|
|
|
|
|
|
|
|
Note 1 - 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 preparation of the consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Reclassification. Certain prior year amounts have been reclassified to conform with current year presentation. This includes the reclassification of accrued capital expenditures of $55.5 million from Accounts Payable to Other Accruals and Current Liabilities on the Consolidated Balance Sheet at September 30, 2010. This reclassification did not impact the Consolidated Statement of Income or the Consolidated Statement of Cash Flows for any of the periods presented.
Earnings for Interim Periods. The Company, in its opinion, has included all adjustments that are necessary for a fair statement of the results of operations for the reported periods. The consolidated financial statements and notes thereto, included herein, should be read in conjunction with the financial statements and notes for the years ended September 30, 2010, 2009 and 2008 that are included in the Company's 2010 Form 10-K. The consolidated financial statements for the year ended September 30, 2011 will be audited by the Company's independent registered public accounting firm after the end of the fiscal year.
The earnings for the nine months ended June 30, 2011 should not be taken as a prediction of earnings for the entire fiscal year ending September 30, 2011. Most of the business of the Utility and Energy Marketing segments is seasonal in nature and is influenced by weather conditions. Due to the seasonal nature of the heating business in the Utility and Energy Marketing segments, earnings during the winter months normally represent a substantial part of the earnings that those segments are expected to achieve for the entire fiscal year. The Company's business segments are discussed more fully in Note 8 ' Business Segment Information.
Consolidated Statement of Cash Flows. For purposes of the Consolidated Statement of Cash Flows, the Company considers all highly liquid debt instruments purchased with a maturity of generally three months or less to be cash equivalents.
At June 30, 2011, the Company accrued $60.7 million of capital expenditures in the Exploration and Production segment, the majority of which was in the Appalachian region. The Company also accrued $5.9 million of capital expenditures in the Pipeline and Storage segment at June 30, 2011. These amounts were excluded from the Consolidated Statement of Cash Flows at June 30, 2011 since they represent non-cash investing activities at that date. Accrued capital expenditures at June 30, 2011 are included in Other Accruals and Current Liabilities on the Consolidated Balance Sheet.
At September 30, 2010, the Company accrued $55.5 million of capital expenditures in the Exploration and Production segment, the majority of which was in the Appalachian region. This amount was excluded from the Consolidated Statement of Cash Flows at September 30, 2010 since it represented a non-cash investing activity at that date. These capital expenditures were paid during the quarter ended December 31, 2010 and have been included in the Consolidated Statement of Cash Flows for the nine months ended June 30, 2011. Accrued capital expenditures at September 30, 2010 are included in Other Accruals and Current Liabilities on the Consolidated Balance Sheet.
At June 30, 2010, the Company accrued $24.3 million of capital expenditures in the Exploration and Production segment, the majority of which was in the Appalachian region. This amount was excluded from the Consolidated Statement of Cash Flows at June 30, 2010 since it represented a non-cash investing activity at that date.
At September 30, 2009, the Company accrued $9.1 million of capital expenditures in the Exploration and Production segment, the majority of which was in the Appalachian region. The Company also accrued $0.7 million of capital expenditures in the All Other category related to the construction of the Midstream Covington Gathering System. These amounts were excluded from the Consolidated Statement of Cash Flows at September 30, 2009 since they represented non-cash investing activities at that date. These capital expenditures were paid during the quarter ended December 31, 2009 and have been included in the Consolidated Statement of Cash Flows for the nine months ended June 30, 2010.
Hedging Collateral Deposits. This is an account title for cash held in margin accounts funded by the Company to serve as collateral for hedging positions. At June 30, 2011, the Company had hedging collateral deposits of $5.6 million related to its exchange-traded futures contracts and $32.4 million related to its over-the-counter crude oil swap agreements. At September 30, 2010, the Company had hedging collateral deposits of $10.1 million related to its exchange-traded futures contracts and $1.0 million related to its over-the-counter crude oil swap agreements. In accordance with its accounting policy, the Company does not offset hedging collateral deposits paid or received against related derivative financial instrument liability or asset balances.
Gas Stored Underground ' Current. In the Utility segment, gas stored underground ' current is carried at lower of cost or market, on a LIFO method. Gas stored underground ' current normally declines during the first and second quarters of the year and is replenished during the third and fourth quarters. In the Utility segment, the current cost of replacing gas withdrawn from storage is recorded in the Consolidated Statements of Income and a reserve for gas replacement is recorded in the Consolidated Balance Sheets under the caption 'Other Accruals and Current Liabilities.' Such reserve, which amounted to $45.0 million at June 30, 2011, is reduced to zero by September 30 of each year as the inventory is replenished.
Property, Plant and Equipment. 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. Such costs amounted to $193.9 million and $151.2 million at June 30, 2011 and September 30, 2010, respectively. All costs related to unproved properties are reviewed quarterly to determine if impairment has occurred. The amount of any impairment is transferred to the pool of capitalized costs being amortized.
In March 2011, the Company entered into a purchase and sale agreement to sell its off-shore oil and natural gas properties effective as of January 1, 2011 in the Gulf of Mexico for approximately $70 million and received a deposit of $7.0 million from the purchaser. The Company completed the sale in April 2011, receiving an additional $54.8 million. The difference between the total proceeds received of $61.8 million and the sale price of $70.0 million represents a purchase price adjustment for the operating cash flow that the Company recorded from January 1, 2011 to the closing date of the sale. Under the full cost method of accounting for oil and natural gas properties, the sale proceeds were accounted for as a reduction of capitalized costs in April 2011. 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.
Capitalized costs are subject to the SEC full cost ceiling test. The ceiling test, which is performed each quarter, determines a limit, or ceiling, on the amount of property acquisition, exploration and development costs that can be capitalized. The ceiling under this test represents (a) the present value of estimated future net cash flows, excluding future cash outflows associated with settling asset retirement obligations that have been accrued on the balance sheet, using a discount factor of 10%, which is computed by applying prices of oil and gas (as adjusted for hedging) to estimated future production of proved oil and gas reserves as of the date of the latest balance sheet, less estimated future expenditures, plus (b) the cost of unevaluated properties not being depleted, less (c) income tax effects related to the differences between the book and tax basis of the properties. In accordance with the SEC final rule on Modernization of Oil and Gas Reporting, the natural gas and oil prices used to calculate the full cost ceiling (as of June 30, 2011) are based on an unweighted arithmetic average of the first day of the month oil and gas prices for each month within the twelve-month period prior to the end of the reporting period. If capitalized costs, net of accumulated depreciation, depletion and amortization and related deferred income taxes, exceed the ceiling at the end of any quarter, a permanent impairment is required to be charged to earnings in that quarter. At June 30, 2011, the Company's capitalized costs were below the full cost ceiling for the Company's oil and gas properties. As a result, an impairment charge was not required at June 30, 2011.
Accumulated Other Comprehensive Loss. The components of Accumulated Other Comprehensive Loss, net of related tax effect, are as follows (in thousands):
At June 30, 2011 | At September 30, 2010 | |||||||
Funded Status of the Pension and Other Post-Retirement Benefit Plans |
$ | (79,465 | ) | $ | (79,465 | ) | ||
Cumulative Foreign Currency Translation Adjustment |
' | (51 | ) | |||||
Net Unrealized Gain on Derivative Financial Instruments |
557 | 32,876 | ||||||
Net Unrealized Gain on Securities Available for Sale |
3,810 | 1,655 | ||||||
|
|
|
|
|||||
Accumulated Other Comprehensive Loss |
$ | (75,098 | ) | $ | (44,985 | ) | ||
|
|
|
|
At June 30, 2011 | At September 30, 2010 | |||||||
Prepayments |
$ | 12,645 | $ | 13,884 | ||||
Prepaid Property and Other Taxes |
10,653 | 12,413 | ||||||
Federal Income Taxes Receivable |
9,514 | 56,334 | ||||||
State Income Taxes Receivable |
7,902 | 18,007 | ||||||
Fair Values of Firm Commitments |
4,072 | 15,331 | ||||||
|
|
|
|
|||||
$ | 44,786 | $ | 115,969 | |||||
|
|
|
|
Stock-Based Compensation. During the nine months ended June 30, 2011, the Company granted 180,000 non-performance based SARs having a weighted average exercise price of $63.87 per share. The weighted average grant date fair value of these SARs was $15.33 per share. These SARs may be settled in cash, in shares of common stock of the Company, or in a combination of cash and shares of common stock of the Company, as determined by the Company. These SARs are considered equity awards under the current authoritative guidance for stock-based compensation. The accounting for those SARs is the same as the accounting for stock options. There were no SARs granted during the quarter ended June 30, 2011. The non-performance based SARs granted during the nine months ended June 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 nine months ended June 30, 2011 was estimated on the date of grant using the same accounting treatment that is applied for stock options.
There were no stock options granted during the quarter or nine months ended June 30, 2011. The Company did not recognize a tax benefit related to the exercise of stock options for the calendar year ended December 31, 2010 due to tax loss carryforwards. The Company expects to recognize a tax benefit of $18.1 million in Paid in Capital related to calendar 2010 stock option exercises in future years as the tax loss carryforward is utilized.
The Company granted 47,250 restricted share awards (non-vested stock as defined by the current accounting literature) during the nine months ended June 30, 2011. The weighted average fair value of such restricted shares was $63.98 per share. There were no restricted share awards granted during the quarter ended June 30, 2011. In addition, the Company granted 8,100 and 37,000 restricted stock units during the quarter and nine months ended June 30, 2011, respectively. The weighted average fair value of such restricted stock units was $65.50 per share and $59.82 per share for the quarter and nine months ended June 30, 2011, respectively. Restricted stock units represent the right to receive shares of common stock of the Company (or the equivalent value in cash or a combination of cash and shares of common stock of the Company, as determined by the Company) at the end of a specified time period. These restricted stock units do not entitle the participant to receive dividends during the vesting period. The accounting for these restricted stock units is the same as the accounting for restricted share awards, except that the fair value at the date of grant of the restricted stock units must be reduced by the present value of forgone dividends over the vesting term of the award.
New Authoritative Accounting and Financial Reporting Guidance.In May 2011, the FASB issued authoritative guidance regarding fair value measurement as a joint project with the IASB. The objective of the guidance was to bring together as closely as possible the fair value measurement and disclosure guidance issued by the two boards. The guidance includes a few updates to measurement guidance and some enhanced disclosure requirements. For all Level 3 fair value measurements, the guidance requires quantitative information about significant unobservable inputs used and a description of the valuation processes in place. The guidance also requires a qualitative discussion about the sensitivity of recurring Level 3 fair value measurements and information about any transfers between Level 1 and Level 2 of the fair value hierarchy. The new guidance also contains a requirement that all fair value measurements, whether they are recorded on the balance sheet or disclosed in the footnotes, be classified as Level 1, Level 2 or Level 3 within the fair value hierarchy. This authoritative guidance will be effective as of the Company's second quarter of fiscal 2012. The Company is currently evaluating the impact that adoption of this authoritative guidance will have on its consolidated financial statement disclosures.
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 to the Company's financial statements.
|
Note 2 - Fair Value Measurements
The FASB authoritative guidance regarding fair value measurements establishes a fair-value hierarchy and prioritizes the inputs used in valuation techniques that measure fair value. Those inputs are prioritized into three levels. Level 1 inputs are unadjusted quoted prices in active markets for assets or liabilities that the Company has the ability to access at the measurement date. Level 2 inputs are inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly at the measurement date. Level 3 inputs are unobservable inputs for the asset or liability at the measurement date. The 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 June 30, 2011 and September 30, 2010. Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement.
Recurring Fair Value Measures | At fair value as of June 30, 2011 | |||||||||||||||
(Thousands of Dollars) |
Level 1 | Level 2 | Level 3 | Total | ||||||||||||
Assets: |
||||||||||||||||
Cash Equivalents ' Money Market Mutual Funds |
$ | 118,652 | $ | ' | $ | ' | $ | 118,652 | ||||||||
Derivative Financial Instruments: |
||||||||||||||||
Commodity Futures Contracts ' Gas |
56 | ' | ' | 56 | ||||||||||||
Over the Counter Swaps ' Oil |
' | (176 | ) | ' | (176 | ) | ||||||||||
Over the Counter Swaps ' Gas |
' | 43,367 | ' | 43,367 | ||||||||||||
Other Investments: |
||||||||||||||||
Balanced Equity Mutual Fund |
22,030 | ' | ' | 22,030 | ||||||||||||
Common Stock ' Financial Services Industry |
6,979 | ' | ' | 6,979 | ||||||||||||
Other Common Stock |
237 | ' | ' | 237 | ||||||||||||
Hedging Collateral Deposits |
37,984 | ' | ' | 37,984 | ||||||||||||
|
|
|
|
|
|
|
|
|||||||||
Total |
$ | 185,938 | $ | 43,191 | $ | ' | $ | 229,129 | ||||||||
|
|
|
|
|
|
|
|
|||||||||
Liabilities: |
||||||||||||||||
Derivative Financial Instruments: |
||||||||||||||||
Commodity Futures Contracts ' Gas |
$ | 2,960 | $ | ' | $ | ' | $ | 2,960 | ||||||||
Over the Counter Swaps ' Oil |
' | ' | 50,453 | 50,453 | ||||||||||||
Over the Counter Swaps ' Gas |
' | (8,806 | ) | ' | (8,806 | ) | ||||||||||
|
|
|
|
|
|
|
|
|||||||||
Total |
$ | 2,960 | $ | (8,806 | ) | $ | 50,453 | $ | 44,607 | |||||||
|
|
|
|
|
|
|
|
|||||||||
Total Net Assets/(Liabilities) |
$ | 182,978 | $ | 51,997 | $ | (50,453 | ) | $ | 184,522 | |||||||
|
|
|
|
|
|
|
|
Recurring Fair Value Measures | At fair value as of September 30, 2010 | |||||||||||||||
(Thousands of Dollars) |
Level 1 | Level 2 | Level 3 | Total | ||||||||||||
Assets: |
||||||||||||||||
Cash Equivalents ' Money Market Mutual Funds |
$ | 277,423 | $ | ' | $ | ' | $ | 277,423 | ||||||||
Derivative Financial Instruments: |
||||||||||||||||
Over the Counter Swaps ' Gas |
' | 67,387 | ' | 67,387 | ||||||||||||
Over the Counter Swaps ' Oil |
' | ' | (2,203 | ) | (2,203 | ) | ||||||||||
Other Investments: |
||||||||||||||||
Balanced Equity Mutual Fund |
17,256 | ' | ' | 17,256 | ||||||||||||
Common Stock ' Financial Services Industry |
4,991 | ' | ' | 4,991 | ||||||||||||
Other Common Stock |
241 | ' | ' | 241 | ||||||||||||
Hedging Collateral Deposits |
11,134 | ' | ' | 11,134 | ||||||||||||
|
|
|
|
|
|
|
|
|||||||||
Total |
$ | 311,045 | $ | 67,387 | $ | (2,203 | ) | $ | 376,229 | |||||||
|
|
|
|
|
|
|
|
|||||||||
Liabilities: |
||||||||||||||||
Derivative Financial Instruments: |
||||||||||||||||
Commodity Futures Contracts ' Gas |
$ | 5,840 | $ | ' | $ | ' | $ | 5,840 | ||||||||
Over the Counter Swaps ' Oil |
' | ' | 14,280 | 14,280 | ||||||||||||
Over the Counter Swaps ' Gas |
' | 40 | ' | 40 | ||||||||||||
|
|
|
|
|
|
|
|
|||||||||
Total |
$ | 5,840 | $ | 40 | $ | 14,280 | $ | 20,160 | ||||||||
|
|
|
|
|
|
|
|
|||||||||
Total Net Assets/(Liabilities) |
$ | 305,205 | $ | 67,347 | $ | (16,483 | ) | $ | 356,069 | |||||||
|
|
|
|
|
|
|
|
Derivative Financial Instruments
At June 30, 2011 and September 30, 2010, the derivative financial instruments reported in Level 1 consist of natural gas NYMEX futures contracts used in the Company's Energy Marketing and Pipeline and Storage segments. Hedging collateral deposits of $5.6 million (at June 30, 2011) and $10.1 million (at September 30, 2010), which are associated with these futures contracts have been reported in Level 1 as well. The derivative financial instruments reported in Level 2 at June 30, 2011 consist of crude oil and natural gas price swap agreements used in the Company's Exploration and Production and Energy Marketing segments. At September 30, 2010, the derivative financial instruments reported in Level 2 consist of natural gas price swap agreements used in the Company's Exploration and Production and Energy Marketing segments. 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 Company's Exploration and Production segment's crude oil price swap agreements at June 30, 2011 and all of its crude oil price swap agreements at September 30, 2010. Hedging collateral deposits of $32.4 million and $1.0 million associated with these crude oil price swap agreements have been reported in Level 1 at June 30, 2011 and September 30, 2010, respectively. 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). Based on an assessment of the counterparties' credit risk, the fair market value of the price swap agreements reported as Level 2 assets have been reduced by $0.4 million and $1.0 million at June 30, 2011 and September 30, 2010, respectively. 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 have been reduced by $0.1 million and $0.3 million at June 30, 2011 and September 30, 2010, respectively. These credit reserves were determined by applying default probabilities to the anticipated cash flows that the Company is either expecting from its counterparties or expecting to pay to its counterparties.
The tables listed below provide reconciliations of the beginning and ending net balances for assets and liabilities measured at fair value and classified as Level 3 for the quarters and nine months ended June 30, 2011 and 2010, respectively. For the quarters and nine months ended June 30, 2011 and June 30, 2010, no transfers in or out of Level 1 or Level 2 occurred. There were no purchases or sales of derivative financial instruments during the periods presented in the tables below. All settlements of the derivative financial instruments are reflected in the Gains/Losses Realized and Included in Earnings column of the tables below.
Fair Value Measurements Using Unobservable Inputs (Level 3) | ||||||||||||||||||||
(Thousands of Dollars) |
Total Gains/Losses | |||||||||||||||||||
April 1, 2011 |
Gains/Losses Realized and Included in Earnings |
Gains/Losses Unrealized and Included in Other Comprehensive Income (Loss) |
Transfer In/Out of Level 3 |
June 30, 2011 |
||||||||||||||||
Derivative Financial Instruments(2) |
$ | (71,913 | ) | $ | 15,377 | (1) | $ | 6,083 | $ | ' | $ | (50,453 | ) |
(1) |
Amounts are reported in Operating Revenues in the Consolidated Statement of Income for the three months ended June 30, 2011. |
(2) |
Derivative Financial Instruments are shown on a net basis. |
Fair Value Measurements Using Unobservable Inputs (Level 3) | ||||||||||||||||||||
(Thousands of Dollars) |
Total Gains/Losses | |||||||||||||||||||
October 1, 2010 |
Gains/Losses Realized and Included in Earnings |
Gains/Losses Unrealized and Included in Other Comprehensive Income (Loss) |
Transfer In/Out of Level 3 |
June 30, 2011 |
||||||||||||||||
Derivative Financial Instruments(2) |
$ | (16,483 | ) | $ | 28,545 | (1) | $ | (62,515 | ) | $ | ' | $ | (50,453 | ) |
(1) |
Amounts are reported in Operating Revenues in the Consolidated Statement of Income for the nine months ended June 30, 2011. |
(2) |
Derivative Financial Instruments are shown on a net basis. |
Fair Value Measurements Using Unobservable Inputs (Level 3) | ||||||||||||||||||||
(Thousands of Dollars) |
Total Gains/Losses | |||||||||||||||||||
April 1, 2010 |
Gains/Losses Realized and Included in Earnings |
Gains/Losses Unrealized and Included in Other Comprehensive Income (Loss) |
Transfer In/Out of Level 3 |
June 30, 2010 |
||||||||||||||||
Derivative Financial Instruments(2) |
$ | (14,100 | ) | $ | (2,172 | )(1) | $ | 16,126 | $ | ' | $ | (146 | ) |
(1) |
Amounts are reported in Operating Revenues in the Consolidated Statement of Income for the three months ended June 30, 2010. |
(2) |
Derivative Financial Instruments are shown on a net basis. |
Fair Value Measurements Using Unobservable Inputs (Level 3) | ||||||||||||||||||||
(Thousands of Dollars) |
Total Gains/Losses | |||||||||||||||||||
October 1, 2010 |
Gains/Losses Realized and Included in Earnings |
Gains/Losses Unrealized and Included in Other Comprehensive Income (Loss) |
Transfer In/Out of Level 3 |
June 30, 2010 |
||||||||||||||||
Derivative Financial Instruments(2) |
$ | 26,969 | $ | (6,969 | )(1) | $ | (20,146 | ) | $ | ' | $ | (146 | ) |
(1) |
Amounts are reported in Operating Revenues in the Consolidated Statement of Income for the nine months ended June 30, 2010. |
(2) |
Derivative Financial Instruments are shown on a net basis. |
|
Note 3 - 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 (in thousands):
June 30, 2011 | September 30, 2010 | |||||||||||||||
Carrying Amount |
Fair Value | Carrying Amount |
Fair Value | |||||||||||||
Long-Term Debt |
$ | 1,049,000 | $ | 1,209,054 | $ | 1,249,000 | $ | 1,423,349 |
Other Investments. Investments in life insurance are stated at their cash surrender values or net present value as discussed below. Investments in an equity mutual fund and the stock of an insurance company (marketable equity securities), as discussed below, are stated at fair value based on quoted market prices.
Other investments include cash surrender values of insurance contracts (net present value in the case of split-dollar collateral assignment arrangements) and marketable equity securities. The values of the insurance contracts amounted to $54.9 million at June 30, 2011 and $55.4 million at September 30, 2010. The fair value of the equity mutual fund was $22.0 million at June 30, 2011 and $17.3 million at September 30, 2010. The gross unrealized gain on this equity mutual fund was $1.5 million at June 30, 2011. The unrealized gain on the equity mutual fund at September 30, 2010 was negligible as the fair value was approximately equal to the cost basis. The fair value of the stock of an insurance company was $7.0 million at June 30, 2011 and $5.0 million at September 30, 2010. The gross unrealized gain on this stock was $4.6 million at June 30, 2011 and $2.6 million at September 30, 2010. The insurance contracts and marketable equity securities are primarily informal funding mechanisms for various benefit obligations the Company has to certain employees.
Derivative Financial Instruments. The Company is exposed to certain risks relating to its ongoing business operations. The primary risk managed by using derivative instruments is commodity price risk in the Exploration and Production, Energy Marketing and Pipeline and Storage segments. The Company enters into futures contracts and over-the-counter swap agreements for natural gas and crude oil to manage the price risk associated with forecasted sales of gas and oil. The Company also enters into futures contracts and swaps to manage the risk associated with forecasted gas purchases, storage of gas, withdrawal of gas from storage to meet customer demand and the potential decline in the value of gas held in storage. The duration of the majority of the Company's hedges do not typically exceed 3 years.
The Company has presented its net derivative assets and liabilities on its Consolidated Balance Sheets at June 30, 2011 and September 30, 2010 as shown in the table below.
Fair Values of Derivative Instruments | ||||||||
(Dollar Amounts in Thousands) | ||||||||
Asset Derivatives |
Liability Derivatives | |||||||
Derivatives Designated as Hedging Instruments |
Consolidated Balance Sheet Location |
Fair Value |
Consolidated Balance Sheet Location |
Fair Value | ||||
Commodity Contracts ' at June 30, 2011 |
Fair Value of Derivative Financial Instruments |
$43,247 | Fair Value of Derivative Financial Instruments |
$44,607 | ||||
Commodity Contracts ' at September 30, 2010 |
Fair Value of Derivative |
$65,184 | Fair Value of Derivative Financial Instruments |
$20,160 |
The following table discloses the fair value of derivative contracts on a gross-contract basis as opposed to the net-contract basis presentation on the Consolidated Balance Sheets at June 30, 2011 and September 30, 2010.
Fair Values of Derivative Instruments | ||||
(Dollar Amounts in Thousands) | ||||
Derivatives Designated as Hedging Instruments |
Gross Asset Derivatives |
Gross Liability Derivatives | ||
Fair Value |
Fair Value | |||
Commodity Contracts ' at |
$54,971 | $56,331 | ||
Commodity Contracts ' at |
$77,837 | $32,813 |
Cash flow hedges
For derivative instruments that are designated and qualify as a cash flow hedge, the effective portion of the gain or loss on the derivative is reported as a component of other comprehensive income (loss) and reclassified into earnings in the period or periods during which the hedged transaction affects earnings. Gains and losses on the derivative representing either hedge ineffectiveness or hedge components excluded from the assessment of effectiveness are recognized in current earnings.
At June 30, 2011, 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 |
73.7 Bcf (all short positions) | |
Crude Oil |
3,165,000 Bbls (all short positions) |
In conjunction with the sale of the Company's off-shore oil and natural gas properties in the Gulf of Mexico, the Company discontinued hedge accounting for the remaining derivative financial instruments that had been designated as hedges of Gulf of Mexico production. At June 30, 2011, natural gas derivative contracts totaling 0.4 Bcf were still outstanding. They were excluded from the table above since there is no forecasted sale associated with the hedged volume. Changes to the fair value of these natural gas derivative contracts, which mature in September 2011, are being reflected in the Consolidated Statement of Income.
At June 30, 2011, the Company's Energy Marketing segment had the following commodity derivative contracts (futures contracts and swaps) outstanding to hedge forecasted sales (where the Company uses short positions to mitigate the risk associated with natural gas price decreases and its impact on decreasing revenues and earnings) and purchases (where the Company uses long positions (i.e. positions that pay-off in the event of commodity price increases) to mitigate the risk of increasing natural gas prices, which would lead to increased purchased gas expense and decreased earnings):
Commodity |
Units | |
Natural Gas |
6.6 Bcf (5.3 Bcf short positions (forecasted storage withdrawals) and 1.3 Bcf long positions (forecasted storage injections)) |
At June 30, 2011, the Company's Pipeline and Storage segment had the following commodity derivative contracts (futures contracts) outstanding to hedge forecasted sales (where the Company uses short positions to mitigate the risk associated with natural gas price decreases and its impact on decreasing revenues and earnings):
Commodity |
Units | |
Natural Gas |
1.5 Bcf (all short positions) |
At June 30, 2011, the Company's Exploration and Production segment had $0.1 million (less than $0.1 million after tax) of net hedging gains included in the accumulated other comprehensive income (loss) balance. It is expected that $3.2 million ($1.8 million after tax) of gains will be reclassified into the Consolidated Statement of Income (Loss) within the next 12 months as the expected sales of the underlying commodities occur. It is expected that $3.1 million ($1.7 million after tax) of losses will be reclassified into the Consolidated Statement of Income (loss) after 12 months. See Note 1, under Accumulated Other Comprehensive Income (Loss), for the after-tax gain (loss) pertaining to derivative financial instruments (Net Unrealized Gain (Loss) on Derivative Financial Instruments in Note 1 includes the Exploration and Production, Energy Marketing and Pipeline and Storage segments).
At June 30, 2011, the Company's Energy Marketing segment had $0.7 million ($0.5 million after tax) of net hedging gains included in the accumulated other comprehensive income (loss) balance. It is expected that the full amount will be reclassified into the Consolidated Statement of Income (Loss) within the next 12 months as the sales and purchases of the underlying commodities occur. See Note 1, under Accumulated Other Comprehensive Income (Loss), for the after-tax gain (loss) pertaining to derivative financial instruments (Net Unrealized Gain (Loss) on Derivative Financial Instruments in Note 1 includes the Exploration and Production, Energy Marketing and Pipeline and Storage segments).
At June 30, 2011, the Company's Pipeline and Storage segment had less than $0.1 million of net hedging gains included in the accumulated other comprehensive income (loss) balance. It is expected that the full amount will be reclassified into the Consolidated Statement of Income (Loss) within the next 12 months as the expected sales of the underlying commodities occur. See Note 1, under Accumulated Other Comprehensive Income (Loss), for the after-tax gain (loss) pertaining to derivative financial instruments (Net Unrealized Gain (Loss) on Derivative Financial Instruments in Note 1 includes the Exploration and Production, Energy Marketing and Pipeline and Storage segments).
The Effect of Derivative Financial Instruments on the Statement of Financial Performance for the Three Months Ended June 30, 2011 and 2010 (Thousands of Dollars) |
||||||||||||||||||||||||||||
Derivatives in Cash Flow Hedging Relationships |
Amount of Derivative Gain or (Loss) Recognized in Other Comprehensive Income (Loss) on the Consolidated Statement of Comprehensive Income (Loss) (Effective Portion) for the Three Months Ended June 30, |
Location of Derivative Gain or (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) on the Consolidated Balance Sheet into the Consolidated Statement of Income (Effective Portion) |
Amount of Derivative Gain or (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) on the Consolidated Balance Sheet into the Consolidated Statement of Income (Effective Portion) for the Three Months Ended June 30, |
Location of Derivative Gain or (Loss) Recognized in the Consolidated Statement of Income (Ineffective Portion and Amount Excluded from Effectiveness Testing) |
Derivative Gain or (Loss) Recognized in the Consolidated Statement of Income (Ineffective Portion and Amount Excluded from Effectiveness Testing) for the Three Months Ended June 30, |
|||||||||||||||||||||||
2011 | 2010 | 2011 | 2010 | 2011 | 2010 | |||||||||||||||||||||||
Commodity Contracts ' Exploration & Production segment |
$ | 25,399 | $ | 16,445 | Operating Revenue |
$ | (5,548 | ) | $ | 11,592 | Operating Revenue |
$ | 570 | $ | ' | |||||||||||||
Commodity Contracts ' Energy Marketing segment |
$ | 737 | $ | 519 | Purchased Gas |
$ | 1,793 | $ | 238 | Purchased Gas | $ | ' | $ | ' | ||||||||||||||
Commodity Contracts ' Pipeline & Storage segment |
$ | 242 | $ | (436 | ) | Operating Revenue |
$ | ' | $ | ' | Operating Revenue |
$ | ' | $ | ' | |||||||||||||
Total | $ | 26,378 | $ | 16,528 | $ | (3,755 | ) | $ | 11,830 | $ | 570 | $ | ' |
The Effect of Derivative Financial Instruments on the Statement of Financial Performance for the Nine Months Ended June 30, 2011 and 2010 (Thousands of Dollars) |
||||||||||||||||||||||||||||
Derivatives in Cash Flow Hedging Relationships |
Amount of Derivative Gain or (Loss) Recognized in Other Comprehensive Income (Loss) on the Consolidated Statement of Comprehensive Income (Loss) (Effective Portion) for the Nine Months Ended June 30, |
Location of Derivative Gain or (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) on the Consolidated Balance Sheet into the Consolidated Statement of Income (Effective Portion) |
Amount of Derivative Gain or (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) on the Consolidated Balance Sheet into the Consolidated Statement of Income (Effective Portion) for the Nine Months Ended June 30, |
Location of Derivative Gain or (Loss) Recognized in the Consolidated Statement of Income (Ineffective Portion and Amount Excluded from Effectiveness Testing) |
Derivative Gain or (Loss) Recognized in the Consolidated Statement of Income (Ineffective Portion and Amount Excluded from Effectiveness Testing) for the Nine Months Ended June 30, |
|||||||||||||||||||||||
2011 | 2010 | 2011 | 2010 | 2011 | 2010 | |||||||||||||||||||||||
Commodity Contracts ' Exploration & Production segment |
$ | (42,969 | ) | $ | 32,910 | Operating Revenue |
$ | 5,415 | $ | 29,170 | Operating Revenue |
$ | 570 | $ | ' | |||||||||||||
Commodity Contracts ' Energy Marketing segment |
$ | 1,340 | $ | 5,821 | Purchased Gas | $ | 7,095 | $ | (209 | ) | Purchased Gas | $ | ' | $ | ' | |||||||||||||
Commodity Contracts ' Pipeline & Storage segment |
$ | 27 | $ | 577 | Operating Revenue |
$ | ' | $ | 511 | Operating Revenue |
$ | ' | $ | ' | ||||||||||||||
Total | $ | (41,602 | ) | $ | 39,308 | $ | 12,510 | $ | 29,472 | $ | 570 | $ | ' |
Fair value hedges
The Company's Energy Marketing segment utilizes fair value hedges to mitigate risk associated with fixed price sales commitments, fixed price purchase commitments, and the decline in the value of natural gas held in storage. With respect to fixed price sales commitments, the Company enters into long positions to mitigate the risk of price increases for natural gas supplies that could occur after the Company enters into fixed price sales agreements with its customers. With respect to fixed price purchase commitments, the Company enters into short positions to mitigate the risk of price decreases that could occur after the Company locks into fixed price purchase deals with its suppliers. With respect to storage hedges, the Company enters into short positions to mitigate the risk of price decreases that could result in a lower of cost or market writedown of the value of natural gas in storage that is recorded in the Company's financial statements. As of June 30, 2011, the Company's Energy Marketing segment had fair value hedges covering approximately 10.5 Bcf (7.4 Bcf of fixed price sales commitments (all long positions) and 3.1 Bcf of fixed price purchase commitments (all short positions)). For derivative instruments that are designated and qualify as a fair value hedge, the gain or loss on the derivative as well as the offsetting gain or loss on the hedged item attributable to the hedged risk completely offset each other in current earnings, as shown below.
Consolidated Statement of Income |
Gain/(Loss) on Derivative | Gain/(Loss) on Commitment | ||||||
Operating Revenues |
$ | 9,531,151 | $ | (9,531,151 | ) | |||
Purchased Gas |
$ | (941,391 | ) | $ | 941,391 |
Derivatives in Fair Value Hedging Relationships |
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 Nine Months Ended June 30, 2011 (In Thousands) |
||||
Commodity Contracts ' Energy |
Operating Revenues | $ | 9,531 | |||
Commodity Contracts ' Energy |
Purchased Gas | $ | (638 | ) | ||
Commodity Contracts ' Energy |
Purchased Gas | $ | (303 | ) | ||
|
|
|||||
$ | 8,590 | |||||
|
|
As of June 30, 2011, eight of the eleven counterparties to the Company's outstanding derivative instrument contracts (specifically the over-the-counter swaps) had a common credit-risk related contingency feature. In the event the Company's credit rating increases or falls below a certain threshold (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 would be required. At June 30, 2011, the fair market value of the derivative financial instrument assets with a credit-risk related contingency feature was $24.6 million according to the Company's internal model (discussed in Note 2 ' Fair Value Measurements). At June 30, 2011, the fair market value of the derivative financial instrument liabilities with a credit-risk related contingency feature was $41.6 million according to the Company's internal model (discussed in Note 2 ' Fair Value Measurements). The liability with one counterparty was $40.3 million. For its over-the-counter crude oil swap agreements, which are in a liability position, the Company was required to post $32.4 million in hedging collateral deposits at June 30, 2011. This is discussed in Note 1 under Hedging Collateral Deposits.
For its exchange traded futures contracts, the majority of which are in a liability position, the Company had posted $5.6 million in hedging collateral as of June 30, 2011. As these are exchange traded futures contracts, there are no specific credit-risk related contingency features. The Company posts hedging collateral based on open positions and margin requirements it has with its counterparties.
The 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 1 under Hedging Collateral Deposits.
|
Note 4 - Income Taxes
The components of federal and state income taxes included in the Consolidated Statements of Income are as follows (in thousands):
Nine Months Ended | ||||||||
June 30, | ||||||||
2011 | 2010 | |||||||
Current Income Taxes |
||||||||
Federal |
$ | (1,825 | ) | $ | 42,323 | |||
State |
2,703 | 9,914 | ||||||
Deferred Income Taxes |
||||||||
Federal |
112,385 | 50,079 | ||||||
State |
27,941 | 13,734 | ||||||
|
|
|
|
|||||
141,204 | 116,050 | |||||||
Deferred Investment Tax Credit |
(523 | ) | (523 | ) | ||||
|
|
|
|
|||||
Total Income Taxes |
$ | 140,681 | $ | 115,527 | ||||
|
|
|
|
|||||
Presented as Follows: |
||||||||
Other Income |
$ | (523 | ) | $ | (523 | ) | ||
Income Tax Expense ' Continuing Operations |
141,204 | 115,449 | ||||||
Income from Discontinued Operations |
' | 601 | ||||||
|
|
|
|
|||||
Total Income Taxes |
$ | 140,681 | $ | 115,527 | ||||
|
|
|
|
Total income taxes as reported differ from the amounts that were computed by applying the federal income tax rate to income before income taxes. The following is a reconciliation of this difference (in thousands):
Nine Months Ended | ||||||||
June 30, | ||||||||
2011 | 2010 | |||||||
U.S. Income Before Income Taxes |
$ | 361,726 | $ | 303,039 | ||||
|
|
|
|
|||||
Income Tax Expense, Computed at Federal Statutory Rate of 35% |
$ | 126,604 | $ | 106,064 | ||||
Increase (Reduction) in Taxes Resulting from: |
||||||||
State Income Taxes |
19,919 | 15,371 | ||||||
Miscellaneous |
(5,842 | ) | (5,908 | ) | ||||
|
|
|
|
|||||
Total Income Taxes |
$ | 140,681 | $ | 115,527 | ||||
|
|
|
|
Significant components of the Company's deferred tax liabilities and assets are as follows (in thousands):
At June 30, 2011 | At September 30, 2010 | |||||||
Deferred Tax Liabilities: |
||||||||
Property, Plant and Equipment |
$ | 1,035,695 | $ | 849,869 | ||||
Pension and Other Post-Retirement Benefit Costs |
183,651 | 177,853 | ||||||
Other |
38,958 | 63,671 | ||||||
|
|
|
|
|||||
Total Deferred Tax Liabilities |
1,258,304 | 1,091,393 | ||||||
|
|
|
|
|||||
Deferred Tax Assets: |
||||||||
Pension and Other Post-Retirement Benefit Costs |
(227,458 | ) | (223,588 | ) | ||||
Tax Loss Carryforwards |
(54,472 | ) | (9,772 | ) | ||||
Other |
(80,114 | ) | (81,751 | ) | ||||
|
|
|
|
|||||
Total Deferred Tax Assets |
(362,044 | ) | (315,111 | ) | ||||
|
|
|
|
|||||
Total Net Deferred Income Taxes |
$ | 896,260 | $ | 776,282 | ||||
|
|
|
|
|||||
Presented as Follows: |
||||||||
Net Deferred Tax Liability/(Asset) ' Current |
$ | (22,885 | ) | $ | (24,476 | ) | ||
Net Deferred Tax Liability ' Non-Current |
919,145 | 800,758 | ||||||
|
|
|
|
|||||
Total Net Deferred Income Taxes |
$ | 896,260 | $ | 776,282 | ||||
|
|
|
|
As a result of certain realization requirements of the authoritative guidance on stock-based compensation, the table of deferred tax liabilities and assets shown above does not include certain deferred tax assets at June 30, 2011 that arose directly from excess tax deductions related to stock-based compensation. A tax benefit of $18.1 million relating to the excess stock-based compensation deductions will be recorded in Paid in Capital in future years when such tax benefit is realized.
Regulatory liabilities representing the reduction of previously recorded deferred income taxes associated with rate-regulated activities that are expected to be refundable to customers amounted to $70.3 million and $69.6 million at June 30, 2011 and September 30, 2010, 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 $151.1 million and $149.7 million at June 30, 2011 and September 30, 2010, respectively.
The Company files U.S. federal and various state income tax returns. The Internal Revenue Service (IRS) is currently conducting an examination of the Company for fiscal 2010 and 2011 in accordance with the Compliance Assurance Process ('CAP'). The CAP audit employs a real time review of the 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 2008 and later years, IRS examinations for fiscal 2008 and prior years have been completed and the Company believes such years are effectively settled. During fiscal 2009, consent was received from the IRS National Office approving the Company's application to change its tax method of accounting for certain capitalized costs relating to its utility property. During fiscal 2010, local IRS examiners proposed to disallow most of the accounting method change recorded by the Company in fiscal 2009. The Company has filed a protest with the IRS Appeals Office disputing the local IRS findings.
The Company is also subject to various routine state income tax examinations. The Company's operating subsidiaries mainly operate in four states which have statutes of limitations that generally expire between three to four years from the date of filing of the income tax return.
|
Current Portion of Long-Term Debt. Current Portion of Long-Term Debt at June 30, 2011 consists of $150 million of 6.70% medium-term notes that mature in November 2011. Current Portion of Long-Term Debt at September 30, 2010 consisted of $200 million of 7.50% notes that matured in November 2010.
|
Note 6 – Commitments and Contingencies
Environmental Matters. The Company is subject to various federal, state and local laws and regulations relating to the protection of the environment. The Company has established procedures for the ongoing evaluation of its operations to identify potential environmental exposures and to comply with regulatory policies and procedures. It is the 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.
The Company has agreed with the NYDEC to remediate a former manufactured gas plant site located in New York. The Company has received approval from the NYDEC of a Remedial Design work plan for this site and has recorded an estimated minimum liability for remediation of this site of $14.5 million.
At June 30, 2011, the Company has estimated its remaining clean-up costs related to former manufactured gas plant sites and third party waste disposal sites (including the former manufactured gas plant site discussed above) will be in the range of $17.2 million to $21.4 million. The minimum estimated liability of $17.2 million, which includes the $14.5 million discussed above, has been recorded on the Consolidated Balance Sheet at June 30, 2011. The Company expects to recover its environmental clean-up costs through rate recovery.
The Company is currently not aware of any material additional exposure to environmental liabilities. However, changes in environmental regulations, new information or other factors could adversely impact the Company.
Other. The Company is involved in other litigation and regulatory matters arising in the normal course of business. These other matters may include, for example, negligence claims and tax, regulatory or other governmental audits, inspections, investigations and other proceedings. These matters may involve state and federal taxes, safety, compliance with regulations, rate base, cost of service and purchased gas cost issues, among other things. While these normal-course matters could have a material effect on earnings and cash flows in the quarterly and annual period in which they are resolved, they are not expected to change materially the Company's present liquidity position, nor are they expected to have a material adverse effect on the financial condition of the Company.
|
Note 7 — Discontinued Operations
On September 1, 2010, the Company sold its landfill gas operations in the states of Ohio, Michigan, Kentucky, Missouri, Maryland and Indiana. Those operations consisted of short distance landfill gas pipeline companies engaged in the purchase, sale and transportation of landfill gas. The Company's landfill gas operations were maintained under the Company's wholly-owned subsidiary, Horizon LFG. 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:
|
Three Months Ended |
|
Nine Months Ended |
|
June 30, |
|
June 30, |
(Thousands) |
2010 |
|
2010 |
|
|
|
|
Operating Revenues |
$2,135 |
|
$8,411 |
Operating Expenses |
2,177 |
|
7,021 |
Operating Income (Loss) |
(42) |
|
1,390 |
Interest Income |
1 |
|
1 |
Other Interest Expense |
(8) |
|
(19) |
Income (Loss) before Income Taxes |
(49) |
|
1,372 |
Income Tax Expense |
8 |
|
601 |
Income (Loss) from Discontinued Operations |
$(57) |
|
$771 |
|
Note 8 - Business Segment Information
The Company reports financial results for four segments: Utility, Pipeline and Storage, Exploration and Production and Energy Marketing. The division of the 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 data presented in the tables below reflect financial information for the segments and reconciliations to consolidated amounts. As stated in the 2010 Form 10-K, the Company evaluates segment performance based on income before discontinued operations, extraordinary items and cumulative effects of changes in accounting (when applicable). When these items are not applicable, the Company evaluates performance based on net income. There have been no changes in the basis of segmentation nor in the basis of measuring segment profit or loss from those used in the Company's 2010 Form 10-K. As for segment assets, the only significant changes from the segment assets disclosed in the 2010 Form 10-K involve the Exploration and Production segment as well as Corporate and Intersegment Eliminations. Total Exploration and Production segment assets have increased by $184.6 million while Corporate and Intersegment Eliminations have decreased by $163.3 million.
Quarter Ended June 30, 2011 (Thousands) | ||||||||||||||||||||||||||||||||
Utility | Pipeline and Storage |
Exploration and Production |
Energy Marketing |
Total Reportable Segments |
All Other | Corporate and Intersegment Eliminations |
Total Consolidated |
|||||||||||||||||||||||||
Revenue from External Customers |
$ | 146,215 | $ | 29,933 | $ | 130,974 | $ | 71,746 | $ | 378,868 | $ | 1,873 | $ | 238 | $ | 380,979 | ||||||||||||||||
Intersegment Revenues |
$ | 3,475 | $ | 20,324 | $ | ' | $ | 156 | $ | 23,955 | $ | 2,810 | $ | (26,765 | ) | $ | ' | |||||||||||||||
Segment Profit: |
||||||||||||||||||||||||||||||||
Net Income (Loss) |
$ | 6,328 | $ | 4,503 | $ | 32,784 | $ | 1,891 | $ | 45,506 | $ | 2,713 | $ | (1,328 | ) | $ | 46,891 | |||||||||||||||
Nine Months Ended June 30, 2011 (Thousands) | ||||||||||||||||||||||||||||||||
Utility | Pipeline and Storage |
Exploration and Production |
Energy Marketing |
Total Reportable Segments |
All Other | Corporate and Intersegment Eliminations |
Total Consolidated |
|||||||||||||||||||||||||
Revenue from External Customers |
$ | 750,802 | $ | 103,115 | $ | 388,571 | $ | 246,719 | $ | 1,489,207 | $ | 2,895 | $ | 706 | $ | 1,492,808 | ||||||||||||||||
Intersegment Revenues |
$ | 14,680 | $ | 60,838 | $ | ' | $ | 156 | $ | 75,674 | $ | 7,026 | $ | (82,700 | ) | $ | ' | |||||||||||||||
Segment Profit: |
||||||||||||||||||||||||||||||||
Net Income (Loss) |
$ | 62,399 | $ | 24,036 | $ | 93,455 | $ | 9,122 | $ | 189,012 | $ | 34,320 | $ | (2,287 | ) | $ | 221,045 |
Quarter Ended June 30, 2010 (Thousands) | ||||||||||||||||||||||||||||||||
Utility | Pipeline and Storage |
Exploration and Production |
Energy Marketing |
Total Reportable Segments |
All Other | Corporate and Intersegment Eliminations |
Total Consolidated |
|||||||||||||||||||||||||
Revenue from External Customers |
$ | 126,326 | $ | 32,086 | $ | 112,802 | $ | 72,830 | $ | 344,044 | $ | 7,724 | $ | 224 | $ | 351,992 | ||||||||||||||||
Intersegment Revenues |
$ | 2,653 | $ | 19,466 | $ | ' | $ | ' | $ | 22,119 | $ | 1,418 | $ | (23,537 | ) | $ | ' | |||||||||||||||
Segment Profit: |
||||||||||||||||||||||||||||||||
Income (Loss) from Continuing Operations |
$ | 5,969 | $ | 7,234 | $ | 27,883 | $ | 1,411 | $ | 42,497 | $ | 243 | $ | (98 | ) | $ | 42,642 | |||||||||||||||
Nine Months Ended June 30, 2010 (Thousands) | ||||||||||||||||||||||||||||||||
Utility | Pipeline and Storage |
Exploration and Production |
Energy Marketing |
Total Reportable Segments |
All Other | Corporate and Intersegment Eliminations |
Total Consolidated |
|||||||||||||||||||||||||
Revenue from External Customers |
$ | 707,323 | $ | 107,560 | $ | 328,312 | $ | 303,103 | $ | 1,446,298 | $ | 27,157 | $ | 652 | $ | 1,474,107 | ||||||||||||||||
Intersegment Revenues |
$ | 13,315 | $ | 60,289 | $ | ' | $ | ' | $ | 73,604 | $ | 1,418 | $ | (75,022 | ) | $ | ' | |||||||||||||||
Segment Profit: |
||||||||||||||||||||||||||||||||
Income (Loss) from Continuing Operations |
$ | 62,254 | $ | 30,036 | $ | 85,046 | $ | 8,472 | $ | 185,808 | $ | 2,154 | $ | (1,221 | ) | $ | 186,741 |
|
Note 9 – Investments in Unconsolidated Subsidiaries
At June 30, 2011, the Company owns a 50% interest in ESNE. ESNE is an 80-megawatt, combined cycle, natural gas-fired turbine power plant in North East, Pennsylvania that is in the process of being dismantled. The Company expects to recover its investment in ESNE through the sale of ESNE's major assets, such as the power turbines.
During the quarter ended March 31, 2011, the Company sold its 50% equity method investments in Seneca Energy and Model City for $59.4 million, resulting in a gain of $50.9 million. Seneca Energy and Model City generate and sell electricity using methane gas obtained from landfills owned by outside parties.
A summary of the Company's investments in unconsolidated subsidiaries at June 30, 2011 and September 30, 2010 is as follows (in thousands):
|
At June 30, 2011 |
At September 30, 2010 |
|
|
|
Seneca Energy |
$ 0 |
$11,007 |
Model City |
0 |
2,017 |
ESNE |
1,367 |
1,804 |
|
$ 1,367 |
$14,828 |
|
Components of Net Periodic Benefit Cost (in thousands):
Three months ended June 30, |
|
|
|
|
|
|
Retirement Plan |
|
Other Post-Retirement Benefits | ||
|
|
|
|
|
|
|
2011 |
2010 |
|
2011 |
2010 |
|
|
|
|
|
|
Service Cost |
$3,693 |
$3,249 |
|
$1,069 |
$1,075 |
Interest Cost |
10,669 |
11,077 |
|
5471 |
6254 |
Expected Return on Plan Assets |
(14,776) |
(14,585) |
|
(7,291) |
(6,583) |
Amortization of Prior Service Cost |
147 |
164 |
|
(427) |
(427) |
Amortization of Transition Amount |
0 |
0 |
|
135 |
135 |
Amortization of Losses |
8,718 |
5,410 |
|
5,948 |
6,470 |
Net Amortization and Deferral for |
|
|
|
|
|
Regulatory Perposes (Including |
|
|
|
|
|
Volumetric Adjustments)(1) |
(2,346) |
(920) |
|
1,602 |
(569) |
|
|
|
|
|
|
Net Periodic Benefit Cost |
$6,105 |
$4,395 |
|
$6,507 |
$6,355 |
Nine months ended June 30, |
|
|
|
|
|
|
Retirement Plan |
|
Other Post-Retirement Benefits | ||
|
|
|
|
|
|
|
2011 |
2010 |
|
2011 |
2010 |
|
|
|
|
|
|
Service Cost |
$11,079 |
$9,747 |
|
$3,207 |
$3,224 |
Interest Cost |
32,007 |
33,231 |
|
16,413 |
18,763 |
Expected Return on Plan Assets |
(44,328) |
(43,756) |
|
(21,873) |
(19,751) |
Amortization of Prior Service Cost |
441 |
492 |
|
(1,282) |
(1,282) |
Amortization of Transition Amount |
0 |
0 |
|
405 |
405 |
Amortization of Losses |
26,155 |
16,230 |
|
17,845 |
19,411 |
Net Amortization and Deferral for |
|
|
|
|
|
Regulatory Purposes (Including |
|
|
|
|
|
Volumetric Adjustments)(1) |
(584) |
2,896 |
|
9,564 |
2,919 |
|
|
|
|
|
|
Net Periodic Benefit Cost |
$24,770 |
$18,840 |
|
$24,279 |
$23,689 |
(1) The Company's policy is to record retirement plan and other post-retirement benefit costs in the Utility segment on a volumetric basis to reflect the fact that the Utility segment experiences higher throughput of natural gas in the winter months and lower throughput of natural gas in the summer months.
Employer Contributions. During the nine months ended June 30, 2011, the Company contributed $40.0 million to its tax-qualified, noncontributory defined-benefit retirement plan (Retirement Plan) and $18.9 million to its VEBA trusts and 401(h) accounts for its other post-retirement benefits. In the remainder of 2011, the Company expects to contribute between $8.0 and $9.0 million to the Retirement Plan. Changes in the discount rate, other actuarial assumptions, and asset performance could ultimately cause the Company to fund larger amounts to the Retirement Plan in fiscal 2011 in order to be in compliance with the Pension Protection Act of 2006. In the remainder of 2011, the Company expects to contribute between $1.0 and $6.5 million to its VEBA trusts and 401(h) accounts.
|
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 preparation of the consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Reclassification. Certain prior year amounts have been reclassified to conform with current year presentation. This includes the reclassification of accrued capital expenditures of $55.5 million from Accounts Payable to Other Accruals and Current Liabilities on the Consolidated Balance Sheet at September 30, 2010. This reclassification did not impact the Consolidated Statement of Income or the Consolidated Statement of Cash Flows for any of the periods presented.
Earnings for Interim Periods. The Company, in its opinion, has included all adjustments that are necessary for a fair statement of the results of operations for the reported periods. The consolidated financial statements and notes thereto, included herein, should be read in conjunction with the financial statements and notes for the years ended September 30, 2010, 2009 and 2008 that are included in the Company's 2010 Form 10-K. The consolidated financial statements for the year ended September 30, 2011 will be audited by the Company's independent registered public accounting firm after the end of the fiscal year.
The earnings for the nine months ended June 30, 2011 should not be taken as a prediction of earnings for the entire fiscal year ending September 30, 2011. Most of the business of the Utility and Energy Marketing segments is seasonal in nature and is influenced by weather conditions. Due to the seasonal nature of the heating business in the Utility and Energy Marketing segments, earnings during the winter months normally represent a substantial part of the earnings that those segments are expected to achieve for the entire fiscal year. The Company's business segments are discussed more fully in Note 8 ' Business Segment Information.
Consolidated Statement of Cash Flows. For purposes of the Consolidated Statement of Cash Flows, the Company considers all highly liquid debt instruments purchased with a maturity of generally three months or less to be cash equivalents.
At June 30, 2011, the Company accrued $60.7 million of capital expenditures in the Exploration and Production segment, the majority of which was in the Appalachian region. The Company also accrued $5.9 million of capital expenditures in the Pipeline and Storage segment at June 30, 2011. These amounts were excluded from the Consolidated Statement of Cash Flows at June 30, 2011 since they represent non-cash investing activities at that date. Accrued capital expenditures at June 30, 2011 are included in Other Accruals and Current Liabilities on the Consolidated Balance Sheet.
At September 30, 2010, the Company accrued $55.5 million of capital expenditures in the Exploration and Production segment, the majority of which was in the Appalachian region. This amount was excluded from the Consolidated Statement of Cash Flows at September 30, 2010 since it represented a non-cash investing activity at that date. These capital expenditures were paid during the quarter ended December 31, 2010 and have been included in the Consolidated Statement of Cash Flows for the nine months ended June 30, 2011. Accrued capital expenditures at September 30, 2010 are included in Other Accruals and Current Liabilities on the Consolidated Balance Sheet.
At June 30, 2010, the Company accrued $24.3 million of capital expenditures in the Exploration and Production segment, the majority of which was in the Appalachian region. This amount was excluded from the Consolidated Statement of Cash Flows at June 30, 2010 since it represented a non-cash investing activity at that date.
At September 30, 2009, the Company accrued $9.1 million of capital expenditures in the Exploration and Production segment, the majority of which was in the Appalachian region. The Company also accrued $0.7 million of capital expenditures in the All Other category related to the construction of the Midstream Covington Gathering System. These amounts were excluded from the Consolidated Statement of Cash Flows at September 30, 2009 since they represented non-cash investing activities at that date. These capital expenditures were paid during the quarter ended December 31, 2009 and have been included in the Consolidated Statement of Cash Flows for the nine months ended June 30, 2010.
Hedging Collateral Deposits. This is an account title for cash held in margin accounts funded by the Company to serve as collateral for hedging positions. At June 30, 2011, the Company had hedging collateral deposits of $5.6 million related to its exchange-traded futures contracts and $32.4 million related to its over-the-counter crude oil swap agreements. At September 30, 2010, the Company had hedging collateral deposits of $10.1 million related to its exchange-traded futures contracts and $1.0 million related to its over-the-counter crude oil swap agreements. In accordance with its accounting policy, the Company does not offset hedging collateral deposits paid or received against related derivative financial instrument liability or asset balances.
Gas Stored Underground ' Current. In the Utility segment, gas stored underground ' current is carried at lower of cost or market, on a LIFO method. Gas stored underground ' current normally declines during the first and second quarters of the year and is replenished during the third and fourth quarters. In the Utility segment, the current cost of replacing gas withdrawn from storage is recorded in the Consolidated Statements of Income and a reserve for gas replacement is recorded in the Consolidated Balance Sheets under the caption 'Other Accruals and Current Liabilities.' Such reserve, which amounted to $45.0 million at June 30, 2011, is reduced to zero by September 30 of each year as the inventory is replenished.
Property, Plant and Equipment. 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. Such costs amounted to $193.9 million and $151.2 million at June 30, 2011 and September 30, 2010, respectively. All costs related to unproved properties are reviewed quarterly to determine if impairment has occurred. The amount of any impairment is transferred to the pool of capitalized costs being amortized.
In March 2011, the Company entered into a purchase and sale agreement to sell its off-shore oil and natural gas properties effective as of January 1, 2011 in the Gulf of Mexico for approximately $70 million and received a deposit of $7.0 million from the purchaser. The Company completed the sale in April 2011, receiving an additional $54.8 million. The difference between the total proceeds received of $61.8 million and the sale price of $70.0 million represents a purchase price adjustment for the operating cash flow that the Company recorded from January 1, 2011 to the closing date of the sale. Under the full cost method of accounting for oil and natural gas properties, the sale proceeds were accounted for as a reduction of capitalized costs in April 2011. 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.
Capitalized costs are subject to the SEC full cost ceiling test. The ceiling test, which is performed each quarter, determines a limit, or ceiling, on the amount of property acquisition, exploration and development costs that can be capitalized. The ceiling under this test represents (a) the present value of estimated future net cash flows, excluding future cash outflows associated with settling asset retirement obligations that have been accrued on the balance sheet, using a discount factor of 10%, which is computed by applying prices of oil and gas (as adjusted for hedging) to estimated future production of proved oil and gas reserves as of the date of the latest balance sheet, less estimated future expenditures, plus (b) the cost of unevaluated properties not being depleted, less (c) income tax effects related to the differences between the book and tax basis of the properties. In accordance with the SEC final rule on Modernization of Oil and Gas Reporting, the natural gas and oil prices used to calculate the full cost ceiling (as of June 30, 2011) are based on an unweighted arithmetic average of the first day of the month oil and gas prices for each month within the twelve-month period prior to the end of the reporting period. If capitalized costs, net of accumulated depreciation, depletion and amortization and related deferred income taxes, exceed the ceiling at the end of any quarter, a permanent impairment is required to be charged to earnings in that quarter. At June 30, 2011, the Company's capitalized costs were below the full cost ceiling for the Company's oil and gas properties. As a result, an impairment charge was not required at June 30, 2011.
Accumulated Other Comprehensive Loss. The components of Accumulated Other Comprehensive Loss, net of related tax effect, are as follows (in thousands):
At June 30, 2011 | At September 30, 2010 | |||||||
Funded Status of the Pension and Other Post-Retirement Benefit Plans |
$ | (79,465 | ) | $ | (79,465 | ) | ||
Cumulative Foreign Currency Translation Adjustment |
' | (51 | ) | |||||
Net Unrealized Gain on Derivative Financial Instruments |
557 | 32,876 | ||||||
Net Unrealized Gain on Securities Available for Sale |
3,810 | 1,655 | ||||||
|
|
|
|
|||||
Accumulated Other Comprehensive Loss |
$ | (75,098 | ) | $ | (44,985 | ) | ||
|
|
|
|
Other Current Assets. The components of the Company's Other Current Assets are as follows (in thousands):
At June 30, 2011 | At September 30, 2010 | |||||||
Prepayments |
$ | 12,645 | $ | 13,884 | ||||
Prepaid Property and Other Taxes |
10,653 | 12,413 | ||||||
Federal Income Taxes Receivable |
9,514 | 56,334 | ||||||
State Income Taxes Receivable |
7,902 | 18,007 | ||||||
Fair Values of Firm Commitments |
4,072 | 15,331 | ||||||
|
|
|
|
|||||
$ | 44,786 | $ | 115,969 | |||||
|
|
|
|
Earnings Per Common Share. Basic earnings per common share is computed by dividing net income available for common stock by the weighted average number of common shares outstanding for the period. Diluted earnings per common share reflects the potential dilution that could occur if securities or other contracts to issue common stock were exercised or converted into common stock. For purposes of determining earnings per common share, the only potentially dilutive securities the Company has outstanding are stock options, SARs and restricted stock units. The diluted weighted average shares outstanding shown on the Consolidated Statements of Income reflects the potential dilution as a result of these securities as determined using the Treasury Stock Method. Stock options, SARs and restricted stock units that are antidilutive are excluded from the calculation of diluted earnings per common share. There were 6,512 antidilutive securities for the quarter ended June 30, 2011. There were no antidilutive securities for the nine months ended June 30, 2011. There were 544,500 and 237,538 antidilutive securities for the quarter and nine months ended June 30, 2010, respectively.
Stock-Based Compensation. During the nine months ended June 30, 2011, the Company granted 180,000 non-performance based SARs having a weighted average exercise price of $63.87 per share. The weighted average grant date fair value of these SARs was $15.33 per share. These SARs may be settled in cash, in shares of common stock of the Company, or in a combination of cash and shares of common stock of the Company, as determined by the Company. These SARs are considered equity awards under the current authoritative guidance for stock-based compensation. The accounting for those SARs is the same as the accounting for stock options. There were no SARs granted during the quarter ended June 30, 2011. The non-performance based SARs granted during the nine months ended June 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 nine months ended June 30, 2011 was estimated on the date of grant using the same accounting treatment that is applied for stock options.
There were no stock options granted during the quarter or nine months ended June 30, 2011. The Company did not recognize a tax benefit related to the exercise of stock options for the calendar year ended December 31, 2010 due to tax loss carryforwards. The Company expects to recognize a tax benefit of $18.1 million in Paid in Capital related to calendar 2010 stock option exercises in future years as the tax loss carryforward is utilized.
The Company granted 47,250 restricted share awards (non-vested stock as defined by the current accounting literature) during the nine months ended June 30, 2011. The weighted average fair value of such restricted shares was $63.98 per share. There were no restricted share awards granted during the quarter ended June 30, 2011. In addition, the Company granted 8,100 and 37,000 restricted stock units during the quarter and nine months ended June 30, 2011, respectively. The weighted average fair value of such restricted stock units was $65.50 per share and $59.82 per share for the quarter and nine months ended June 30, 2011, respectively. Restricted stock units represent the right to receive shares of common stock of the Company (or the equivalent value in cash or a combination of cash and shares of common stock of the Company, as determined by the Company) at the end of a specified time period. These restricted stock units do not entitle the participant to receive dividends during the vesting period. The accounting for these restricted stock units is the same as the accounting for restricted share awards, except that the fair value at the date of grant of the restricted stock units must be reduced by the present value of forgone dividends over the vesting term of the award.
New Authoritative Accounting and Financial Reporting Guidance.In May 2011, the FASB issued authoritative guidance regarding fair value measurement as a joint project with the IASB. The objective of the guidance was to bring together as closely as possible the fair value measurement and disclosure guidance issued by the two boards. The guidance includes a few updates to measurement guidance and some enhanced disclosure requirements. For all Level 3 fair value measurements, the guidance requires quantitative information about significant unobservable inputs used and a description of the valuation processes in place. The guidance also requires a qualitative discussion about the sensitivity of recurring Level 3 fair value measurements and information about any transfers between Level 1 and Level 2 of the fair value hierarchy. The new guidance also contains a requirement that all fair value measurements, whether they are recorded on the balance sheet or disclosed in the footnotes, be classified as Level 1, Level 2 or Level 3 within the fair value hierarchy. This authoritative guidance will be effective as of the Company's second quarter of fiscal 2012. The Company is currently evaluating the impact that adoption of this authoritative guidance will have on its consolidated financial statement disclosures.
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 to the Company's financial statements.
|
At June 30, 2011 | At September 30, 2010 | |||||||
Funded Status of the Pension and Other Post-Retirement Benefit Plans |
$ | (79,465 | ) | $ | (79,465 | ) | ||
Cumulative Foreign Currency Translation Adjustment |
' | (51 | ) | |||||
Net Unrealized Gain on Derivative Financial Instruments |
557 | 32,876 | ||||||
Net Unrealized Gain on Securities Available for Sale |
3,810 | 1,655 | ||||||
|
|
|
|
|||||
Accumulated Other Comprehensive Loss |
$ | (75,098 | ) | $ | (44,985 | ) | ||
|
|
|
|
At June 30, 2011 | At September 30, 2010 | |||||||
Prepayments |
$ | 12,645 | $ | 13,884 | ||||
Prepaid Property and Other Taxes |
10,653 | 12,413 | ||||||
Federal Income Taxes Receivable |
9,514 | 56,334 | ||||||
State Income Taxes Receivable |
7,902 | 18,007 | ||||||
Fair Values of Firm Commitments |
4,072 | 15,331 | ||||||
|
|
|
|
|||||
$ | 44,786 | $ | 115,969 | |||||
|
|
|
|
|
Recurring Fair Value Measures | At fair value as of June 30, 2011 | |||||||||||||||
(Thousands of Dollars) |
Level 1 | Level 2 | Level 3 | Total | ||||||||||||
Assets: |
||||||||||||||||
Cash Equivalents ' Money Market Mutual Funds |
$ | 118,652 | $ | ' | $ | ' | $ | 118,652 | ||||||||
Derivative Financial Instruments: |
||||||||||||||||
Commodity Futures Contracts ' Gas |
56 | ' | ' | 56 | ||||||||||||
Over the Counter Swaps ' Oil |
' | (176 | ) | ' | (176 | ) | ||||||||||
Over the Counter Swaps ' Gas |
' | 43,367 | ' | 43,367 | ||||||||||||
Other Investments: |
||||||||||||||||
Balanced Equity Mutual Fund |
22,030 | ' | ' | 22,030 | ||||||||||||
Common Stock ' Financial Services Industry |
6,979 | ' | ' | 6,979 | ||||||||||||
Other Common Stock |
237 | ' | ' | 237 | ||||||||||||
Hedging Collateral Deposits |
37,984 | ' | ' | 37,984 | ||||||||||||
|
|
|
|
|
|
|
|
|||||||||
Total |
$ | 185,938 | $ | 43,191 | $ | ' | $ | 229,129 | ||||||||
|
|
|
|
|
|
|
|
|||||||||
Liabilities: |
||||||||||||||||
Derivative Financial Instruments: |
||||||||||||||||
Commodity Futures Contracts ' Gas |
$ | 2,960 | $ | ' | $ | ' | $ | 2,960 | ||||||||
Over the Counter Swaps ' Oil |
' | ' | 50,453 | 50,453 | ||||||||||||
Over the Counter Swaps ' Gas |
' | (8,806 | ) | ' | (8,806 | ) | ||||||||||
|
|
|
|
|
|
|
|
|||||||||
Total |
$ | 2,960 | $ | (8,806 | ) | $ | 50,453 | $ | 44,607 | |||||||
|
|
|
|
|
|
|
|
|||||||||
Total Net Assets/(Liabilities) |
$ | 182,978 | $ | 51,997 | $ | (50,453 | ) | $ | 184,522 | |||||||
|
|
|
|
|
|
|
|
Recurring Fair Value Measures | At fair value as of September 30, 2010 | |||||||||||||||
(Thousands of Dollars) |
Level 1 | Level 2 | Level 3 | Total | ||||||||||||
Assets: |
||||||||||||||||
Cash Equivalents ' Money Market Mutual Funds |
$ | 277,423 | $ | ' | $ | ' | $ | 277,423 | ||||||||
Derivative Financial Instruments: |
||||||||||||||||
Over the Counter Swaps ' Gas |
' | 67,387 | ' | 67,387 | ||||||||||||
Over the Counter Swaps ' Oil |
' | ' | (2,203 | ) | (2,203 | ) | ||||||||||
Other Investments: |
||||||||||||||||
Balanced Equity Mutual Fund |
17,256 | ' | ' | 17,256 | ||||||||||||
Common Stock ' Financial Services Industry |
4,991 | ' | ' | 4,991 | ||||||||||||
Other Common Stock |
241 | ' | ' | 241 | ||||||||||||
Hedging Collateral Deposits |
11,134 | ' | ' | 11,134 | ||||||||||||
|
|
|
|
|
|
|
|
|||||||||
Total |
$ | 311,045 | $ | 67,387 | $ | (2,203 | ) | $ | 376,229 | |||||||
|
|
|
|
|
|
|
|
|||||||||
Liabilities: |
||||||||||||||||
Derivative Financial Instruments: |
||||||||||||||||
Commodity Futures Contracts ' Gas |
$ | 5,840 | $ | ' | $ | ' | $ | 5,840 | ||||||||
Over the Counter Swaps ' Oil |
' | ' | 14,280 | 14,280 | ||||||||||||
Over the Counter Swaps ' Gas |
' | 40 | ' | 40 | ||||||||||||
|
|
|
|
|
|
|
|
|||||||||
Total |
$ | 5,840 | $ | 40 | $ | 14,280 | $ | 20,160 | ||||||||
|
|
|
|
|
|
|
|
|||||||||
Total Net Assets/(Liabilities) |
$ | 305,205 | $ | 67,347 | $ | (16,483 | ) | $ | 356,069 | |||||||
|
|
|
|
|
|
|
|
Fair Value Measurements Using Unobservable Inputs (Level 3) | ||||||||||||||||||||
(Thousands of Dollars) |
Total Gains/Losses | |||||||||||||||||||
April 1, 2011 |
Gains/Losses Realized and Included in Earnings |
Gains/Losses Unrealized and Included in Other Comprehensive Income (Loss) |
Transfer In/Out of Level 3 |
June 30, 2011 |
||||||||||||||||
Derivative Financial Instruments(2) |
$ | (71,913 | ) | $ | 15,377 | (1) | $ | 6,083 | $ | ' | $ | (50,453 | ) |
(1) |
Amounts are reported in Operating Revenues in the Consolidated Statement of Income for the three months ended June 30, 2011. |
(2) |
Derivative Financial Instruments are shown on a net basis. |
Fair Value Measurements Using Unobservable Inputs (Level 3) | ||||||||||||||||||||
(Thousands of Dollars) |
Total Gains/Losses | |||||||||||||||||||
October 1, 2010 |
Gains/Losses Realized and Included in Earnings |
Gains/Losses Unrealized and Included in Other Comprehensive Income (Loss) |
Transfer In/Out of Level 3 |
June 30, 2011 |
||||||||||||||||
Derivative Financial Instruments(2) |
$ | (16,483 | ) | $ | 28,545 | (1) | $ | (62,515 | ) | $ | ' | $ | (50,453 | ) |
(1) |
Amounts are reported in Operating Revenues in the Consolidated Statement of Income for the nine months ended June 30, 2011. |
(2) |
Derivative Financial Instruments are shown on a net basis. |
Fair Value Measurements Using Unobservable Inputs (Level 3) | ||||||||||||||||||||
(Thousands of Dollars) |
Total Gains/Losses | |||||||||||||||||||
April 1, 2010 |
Gains/Losses Realized and Included in Earnings |
Gains/Losses Unrealized and Included in Other Comprehensive Income (Loss) |
Transfer In/Out of Level 3 |
June 30, 2010 |
||||||||||||||||
Derivative Financial Instruments(2) |
$ | (14,100 | ) | $ | (2,172 | )(1) | $ | 16,126 | $ | ' | $ | (146 | ) |
(1) |
Amounts are reported in Operating Revenues in the Consolidated Statement of Income for the three months ended June 30, 2010. |
(2) |
Derivative Financial Instruments are shown on a net basis. |
Fair Value Measurements Using Unobservable Inputs (Level 3) | ||||||||||||||||||||
(Thousands of Dollars) |
Total Gains/Losses | |||||||||||||||||||
October 1, 2010 |
Gains/Losses Realized and Included in Earnings |
Gains/Losses Unrealized and Included in Other Comprehensive Income (Loss) |
Transfer In/Out of Level 3 |
June 30, 2010 |
||||||||||||||||
Derivative Financial Instruments(2) |
$ | 26,969 | $ | (6,969 | )(1) | $ | (20,146 | ) | $ | ' | $ | (146 | ) |
(1) |
Amounts are reported in Operating Revenues in the Consolidated Statement of Income for the nine months ended June 30, 2010. |
(2) |
Derivative Financial Instruments are shown on a net basis. |
|
June 30, 2011 | September 30, 2010 | |||||||||||||||
Carrying Amount |
Fair Value | Carrying Amount |
Fair Value | |||||||||||||
Long-Term Debt |
$ | 1,049,000 | $ | 1,209,054 | $ | 1,249,000 | $ | 1,423,349 |
Fair Values of Derivative Instruments | ||||||||
(Dollar Amounts in Thousands) | ||||||||
Asset Derivatives |
Liability Derivatives | |||||||
Derivatives Designated as Hedging Instruments |
Consolidated Balance Sheet Location |
Fair Value |
Consolidated Balance Sheet Location |
Fair Value | ||||
Commodity Contracts ' at June 30, 2011 |
Fair Value of Derivative Financial Instruments |
$43,247 | Fair Value of Derivative Financial Instruments |
$44,607 | ||||
Commodity Contracts ' at September 30, 2010 |
Fair Value of Derivative |
$65,184 | Fair Value of Derivative Financial Instruments |
$20,160 |
Fair Values of Derivative Instruments | ||||
(Dollar Amounts in Thousands) | ||||
Derivatives Designated as Hedging Instruments |
Gross Asset Derivatives |
Gross Liability Derivatives | ||
Fair Value |
Fair Value | |||
Commodity Contracts ' at |
$54,971 | $56,331 | ||
Commodity Contracts ' at |
$77,837 | $32,813 |
The Effect of Derivative Financial Instruments on the Statement of Financial Performance for the Three Months Ended June 30, 2011 and 2010 (Thousands of Dollars) |
||||||||||||||||||||||||||||
Derivatives in Cash Flow Hedging Relationships |
Amount of Derivative Gain or (Loss) Recognized in Other Comprehensive Income (Loss) on the Consolidated Statement of Comprehensive Income (Loss) (Effective Portion) for the Three Months Ended June 30, |
Location of Derivative Gain or (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) on the Consolidated Balance Sheet into the Consolidated Statement of Income (Effective Portion) |
Amount of Derivative Gain or (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) on the Consolidated Balance Sheet into the Consolidated Statement of Income (Effective Portion) for the Three Months Ended June 30, |
Location of Derivative Gain or (Loss) Recognized in the Consolidated Statement of Income (Ineffective Portion and Amount Excluded from Effectiveness Testing) |
Derivative Gain or (Loss) Recognized in the Consolidated Statement of Income (Ineffective Portion and Amount Excluded from Effectiveness Testing) for the Three Months Ended June 30, |
|||||||||||||||||||||||
2011 | 2010 | 2011 | 2010 | 2011 | 2010 | |||||||||||||||||||||||
Commodity Contracts ' Exploration & Production segment |
$ | 25,399 | $ | 16,445 | Operating Revenue |
$ | (5,548 | ) | $ | 11,592 | Operating Revenue |
$ | 570 | $ | ' | |||||||||||||
Commodity Contracts ' Energy Marketing segment |
$ | 737 | $ | 519 | Purchased Gas |
$ | 1,793 | $ | 238 | Purchased Gas | $ | ' | $ | ' | ||||||||||||||
Commodity Contracts ' Pipeline & Storage segment |
$ | 242 | $ | (436 | ) | Operating Revenue |
$ | ' | $ | ' | Operating Revenue |
$ | ' | $ | ' | |||||||||||||
Total | $ | 26,378 | $ | 16,528 | $ | (3,755 | ) | $ | 11,830 | $ | 570 | $ | ' |
The Effect of Derivative Financial Instruments on the Statement of Financial Performance for the Nine Months Ended June 30, 2011 and 2010 (Thousands of Dollars) |
||||||||||||||||||||||||||||
Derivatives in Cash Flow Hedging Relationships |
Amount of Derivative Gain or (Loss) Recognized in Other Comprehensive Income (Loss) on the Consolidated Statement of Comprehensive Income (Loss) (Effective Portion) for the Nine Months Ended June 30, |
Location of Derivative Gain or (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) on the Consolidated Balance Sheet into the Consolidated Statement of Income (Effective Portion) |
Amount of Derivative Gain or (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) on the Consolidated Balance Sheet into the Consolidated Statement of Income (Effective Portion) for the Nine Months Ended June 30, |
Location of Derivative Gain or (Loss) Recognized in the Consolidated Statement of Income (Ineffective Portion and Amount Excluded from Effectiveness Testing) |
Derivative Gain or (Loss) Recognized in the Consolidated Statement of Income (Ineffective Portion and Amount Excluded from Effectiveness Testing) for the Nine Months Ended June 30, |
|||||||||||||||||||||||
2011 | 2010 | 2011 | 2010 | 2011 | 2010 | |||||||||||||||||||||||
Commodity Contracts ' Exploration & Production segment |
$ | (42,969 | ) | $ | 32,910 | Operating Revenue |
$ | 5,415 | $ | 29,170 | Operating Revenue |
$ | 570 | $ | ' | |||||||||||||
Commodity Contracts ' Energy Marketing segment |
$ | 1,340 | $ | 5,821 | Purchased Gas | $ | 7,095 | $ | (209 | ) | Purchased Gas | $ | ' | $ | ' | |||||||||||||
Commodity Contracts ' Pipeline & Storage segment |
$ | 27 | $ | 577 | Operating Revenue |
$ | ' | $ | 511 | Operating Revenue |
$ | ' | $ | ' | ||||||||||||||
Total | $ | (41,602 | ) | $ | 39,308 | $ | 12,510 | $ | 29,472 | $ | 570 | $ | ' |
Derivatives in Fair Value Hedging Relationships |
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 Nine Months Ended June 30, 2011 (In Thousands) |
||||
Commodity Contracts ' Energy |
Operating Revenues | $ | 9,531 | |||
Commodity Contracts ' Energy |
Purchased Gas | $ | (638 | ) | ||
Commodity Contracts ' Energy |
Purchased Gas | $ | (303 | ) | ||
|
|
|||||
$ | 8,590 | |||||
|
|
(1) |
Represents hedging of fixed price sales commitments of natural gas. |
(2) |
Represents hedging of fixed price purchase commitments of natural gas. |
(3) |
Represents hedging of natural gas held in storage. |
Consolidated Statement of Income |
Gain/(Loss) on Derivative | Gain/(Loss) on Commitment | ||||||
Operating Revenues |
$ | 9,531,151 | $ | (9,531,151 | ) | |||
Purchased Gas |
$ | (941,391 | ) | $ | 941,391 |
|
Nine Months Ended | ||||||||
June 30, | ||||||||
2011 | 2010 | |||||||
Current Income Taxes |
||||||||
Federal |
$ | (1,825 | ) | $ | 42,323 | |||
State |
2,703 | 9,914 | ||||||
Deferred Income Taxes |
||||||||
Federal |
112,385 | 50,079 | ||||||
State |
27,941 | 13,734 | ||||||
|
|
|
|
|||||
141,204 | 116,050 | |||||||
Deferred Investment Tax Credit |
(523 | ) | (523 | ) | ||||
|
|
|
|
|||||
Total Income Taxes |
$ | 140,681 | $ | 115,527 | ||||
|
|
|
|
|||||
Presented as Follows: |
||||||||
Other Income |
$ | (523 | ) | $ | (523 | ) | ||
Income Tax Expense ' Continuing Operations |
141,204 | 115,449 | ||||||
Income from Discontinued Operations |
' | 601 | ||||||
|
|
|
|
|||||
Total Income Taxes |
$ | 140,681 | $ | 115,527 | ||||
|
|
|
|
Nine Months Ended | ||||||||
June 30, | ||||||||
2011 | 2010 | |||||||
U.S. Income Before Income Taxes |
$ | 361,726 | $ | 303,039 | ||||
|
|
|
|
|||||
Income Tax Expense, Computed at Federal Statutory Rate of 35% |
$ | 126,604 | $ | 106,064 | ||||
Increase (Reduction) in Taxes Resulting from: |
||||||||
State Income Taxes |
19,919 | 15,371 | ||||||
Miscellaneous |
(5,842 | ) | (5,908 | ) | ||||
|
|
|
|
|||||
Total Income Taxes |
$ | 140,681 | $ | 115,527 | ||||
|
|
|
|
At June 30, 2011 | At September 30, 2010 | |||||||
Deferred Tax Liabilities: |
||||||||
Property, Plant and Equipment |
$ | 1,035,695 | $ | 849,869 | ||||
Pension and Other Post-Retirement Benefit Costs |
183,651 | 177,853 | ||||||
Other |
38,958 | 63,671 | ||||||
|
|
|
|
|||||
Total Deferred Tax Liabilities |
1,258,304 | 1,091,393 | ||||||
|
|
|
|
|||||
Deferred Tax Assets: |
||||||||
Pension and Other Post-Retirement Benefit Costs |
(227,458 | ) | (223,588 | ) | ||||
Tax Loss Carryforwards |
(54,472 | ) | (9,772 | ) | ||||
Other |
(80,114 | ) | (81,751 | ) | ||||
|
|
|
|
|||||
Total Deferred Tax Assets |
(362,044 | ) | (315,111 | ) | ||||
|
|
|
|
|||||
Total Net Deferred Income Taxes |
$ | 896,260 | $ | 776,282 | ||||
|
|
|
|
|||||
Presented as Follows: |
||||||||
Net Deferred Tax Liability/(Asset) ' Current |
$ | (22,885 | ) | $ | (24,476 | ) | ||
Net Deferred Tax Liability ' Non-Current |
919,145 | 800,758 | ||||||
|
|
|
|
|||||
Total Net Deferred Income Taxes |
$ | 896,260 | $ | 776,282 | ||||
|
|
|
|
|
|
Three Months Ended |
|
Nine Months Ended |
|
June 30, |
|
June 30, |
(Thousands) |
2010 |
|
2010 |
|
|
|
|
Operating Revenues |
$2,135 |
|
$8,411 |
Operating Expenses |
2,177 |
|
7,021 |
Operating Income (Loss) |
(42) |
|
1,390 |
Interest Income |
1 |
|
1 |
Other Interest Expense |
(8) |
|
(19) |
Income (Loss) before Income Taxes |
(49) |
|
1,372 |
Income Tax Expense |
8 |
|
601 |
Income (Loss) from Discontinued Operations |
$(57) |
|
$771 |
|
Quarter Ended June 30, 2011 (Thousands) | ||||||||||||||||||||||||||||||||
Utility | Pipeline and Storage |
Exploration and Production |
Energy Marketing |
Total Reportable Segments |
All Other | Corporate and Intersegment Eliminations |
Total Consolidated |
|||||||||||||||||||||||||
Revenue from External Customers |
$ | 146,215 | $ | 29,933 | $ | 130,974 | $ | 71,746 | $ | 378,868 | $ | 1,873 | $ | 238 | $ | 380,979 | ||||||||||||||||
Intersegment Revenues |
$ | 3,475 | $ | 20,324 | $ | ' | $ | 156 | $ | 23,955 | $ | 2,810 | $ | (26,765 | ) | $ | ' | |||||||||||||||
Segment Profit: |
||||||||||||||||||||||||||||||||
Net Income (Loss) |
$ | 6,328 | $ | 4,503 | $ | 32,784 | $ | 1,891 | $ | 45,506 | $ | 2,713 | $ | (1,328 | ) | $ | 46,891 | |||||||||||||||
Nine Months Ended June 30, 2011 (Thousands) | ||||||||||||||||||||||||||||||||
Utility | Pipeline and Storage |
Exploration and Production |
Energy Marketing |
Total Reportable Segments |
All Other | Corporate and Intersegment Eliminations |
Total Consolidated |
|||||||||||||||||||||||||
Revenue from External Customers |
$ | 750,802 | $ | 103,115 | $ | 388,571 | $ | 246,719 | $ | 1,489,207 | $ | 2,895 | $ | 706 | $ | 1,492,808 | ||||||||||||||||
Intersegment Revenues |
$ | 14,680 | $ | 60,838 | $ | ' | $ | 156 | $ | 75,674 | $ | 7,026 | $ | (82,700 | ) | $ | ' | |||||||||||||||
Segment Profit: |
||||||||||||||||||||||||||||||||
Net Income (Loss) |
$ | 62,399 | $ | 24,036 | $ | 93,455 | $ | 9,122 | $ | 189,012 | $ | 34,320 | $ | (2,287 | ) | $ | 221,045 | |||||||||||||||
Quarter Ended June 30, 2010 (Thousands) | ||||||||||||||||||||||||||||||||
Utility | Pipeline and Storage |
Exploration and Production |
Energy Marketing |
Total Reportable Segments |
All Other | Corporate and Intersegment Eliminations |
Total Consolidated |
|||||||||||||||||||||||||
Revenue from External Customers |
$ | 126,326 | $ | 32,086 | $ | 112,802 | $ | 72,830 | $ | 344,044 | $ | 7,724 | $ | 224 | $ | 351,992 | ||||||||||||||||
Intersegment Revenues |
$ | 2,653 | $ | 19,466 | $ | ' | $ | ' | $ | 22,119 | $ | 1,418 | $ | (23,537 | ) | $ | ' | |||||||||||||||
Segment Profit: |
||||||||||||||||||||||||||||||||
Income (Loss) from Continuing Operations |
$ | 5,969 | $ | 7,234 | $ | 27,883 | $ | 1,411 | $ | 42,497 | $ | 243 | $ | (98 | ) | $ | 42,642 | |||||||||||||||
Nine Months Ended June 30, 2010 (Thousands) | ||||||||||||||||||||||||||||||||
Utility | Pipeline and Storage |
Exploration and Production |
Energy Marketing |
Total Reportable Segments |
All Other | Corporate and Intersegment Eliminations |
Total Consolidated |
|||||||||||||||||||||||||
Revenue from External Customers |
$ | 707,323 | $ | 107,560 | $ | 328,312 | $ | 303,103 | $ | 1,446,298 | $ | 27,157 | $ | 652 | $ | 1,474,107 | ||||||||||||||||
Intersegment Revenues |
$ | 13,315 | $ | 60,289 | $ | ' | $ | ' | $ | 73,604 | $ | 1,418 | $ | (75,022 | ) | $ | ' | |||||||||||||||
Segment Profit: |
||||||||||||||||||||||||||||||||
Income (Loss) from Continuing Operations |
$ | 62,254 | $ | 30,036 | $ | 85,046 | $ | 8,472 | $ | 185,808 | $ | 2,154 | $ | (1,221 | ) | $ | 186,741 |
|
|
At June 30, 2011 |
At September 30, 2010 |
|
|
|
Seneca Energy |
$ 0 |
$11,007 |
Model City |
0 |
2,017 |
ESNE |
1,367 |
1,804 |
|
$ 1,367 |
$14,828 |
|
Three months ended June 30,
Retirement Plan | Other Post-Retirement Benefits | |||||||||||
2011 | 2010 | 2011 | 2010 | |||||||||
Service Cost | $ | 3,693 | $ | 3,249 | $ | 1,069 | $ | 1,075 | ||||
Interest Cost | 10,669 | 11,077 | 5,471 | 6,254 | ||||||||
Expected Return on Plan Assets | (14,776 | ) | (14,585 | ) | (7,291 | ) | (6,583 | ) | ||||
Amortization of Prior Service Cost | 147 | 164 | (427 | ) | (427 | ) | ||||||
Amortization of Transition Amount | 0 | 0 | 135 | 135 | ||||||||
Amortization of Losses | 8,718 | 5,410 | 5,948 | 6,470 | ||||||||
Net Amortization and Deferral for | ||||||||||||
Regulatory Purposes (Including | ||||||||||||
Volumetric Adjustments) (1) | (2,346 | ) | (920 | ) | 1,602 | (569 | ) | |||||
Net Periodic Benefit Cost | $ | 6,105 | $ | 4,395 | $ | 6,507 | $ | 6,355 |
Nine months ended June 30, | ||||||||||||
Retirement Plan | Other Post-Retirement Benefits | |||||||||||
2011 | 2010 | 2011 | 2010 | |||||||||
Service Cost | $ | 11,079 | $ | 9,747 | $ | 3,207 | $ | 3,224 | ||||
Interest Cost | 32,007 | 33,231 | 16,413 | 18,763 | ||||||||
Expected Return on Plan Assets | (44,328 | ) | (43,756 | ) | (21,873 | ) | (19,751 | ) | ||||
Amortization of Prior Service Cost | 441 | 492 | (1,282 | ) | (1,282 | ) | ||||||
Amortization of Transition Amount | 0 | 0 | 405 | 405 | ||||||||
Amortization of Losses | 26,155 | 16,230 | 17,845 | 19,411 | ||||||||
Net Amortization and Deferral for | ||||||||||||
Regulatory Purposes (Including | ||||||||||||
Volumetric Adjustments) (1) | (584 | ) | 2,896 | 9,564 | 2,919 | |||||||
Net Periodic Benefit Cost | $ | 24,770 | $ | 18,840 | $ | 24,279 | $ | 23,689 |
(1) | The Company's policy is to record retirement plan and other post-retirement benefit costs in the Utility segment on a volumetric basis to reflect the fact that the Utility segment experiences higher throughput of natural gas in the winter months and lower throughput of natural gas in the summer months. |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
|