances, and Settlements (Net)............................ |
— |
2,302 | 2,302 |
|
|||||
Balance at September 30, 2011......................................................................... |
1,561 | 2,659 | 4,220 |
|
|||||
Realized Gains/(Losses)........................................................................................ |
— |
4 | 4 |
|
|||||
Unrealized Gains/(Losses).................................................................................... |
(256) | 15 | (241) |
|
|||||
Purchases, Sales, Issuances, and Settlements (Net)............................ |
— |
2 | 2 |
|
|||||
Balance at September 30, 2012......................................................................... |
$ 1,305
|
$ 2,680
|
$ 3,985
|
|
|||||
|
|
|
|
|
|
|
|
|
Year Ended September 30, 2010 |
|
(Thousands) |
Operating Revenues........................................................................................................................................................... |
$ 9,919
|
Operating Expenses............................................................................................................................................................ |
8,933 |
Operating Income................................................................................................................................................................. |
986 |
Other Income.......................................................................................................................................................................... |
4 |
Interest Income..................................................................................................................................................................... |
2 |
Interest Expense................................................................................................................................................................... |
29 |
Income before Income Taxes......................................................................................................................................... |
963 |
Income Tax Expense........................................................................................................................................................... |
493 |
Income from Discontinued Operations....................................................................................................................... |
470 |
Gain on Disposal, Net of Taxes of $4,024............................................................................................................... |
6,310 |
Income from Discontinued Operations....................................................................................................................... |
$ 6,780
|
|
|
Year Ended September 30, 2012 |
|||||||
|
Utility |
Pipeline and Storage |
Exploration and Production |
Energy Marketing |
Total Reportable Segments |
All Other |
Corporate and Intersegment Eliminations |
Total Consolidated |
|
(Thousands) |
|||||||
Revenue from External Customers(1) |
$ 704,518
|
$ 172,312
|
$ 558,180
|
$ 186,579
|
$ 1,621,589
|
$ 4,307
|
$ 957
|
$ 1,626,853
|
Intersegment Revenues..................... |
$ 14,604
|
$ 86,963
|
$ — |
$ 1,425
|
$ 102,992
|
$ 16,771
|
$ (119,763)
|
$— |
Interest Income...................................... |
$ 2,765
|
$ 199
|
$ 1,493
|
$ 188
|
$ 4,645
|
$ 175
|
$ (1,131)
|
$ 3,689
|
Interest Expense.................................... |
$ 33,181
|
$ 25,603
|
$ 29,243
|
$ 41
|
$ 88,068
|
$ 1,738
|
$ (3,566)
|
$ 86,240
|
Depreciation, Depletion and Amortization |
$ 42,757
|
$ 38,182
|
$ 187,624
|
$ 90
|
$ 268,653
|
$ 2,091
|
$ 786
|
$ 271,530
|
Income Tax Expense (Benefit)........ |
$ 29,110
|
$ 37,655
|
$ 79,050
|
$ 1,933
|
$ 147,748
|
$ 4,335
|
$ (1,529)
|
$ 150,554
|
Segment Profit: Net Income (Loss) |
$ 58,590
|
$ 60,527
|
$ 96,498
|
$ 4,169
|
$ 219,784
|
$ 6,868
|
$ (6,575)
|
$ 220,077
|
Expenditures for Additions to Long-Lived Assets |
$ 58,284
|
$ 144,167
|
$ 693,810
|
$ 770
|
$ 897,031
|
$ 80,017
|
$ 346
|
$ 977,394
|
|
At September 30, 2012 |
|||||||
|
(Thousands) |
|||||||
Segment Assets......................... |
$ 2,070,413
|
$ 1,243,862
|
$ 2,367,485
|
$ 61,968
|
$ 5,743,728
|
$ 209,934
|
$ (18,520)
|
$ 5,935,142
|
|
Year Ended September 30, 2011 |
|||||||
|
Utility |
Pipeline and Storage |
Exploration and Production |
Energy Marketing |
Total Reportable Segments |
All Other |
Corporate and Intersegment Eliminations |
Total Consolidated |
|
(Thousands) |
|||||||
Revenue from External Customers(1) |
$ 835,853
|
$ 134,071
|
$ 519,035
|
$ 284,546
|
$ 1,773,505
|
$ 4,401
|
$ 936
|
$ 1,778,842
|
Intersegment Revenues..................... |
$ 16,642
|
$ 81,037
|
$ — |
$ 420
|
$ 98,099
|
$ 10,017
|
$ (108,116)
|
$— |
Interest Income...................................... |
$ 2,049
|
$ 324
|
$ (27)
|
$ 104
|
$ 2,450
|
$ 247
|
$ 219
|
$ 2,916
|
Interest Expense.................................... |
$ 34,440
|
$ 25,737
|
$ 17,402
|
$ 20
|
$ 77,599
|
$ 2,173
|
$ (1,651)
|
$ 78,121
|
Depreciation, Depletion and Amortization |
$ 40,808
|
$ 37,266
|
$ 146,806
|
$ 47
|
$ 224,927
|
$ 840
|
$ 760
|
$ 226,527
|
Income Tax Expense (Benefit)........ |
$ 33,325
|
$ 19,854
|
$ 89,034
|
$ 4,489
|
$ 146,702
|
$ 18,961
|
$ (1,282)
|
$ 164,381
|
Gain on Sale of Unconsolidated Subsidiaries |
$— |
$— |
$ — |
$— |
$— |
$50,879(2) |
$— |
$ 50,879
|
Segment Profit: Net Income (Loss) |
$ 63,228
|
$ 31,515
|
$ 124,189
|
$ 8,801
|
$ 227,733
|
$ 38,502
|
$ (7,833)
|
$ 258,402
|
Expenditures for Additions to Long-Lived Assets |
$ 58,398
|
$ 129,206
|
$ 648,815
|
$ 460
|
$ 836,879
|
$ 17,022
|
$ 285
|
$ 854,186
|
|
At September 30, 2011 |
|||||||
|
(Thousands) |
|||||||
Segment Assets......................... |
$ 2,001,546
|
$ 1,112,494
|
$ 1,885,014
|
$ 71,138
|
$ 5,070,192
|
$ 166,730
|
$ (15,838)
|
$ 5,221,084
|
|
Year Ended September 30, 2010 |
|||||||
|
Utility |
Pipeline and Storage |
Exploration and Production |
Energy Marketing |
Total Reportable Segments |
All Other |
Corporate and Intersegment Eliminations |
Total Consolidated |
|
(Thousands) |
|||||||
Revenue from External Customers(1) |
$ 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
|
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........................... |
$ 2,027,101
|
$ 1,080,772
|
$ 1,539,705
|
$ 69,561
|
$ 4,717,139
|
$ 198,706
|
$ 131,209
|
$ 5,047,054
|
(1) |
All Revenue from External Customers originated in the United States. |
|
|
(2) |
In February 2011, the Company sold its 50% equity method investments in Seneca Energy and Model City for $59.4 million, resulting in a gain of $50.9 million. |
|
|
|
|
||
|
|
||||
Geographic Information |
At September 30 |
||||
|
2012 |
2011 |
2010 |
||
|
(Thousands) |
||||
Long-Lived Assets: |
|
|
|
||
United States....................................................................................................................................................... |
$ 5,579,566
|
$ 4,809,183
|
$ 4,238,253
|
||
|
|
|
|
|
|
|
|
|
|
|
|
Net Income |
Earnings per |
|
Quarter |
Operating |
Operating |
Available for |
Common Share |
|
Ended |
Revenues |
Income |
Common Stock |
Basic |
Diluted |
|
(Thousands, except per common share amounts) |
||||
2012 |
|
|
|
|
|
9/30/2012......................................................................................... |
$ 313,261
|
$ 107,265
|
$48,802(1) |
$ 0.59
|
$ 0.58
|
6/30/2012......................................................................................... |
$ 328,861
|
$ 90,293
|
$ 43,184
|
$ 0.52
|
$ 0.52
|
3/31/2012......................................................................................... |
$ 552,308
|
$ 132,097
|
$67,392(2) |
$ 0.81
|
$ 0.81
|
12/31/2011....................................................................................... |
$ 432,423
|
$ 118,394
|
$ 60,699
|
$ 0.73
|
$ 0.73
|
2011 |
|
|
|
|
|
9/30/2011......................................................................................... |
$ 286,034
|
$ 75,191
|
$ 37,356
|
$ 0.45
|
$ 0.45
|
6/30/2011......................................................................................... |
$ 380,979
|
$ 94,805
|
$ 46,891
|
$ 0.57
|
$ 0.56
|
3/31/2011......................................................................................... |
$ 660,881
|
$ 153,756
|
$115,611(3) |
$ 1.40
|
$ 1.38
|
12/31/2010...................................................................................... |
$ 450,948
|
$ 117,410
|
$ 58,544
|
$ 0.71
|
$ 0.70
|
(1)
(2)
(3) |
Includes $12.8 million of income associated with the elimination of Supply Corporation’s post-retirement regulatory liability as specified in Supply Corporation’s rate case settlement.
Includes a $4.0 million accrual of a natural gas impact fee related to wells drilled prior to 2012 that was first imposed by Pennsylvania in 2012. This fee was recorded in the Exploration and Production segment.
Includes a $31.4 million after tax gain on the sale of the Company’s 50% equity method investments in Seneca Energy and Model City.
|
|
|
At September 30 |
|
|
2012 |
2011 |
|
(Thousands) |
|
Proved Properties(1)..................................................................................................................................................................... |
$ 2,789,181
|
$ 2,010,662
|
Unproved Properties..................................................................................................................................................................... |
146,084 | 226,276 |
|
2,935,265 | 2,236,938 |
Less — Accumulated Depreciation, Depletion and Amortization............................................................................. |
681,798 | 499,671 |
|
$ 2,253,467
|
$ 1,737,267
|
(1) |
Includes asset retirement costs of $43.1 million and $32.7 million at September 30, 2012 and 2011, respectively. |
|
Total |
|
|||
|
as of |
|
|||
|
September 30, |
Year Costs Incurred |
|||
|
2012 |
2012 |
2011 |
2010 |
Prior |
|
(Thousands) |
||||
Acquisition Costs.............................................................................................................. |
$ 87,280
|
$ 6,195
|
$— |
$ 69,206
|
$ 11,879
|
Development Costs........................................................................................................ |
21,947 | 15,225 | 6,722 |
— |
— |
Exploration Costs............................................................................................................. |
33,891 | 33,891 |
— |
— |
— |
Capitalized Interest.......................................................................................................... |
2,966 | 2,966 |
— |
— |
— |
|
$ 146,084
|
$ 58,277
|
$ 6,722
|
$ 69,206
|
$ 11,879
|
|
Year Ended September 30 |
||
|
2012 |
2011 |
2010 |
United States |
(Thousands) |
||
Property Acquisition Costs: |
|
|
|
Proved.......................................................................................................................................................................... |
$ 13,095
|
$ 28,838
|
$ 790
|
Unproved.................................................................................................................................................................... |
13,867 | 20,012 | 80,221 |
Exploration Costs (1)............................................................................................................................................. |
84,624 | 62,651 |
75,155 |
Development Costs (2)........................................................................................................................................ |
576,397 | 531,372 | 234,094 |
Asset Retirement Costs...................................................................................................................................... |
10,344 | 12,087 | 3,901 |
|
$ 698,327
|
$ 654,960
|
$ 394,161
|
(1) |
Amounts for 2012, 2011 and 2010 include capitalized interest of $1.0 million, $0.8 million and $0.2 million, respectively. |
|
|
(2) |
Amounts for 2012, 2011 and 2010 include capitalized interest of $2.0 million, $0.7 million and $0.9 million, respectively. |
|
Year Ended September 30 |
||
|
2012 |
2011 |
2010 |
|
(Thousands, except per Mcfe amounts) |
||
United States |
|
|
|
Operating Revenues: |
|
|
|
Natural Gas (includes revenues from sales to affiliates of $1, $23 and $253, respectively) |
$ 181,544
|
$ 223,648
|
$ 152,163
|
Oil, Condensate and Other Liquids................................................................................................................... |
307,018 | 273,952 | 233,569 |
Total Operating Revenues(1)............................................................................................................................... |
488,562 | 497,600 | 385,732 |
Production/Lifting Costs........................................................................................................................................ |
83,361 | 73,250 | 61,398 |
Franchise/Ad Valorem Taxes............................................................................................................................... |
23,620 | 12,179 | 10,592 |
Accretion Expense................................................................................................................................................... |
3,084 | 3,668 | 5,444 |
Depreciation, Depletion and Amortization ($2.19, $2.12 and $2.10 per Mcfe of production) |
182,759 | 143,372 | 104,092 |
Income Tax Expense ............................................................................................................................................. |
81,904 | 110,117 | 83,946 |
Results of Operations for Producing Activities (excluding corporate overheads and interest charges) |
$ 113,834
|
$ 155,014
|
$ 120,260
|
(1) |
Exclusive of hedging gains and losses. See further discussion in Note G — Financial Instruments. |
|
|
|
Gas MMcf |
||||
|
U. S.
|
||||
|
Appalachian Region |
|
West Coast Region |
Gulf Coast Region |
Total Company |
Proved Developed and Undeveloped Reserves: |
|
|
|
|
|
September 30, 2009.................................................................................................................................. |
149,828 |
|
72,959 | 26,167 | 248,954 |
Extensions and Discoveries................................................................................................................. |
189,979 | (1) | 269 | 2,881 | 193,129 |
Revisions of Previous Estimates...................................................................................................... |
7,677 |
|
2,315 | 6,683 | 16,675 |
Production...................................................................................................................................................... |
(16,222) | (2) | (3,819) | (10,304) | (30,345) |
September 30, 2010.................................................................................................................................. |
331,262 |
|
71,724 | 25,427 | 428,413 |
Extensions and Discoveries................................................................................................................. |
249,047 | (1) | 195 | 158 | 249,400 |
Revisions of Previous Estimates...................................................................................................... |
24,486 |
|
526 | 1,373 | 26,385 |
Production...................................................................................................................................................... |
(42,979) | (2) | (3,447) | (4,041) | (50,467) |
Purchases of Minerals in Place........................................................................................................... |
44,790 |
|
— |
— |
44,790 |
Sales of Minerals in Place...................................................................................................................... |
— |
|
(682) | (22,917) | (23,599) |
September 30, 2011.................................................................................................................................. |
606,606 |
|
68,316 |
— |
674,922 |
Extensions and Discoveries................................................................................................................. |
435,460 | (1) | 638 |
— |
436,098 |
Revisions of Previous Estimates...................................................................................................... |
(53,992) |
|
(2,463) |
— |
(56,455) |
Production...................................................................................................................................................... |
(62,663) | (2) | (3,468) |
— |
(66,131) |
September 30, 2012.................................................................................................................................. |
925,411 |
|
63,023 |
— |
988,434 |
|
|
|
|
|
|
Proved Developed Reserves: |
|
|
|
|
|
September 30, 2009.................................................................................................................................. |
120,579 |
|
67,603 | 18,051 | 206,233 |
September 30, 2010.................................................................................................................................. |
210,817 |
|
66,178 | 19,293 | 296,288 |
September 30, 2011.................................................................................................................................. |
350,458 |
|
63,965 |
— |
414,423 |
September 30, 2012.................................................................................................................................. |
544,560 |
|
59,923 |
— |
604,483 |
Proved Undeveloped Reserves: |
|
|
|
|
|
September 30, 2009.................................................................................................................................. |
29,249 |
|
5,356 | 8,116 | 42,721 |
September 30, 2010.................................................................................................................................. |
120,445 |
|
5,546 | 6,134 | 132,125 |
September 30, 2011.................................................................................................................................. |
256,148 |
|
4,351 |
— |
260,499 |
September 30, 2012.................................................................................................................................. |
380,851 |
|
3,100 |
— |
383,951 |
(1) |
Extensions and discoveries include 182 Bcf (during 2010), 249 Bcf (during 2011) and 435 Bcf (during 2012), of Marcellus Shale gas in the Appalachian Region. |
|
|
(2) |
Production includes 7,180 MMcf (during 2010), 35,356 MMcf (during 2011) and 55,812 MMcf (during 2012), from Marcellus Shale fields (which exceed 15% of total reserves). |
|
Oil Mbbl |
|||
|
U. S. |
|
||
|
Appalachian Region |
West Coast Region |
Gulf Coast Region |
Total Company |
Proved Developed and Undeveloped Reserves: |
|
|
|
|
September 30, 2009......................................................................................................................................... |
311 | 44,824 | 1,452 | 46,587 |
Extensions and Discoveries........................................................................................................................ |
4 | 828 | 222 | 1,054 |
Revisions of Previous Estimates............................................................................................................. |
2 | 484 | 332 | 818 |
Production............................................................................................................................................................. |
(49) |
(2,669)(1) |
(502) | (3,220) |
September 30, 2010......................................................................................................................................... |
268 | 43,467 | 1,504 | 45,239 |
Extensions and Discoveries........................................................................................................................ |
10 | 756 | 1 | 767 |
Revisions of Previous Estimates............................................................................................................. |
46 | 1,909 | (339) | 1,616 |
Production............................................................................................................................................................. |
(45) | (2,628) | (187) | (2,860) |
Sales of Minerals in Place............................................................................................................................. |
— |
(438) | (979) | (1,417) |
September 30, 2011......................................................................................................................................... |
279 | 43,066 |
— |
43,345 |
Extensions and Discoveries........................................................................................................................ |
28 | 1,229 |
— |
1,257 |
Revisions of Previous Estimates............................................................................................................. |
35 | 1,095 |
— |
1,130 |
Production............................................................................................................................................................. |
(36) | (2,834) |
— |
(2,870) |
September 30, 2012......................................................................................................................................... |
306 | 42,556 |
— |
42,862 |
|
|
|
|
|
Proved Developed Reserves: |
|
|
|
|
September 30, 2009......................................................................................................................................... |
285 | 37,711 | 1,194 | 39,190 |
September 30, 2010......................................................................................................................................... |
263 | 36,353 | 1,066 | 37,682 |
September 30, 2011......................................................................................................................................... |
274 | 37,306 |
— |
37,580 |
September 30, 2012......................................................................................................................................... |
306 | 38,138 |
— |
38,444 |
Proved Undeveloped Reserves: |
|
|
|
|
September 30, 2009......................................................................................................................................... |
26 | 7,113 | 258 | 7,397 |
September 30, 2010......................................................................................................................................... |
5 | 7,114 | 438 | 7,557 |
September 30, 2011......................................................................................................................................... |
5 | 5,760 |
— |
5,765 |
September 30, 2012......................................................................................................................................... |
— |
4,418 |
— |
4,418 |
(1) |
The Midway Sunset North fields (which exceeded 15% of total reserves at September 30, 2010) contributed 1,543 Mbbls of production during 2010. As of September 30, 2012 and 2011, the Midway Sunset North fields were below 15% of total reserves. |
|
Year Ended September 30 |
||
|
2012 |
2011 |
2010 |
|
(Thousands) |
||
United States |
|
|
|
Future Cash Inflows......................................................................................................................................... |
$ 7,373,129
|
$ 7,180,320
|
$ 5,273,605
|
Less: |
|
|
|
Future Production Costs................................................................................................................................ |
1,919,530 | 1,555,603 | 1,347,855 |
Future Development Costs.......................................................................................................................... |
619,573 | 636,745 | 445,413 |
Future Income Tax Expense at Applicable Statutory Rate............................................................ |
1,812,055 | 1,834,778 | 1,186,567 |
Future Net Cash Flows................................................................................................................................... |
3,021,971 | 3,153,194 | 2,293,770 |
Less: |
|
|
|
10% Annual Discount for Estimated Timing of Cash Flows.......................................................... |
1,552,180 | 1,629,037 | 1,120,182 |
Standardized Measure of Discounted Future Net Cash Flows..................................................... |
$ 1,469,791
|
$ 1,524,157
|
$ 1,173,588
|
|
Year Ended September 30 |
||
|
2012 |
2011 |
2010 |
|
(Thousands) |
||
United States |
|
|
|
Standardized Measure of Discounted Future |
|
|
|
Net Cash Flows at Beginning of Year................................................................................................ |
$ 1,524,157
|
$ 1,173,588
|
$ 875,977
|
Sales, Net of Production Costs............................................................................................................ |
(381,581) | (412,172) | (313,742) |
Net Changes in Prices, Net of Production Costs......................................................................... |
(385,019) | 404,445 | 176,530 |
Purchases of Minerals in Place............................................................................................................. |
— |
52,697 |
— |
Sales of Minerals in Place........................................................................................................................ |
— |
(73,633) |
— |
Extensions and Discoveries................................................................................................................... |
224,474 | 218,140 | 329,555 |
Changes in Estimated Future Development Costs..................................................................... |
29,627 | (85,191) | (17,353) |
Previously Estimated Development Costs Incurred................................................................... |
252,967 | 168,275 | 47,539 |
Net Change in Income Taxes at Applicable Statutory Rate..................................................... |
(19,280) | (249,773) | (85,703) |
Revisions of Previous Quantity Estimates..................................................................................... |
103,472 | 124,545 | 46,246 |
Accretion of Discount and Other.......................................................................................................... |
120,974 | 203,236 | 114,539 |
Standardized Measure of Discounted Future Net Cash Flows at End of Year............... |
$ 1,469,791
|
$ 1,524,157
|
$ 1,173,588
|
|
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