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Principles of Consolidation. The Company consolidates its majority owned entities. The equity method is used to account for minority owned entities. All significant intercompany balances and transactions are eliminated.
The preparation of the consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Reclassification. Certain prior year amounts have been reclassified to conform with current year presentation.
Earnings for Interim Periods. The Company, in its opinion, has included all adjustments that are necessary for a fair statement of the results of operations for the reported periods. The consolidated financial statements and notes thereto, included herein, should be read in conjunction with the financial statements and notes for the years ended September 30, 2009, 2008 and 2007 that are included in the Company's 2009 Form 10-K. The consolidated financial statements for the year ended September 30, 2010 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, 2010 should not be taken as a prediction of earnings for the entire fiscal year ending September 30, 2010. Most of the business of the Utility and Energy Marketing segments is seasonal in nature and is influenced by weather conditions. Due to the seasonal nature of the heating business in the Utility and Energy Marketing segments, earnings during the winter months normally represent a substantial part of the earnings that those segments are expected to achieve for the entire fiscal year. The Company's business segments are discussed more fully in Note 7 – Business Segment Information.
Consolidated Statement of Cash Flows. For purposes of the Consolidated Statement of Cash Flows, the Company considers all highly liquid debt instruments purchased with a maturity of generally three months or less to be cash equivalents.
At June 30, 2010, the Company accrued $24.3 million of capital expenditures in the Exploration and Production segment, the majority of which was in the Appalachian region. This amount was excluded from the Consolidated Statement of Cash Flows at June 30, 2010 since it represented a non-cash investing activity at that date.
At September 30, 2009, the Company accrued $9.1 million of capital expenditures in the Exploration and Production segment, the majority of which was in the Appalachian region. The Company also accrued $0.7 million of capital expenditures in the All Other category related to the construction of the Midstream Covington Gathering System. These amounts were excluded from the Consolidated Statement of Cash Flows at September 30, 2009 since they represented non-cash investing activities at that date. These capital expenditures were paid during the quarter ended December 31, 2009 and have been included in the Consolidated Statement of Cash Flows for the nine months ended June 30, 2010.
At June 30, 2009, the Company accrued $9.4 million of capital expenditures in the Exploration and Production segment, the majority of which was in the Appalachian region. This amount was excluded from the Consolidated Statement of Cash Flows at June 30, 2009 since it represents a non-cash investing activity at that date.
At September 30, 2008, the Company accrued $16.8 million of capital expenditures related to the construction of the Empire Connector project. This amount was excluded from the Consolidated Statement of Cash Flows at September 30, 2008 since it represented a non-cash investing activity at that date. These capital expenditures were paid during the quarter ended December 31, 2008 and have been included in the Consolidated Statement of Cash Flows for the nine months ended June 30, 2009.
Hedging Collateral Deposits. This is an account title for cash held in margin accounts funded by the Company to serve as collateral for hedging positions. At June 30, 2010, the Company had hedging collateral deposits of $6.4 million related to its exchange-traded futures contracts and $1.8 million related to its over-the-counter crude oil swap agreements. In accordance with its accounting policy, the Company does not offset hedging collateral deposits paid or received against related derivative financial instrument liability or asset balances.
Cash Held in Escrow. On July 20, 2009, the Company's wholly-owned subsidiary in the Exploration and Production segment, Seneca, acquired Ivanhoe Energy's United States oil and gas operations for approximately $39.2 million in cash (including cash acquired of $4.3 million). The cash acquired at acquisition includes $2 million held in escrow at June 30, 2010 and September 30, 2009. Seneca placed this amount in escrow as part of the purchase price. Currently, the Company and Ivanhoe Energy are negotiating a final resolution to the issue of whether Ivanhoe Energy is entitled to some or all of the amount held in escrow.
Gas Stored Underground - Current. In the Utility segment, gas stored underground – current is carried at lower of cost or market, on a LIFO method. Gas stored underground – current normally declines during the first and second quarters of the year and is replenished during the third and fourth quarters. In the Utility segment, the current cost of replacing gas withdrawn from storage is recorded in the Consolidated Statements of Income and a reserve for gas replacement is recorded in the Consolidated Balance Sheets under the caption "Other Accruals and Current Liabilities." Such reserve, which amounted to $44.6 million at June 30, 2010, is reduced to zero by September 30 of each year as the inventory is replenished.
Property, Plant and Equipment. In the 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 $192.0 million at June 30, 2010. All costs related to unproved properties are reviewed quarterly to determine if impairment has occurred. The amount of any impairment is transferred to the pool of capitalized costs being amortized.
Capitalized costs are subject to the SEC full cost ceiling test. The ceiling test, which is performed each quarter, determines a limit, or ceiling, on the amount of property acquisition, exploration and development costs that can be capitalized. The ceiling under this test represents (a) the present value of estimated future net cash flows, excluding future cash outflows associated with settling asset retirement obligations that have been accrued on the balance sheet, using a discount factor of 10%, which is computed by applying current market prices of oil and gas (as adjusted for hedging) to estimated future production of proved oil and gas reserves as of the date of the latest balance sheet, less estimated future expenditures, plus (b) the cost of unevaluated properties not being depleted, less (c) income tax effects related to the differences between the book and tax basis of the properties. If capitalized costs, net of accumulated depreciation, depletion and amortization and related deferred income taxes, exceed the ceiling at the end of any quarter, a permanent impairment is required to be charged to earnings in that quarter. The Company's capitalized costs exceeded the full cost ceiling for the Company's oil and gas properties at December 31, 2008. As such, the Company recognized a pre-tax impairment of $182.8 million at December 31, 2008. Deferred income taxes of $74.6 million were recorded associated with this impairment. At June 30, 2010, 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, 2010.
Accumulated Other Comprehensive Loss. The components of Accumulated Other Comprehensive Loss, net of related tax effect, are as follows (in thousands):
|
|
At June 30, 2010 |
|
At September 30, 2009 |
Funded Status of the Pension and Other Post-Retirement Benefit Plans |
|
$(63,802) |
|
$(63,802) |
Cumulative Foreign Currency Translation Adjustment |
|
36 |
|
(104) |
Net Unrealized Gain on Derivative Financial Instruments |
|
24,406 |
|
18,491 |
Net Unrealized Gain on Securities Available for Sale |
|
1,207 |
|
3,019 |
Accumulated Other Comprehensive Loss |
|
$(38,153) |
|
$(42,396) |
Earnings Per Common Share. Basic earnings per common share is computed by dividing income available for common stock by the weighted average number of common shares outstanding for the period. Diluted earnings per common share reflects the potential dilution that could occur if securities or other contracts to issue common stock were exercised or converted into common stock. For purposes of determining earnings per common share, the only potentially dilutive securities the Company has outstanding are stock options and SARs. The diluted weighted average shares outstanding shown on the Consolidated Statements of Income reflects the potential dilution as a result of these stock options and SARs as determined using the Treasury Stock Method. Stock options and SARs that are antidilutive are excluded from the calculation of diluted earnings per common share. For both the quarter and nine months ended June 30, 2010, there were no stock options excluded as being antidilutive. There were 544,500 and 237,538 SARs excluded as being antidilutive for the quarter and nine months ended June 30, 2010, respectively. For both the quarter and nine months ended June 30, 2009, there were 765,000 stock options excluded as being antidilutive. In addition, there were 365,000 SARs excluded as being antidilutive for both the quarter and nine months ended June 30, 2009.
Stock-Based Compensation. During the nine months ended June 30, 2010, the Company granted 520,500 performance-based SARs having a weighted average exercise price of $52.10 per share. The weighted average grant date fair value of these SARs was $12.06 per share. These SARs may be settled in cash, in shares of common stock of the Company, or in a combination of cash and shares of common stock of the Company, as determined by the Company. These SARs are considered equity awards under the current authoritative guidance for stock-based compensation. The accounting for those SARs is the same as the accounting for stock options. There were no SARs granted during the quarter ended June 30, 2010. The performance-based SARs granted during the nine months ended June 30, 2010 vest and become exercisable annually in one-third increments, provided that a performance condition is met. The performance condition for each fiscal year, generally stated, is an increase over the prior fiscal year of at least five percent in certain oil and natural gas production of the Exploration and Production segment. The weighted average grant date fair value of these performance-based SARs granted during the nine months ended June 30, 2010 was estimated on the date of grant using the same accounting treatment that is applied for stock options, and assumes that the performance conditions specified will be achieved. If such conditions are not met or it is not considered probable that such conditions will be met, no compensation expense is recognized and any previously recognized compensation expense is reversed.
There were no stock options granted during the quarter or nine months ended June 30, 2010. The Company granted 4,000 restricted share awards (non-vested stock as defined by the current accounting literature) during the nine months ended June 30, 2010. The weighted average fair value of such restricted shares was $52.10 per share. There were no restricted share awards granted during the quarter ended June 30, 2010.
New Authoritative Accounting and Financial Reporting Guidance. In September 2006, the FASB issued authoritative guidance for using fair value to measure assets and liabilities. This guidance serves to clarify the extent to which companies measure assets and liabilities at fair value, the information used to measure fair value, and the effect that fair-value measurements have on earnings. This guidance is to be applied whenever assets or liabilities are to be measured at fair value. On October 1, 2008, the Company adopted this guidance for financial assets and financial liabilities that are recognized or disclosed at fair value on a recurring basis. The FASB's authoritative guidance for using fair value to measure nonfinancial assets and nonfinancial liabilities on a nonrecurring basis became effective during the quarter ended December 31, 2009. The Company's nonfinancial assets and nonfinancial liabilities were not impacted by this guidance during the nine months ended June 30, 2010. The Company has identified Goodwill as being the major nonfinancial asset that may be impacted by the adoption of this guidance. The impact of this guidance will be known when the Company performs its annual test for goodwill impairment at the end of the fiscal year; however, at this time, it is not expected to be material. The Company has identified Asset Retirement Obligations as a nonfinancial liability that may be impacted by the adoption of the guidance. The impact of this guidance will be known when the Company recognizes new asset retirement obligations. However, at this time, the Company believes the impact of the guidance will be immaterial. Additionally, in February 2010, the FASB issued updated guidance that includes additional requirements and disclosures regarding fair value measurements. The guidance now requires the gross presentation of activity within the Level 3 roll forward and requires disclosure of details on transfers in and out of Level 1 and 2 fair value measurements. It also provides further clarification on the level of disaggregation of fair value measurements and disclosures on inputs and valuation techniques. The Company has updated its disclosures to reflect the new requirements in Note 2 – Fair Value Measurements, except for the Level 3 roll forward gross presentation, which will be effective as of the Company's first quarter of fiscal 2012.
On December 31, 2008, the SEC issued a final rule on Modernization of Oil and Gas Reporting. The final rule modifies the SEC's reporting and disclosure rules for oil and gas reserves and aligns the full cost accounting rules with the revised disclosures. The most notable changes of the final rule include the replacement of the single day period-end pricing used to value oil and gas reserves with a 12-month average of the first day of the month price for each month within the reporting period. The final rule also permits voluntary disclosure of probable and possible reserves, a disclosure previously prohibited by SEC rules. Additionally, on January 6, 2010, the FASB amended the oil and gas accounting standards to conform to the SEC final rule on Modernization of Oil and Gas Reporting. The revised reporting and disclosure requirements will be effective for the Company's Form 10-K for the period ended September 30, 2010. Early adoption is not permitted. The Company is currently evaluating the impact that adoption of these rules will have on its consolidated financial statements and MD&A disclosures.
In March 2009, the FASB issued authoritative guidance that expands the disclosures required in an employer's financial statements about pension and other post-retirement benefit plan assets. The additional disclosures include more details on how investment allocation decisions are made, the plan's investment policies and strategies, the major categories of plan assets, the inputs and valuation techniques used to measure the fair value of plan assets, the effect of fair value measurements using significant unobservable inputs on changes in plan assets for the period, and disclosure regarding significant concentrations of risk within plan assets. The additional disclosure requirements are required for the Company's Form 10-K for the period ended September 30, 2010. The Company is currently evaluating the impact that adoption of this authoritative guidance will have on its consolidated financial statement disclosures.
In June 2009, the FASB issued amended authoritative guidance to improve and clarify financial reporting requirements by companies involved with variable interest entities. The new guidance requires a company to perform an analysis to determine whether the company's variable interest or interests give it a controlling financial interest in a variable interest entity. The analysis also assists in identifying the primary beneficiary of a variable interest entity. This authoritative guidance will be effective as of the Company's first quarter of fiscal 2011. Given the current organizational structure of the Company, the Company does not believe this authoritative guidance will have any impact on its consolidated financial statements.
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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.
Recurring Fair Value Measures |
At fair value as of June 30, 2010 | |||
(Thousands of Dollars) |
Level 1 |
Level 2 |
Level 3 |
Total |
|
|
|
|
|
|
|
|
| |
Cash Equivalents – Money Market Mutual Funds |
$ 303,261 |
$ - |
$ - |
$ 303,261 |
Derivative Financial Instruments: |
|
|
|
|
Commodity Futures Contracts - Gas |
576 |
- |
- |
576 |
Over the Counter Swaps – Oil |
- |
58 |
79 |
137 |
Over the Counter Swaps – Gas |
- |
41,184 |
- |
41,184 |
Other Investments: |
|
|
|
|
15,805 |
- |
- |
15,805 | |
Common Stock – Financial Services Industry |
5,762 |
- |
- |
5,762 |
Other Common Stock |
201 |
- |
- |
201 |
Hedging Collateral Deposits (1) |
8,222 |
- |
- |
8,222 |
Total |
$333,827 |
$ 41,242 |
$ 79 |
$ 375,148 |
|
|
| ||
Liabilities: |
|
|
|
|
Derivative Financial Instruments: |
|
|
|
|
Commodity Futures Contracts - Gas |
$ 2,521 |
$ - |
$ - |
$ 2,521 |
Over the Counter Swaps – Oil |
- |
- |
225 |
225 |
Over the Counter Swaps – Gas |
- |
30 |
- |
30 |
Total |
$ 2,521 |
$ 30 |
$ 225 |
$ 2,776 |
|
|
|
|
|
Total Net Assets/(Liabilities) |
$331,306 |
$ 41,212 |
$ (146) |
$ 372,372 |
(1) The 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.
(Thousands of Dollars) |
Level 1 |
Level 2 |
Level 3 |
Total |
|
| |||
Assets: |
|
|
|
|
Cash Equivalents |
$390,462 |
$ - |
$ - |
$ 390,462 |
Derivative Financial Instruments |
5,312 |
12,536 |
26,969 |
44,817 |
Other Investments |
24,276 |
- |
- |
24,276 |
Hedging Collateral Deposits |
848 |
- |
- |
848 |
Total |
$420,898 |
$ 12,536 |
$ 26,969 |
$ 460,403 |
|
|
|
|
|
Liabilities: |
|
|
|
|
Derivative Financial Instruments |
$ - |
$ 2,148 |
$ - |
$ 2,148 |
Total |
$ - |
$ 2,148 |
$ - |
$ 2,148 |
|
|
|
|
|
Total Net Assets/(Liabilities) |
$420,898 |
$ 10,388 |
$26,969 |
$ 458,255 |
Derivative Financial Instruments
At June 30, 2010, the derivative financial instruments reported in Level 1 consist of NYMEX futures contracts used in the Company's Energy Marketing and Pipeline and Storage segments (at September 30, 2009, the derivative financial instruments reported in Level 1 consist of NYMEX futures used in the Company's Energy Marketing segment). Hedging collateral deposits of $6.4 million associated with these futures contracts have been reported in Level 1 as well. The derivative financial instruments reported in Level 2 consist of natural gas and some of the crude oil swap agreements used in the Company's Exploration and Production segment and natural gas swap agreements used in the Energy Marketing segment at June 30, 2010 (at September 30, 2009, the derivative financial instruments reported in Level 2 consist of natural gas swap agreements used in the Company's Exploration and Production and Energy Marketing segments). The fair value of these swap agreements is based on an internal, discounted cash flow model that uses observable inputs (i.e. LIBOR based discount rates and basis differential information, if applicable, at active natural gas/crude oil trading markets). At June 30, 2010, the derivative financial instruments reported in Level 3 consist of a majority of the Exploration and Production segment's crude oil swap agreements (at September 30, 2009, all of the Exploration and Production segment's crude oil swap agreements were reported as Level 3). Hedging collateral deposits of $1.8 million associated with these oil swap agreements have been reported in Level 1. The fair value of the crude oil swap agreements is based on an internal, discounted cash flow model that uses both observable (i.e. LIBOR based discount rates) and unobservable inputs (i.e. basis differential information of crude oil trading markets with low trading volume). Based on an assessment of the counterparties' credit risk, the fair market value of the price swap agreements reported as Level 2 and Level 3 assets have been reduced by $0.7 million and $0.9 million at June 30, 2010 and September 30, 2009, respectively. The fair market value of the price swap agreements reported as Level 2 liabilities at September 30, 2009 have been reduced by less than $0.1 million based on an assessment of the Company's credit risk. (Note: As the fair value of the price swap agreements reported as Level 2 and 3 liabilities at June 30, 2010 was minor and the hedging collateral sufficiently covered the liabilities, there was no credit reserve recorded for the Level 2 and 3 liabilities at June 30, 2010.) These credit reserves were determined by applying default probabilities to the anticipated cash flows that the Company is either expecting from its counterparties or expecting to pay to its counterparties.
The tables listed below provide reconciliations of the beginning and ending net balances for assets and liabilities measured at fair value and classified as Level 3 for the quarter and nine months ended June 30, 2010 and 2009, respectively. For the quarter ended June 30, 2010, no transfers in or out of Level 1 or Level 2 occurred.
Fair Value Measurements Using Unobservable Inputs (Level 3) | |||||
(Thousands of Dollars) |
|
Total Gains/Losses – Realized and Unrealized |
|
| |
|
March 31, 2010 |
Included in Earnings |
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 – Realized and Unrealized |
|
| |
|
September 30, 2009 |
Included in Earnings |
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.
Fair Value Measurements Using Unobservable Inputs (Level 3) | |||||
(Thousands of Dollars) |
|
Total Gains/Losses – Realized and Unrealized |
|
| |
|
March 31, 2009 |
Included in Earnings |
Included in Other Comprehensive Income (Loss) |
Transfer In/Out of Level 3 |
June 30, 2009 |
|
|
|
|
| |
Derivative Financial Instruments(2) |
$79,159 |
$(13,662)(1) |
$(22,459) |
$(8,492) |
$34,546 |
(1) Amounts are reported in Operating Revenues in the Consolidated Statement of Income for the three months ended June 30, 2009.
(2) Derivative Financial Instruments are shown on a net basis.
Fair Value Measurements Using Unobservable Inputs (Level 3) | |||||
(Thousands of Dollars) |
|
Total Gains/Losses – Realized and Unrealized |
|
| |
|
September 30, 2008 |
Included in Earnings |
Included in Other Comprehensive Income (Loss) |
Transfer In/Out of Level 3 |
June 30, 2009 |
|
|
|
|
| |
Derivative Financial Instruments(2) |
$6,333 |
$(49,443)(1) |
$86,148 |
$(8,492) |
$34,546 |
(1) Amounts are reported in Operating Revenues in the Consolidated Statement of Income for the nine months ended June 30, 2009.
(2) Derivative Financial Instruments are shown on a net basis.
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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:
|
June 30, 2010 |
September 30, 2009 | ||
|
Carrying Amount |
Fair Value |
Carrying Amount |
Fair Value |
Long-Term Debt |
$1,249,000 |
$1,372,413 |
$1,249,000 |
$1,347,368 |
Other Investments. Investments in life insurance are stated at their cash surrender values or net present value as discussed below. Investments in an equity mutual fund and the stock of an insurance company (marketable equity securities), as discussed below, are stated at fair value based on quoted market prices.
Other investments include cash surrender values of insurance contracts (net present value in the case of split-dollar collateral assignment arrangements) and marketable equity securities. The values of the insurance contracts amounted to $54.6 million at June 30, 2010 and $54.2 million at September 30, 2009. The fair value of the equity mutual fund was $15.8 million at June 30, 2010 and September 30, 2009. The gross unrealized loss on this equity mutual fund was $1.4 million at June 30, 2010 and $1.0 million at September 30, 2009. Management does not consider this investment to be other than temporarily impaired. The fair value of the stock of an insurance company was $5.8 million at June 30, 2010 and $8.3 million at September 30, 2009. The gross unrealized gain on this stock was $3.4 million at June 30, 2010 and $5.9 million at September 30, 2009. The insurance contracts and marketable equity securities are primarily informal funding mechanisms for various benefit obligations the Company has to certain employees.
Derivative Financial Instruments. The Company is exposed to certain risks relating to its ongoing business operations. The primary risk managed by using derivative instruments is commodity price risk in the Exploration and Production, Energy Marketing and Pipeline and Storage segments. The Company enters into futures contracts and over-the-counter swap agreements for natural gas and crude oil to manage the price risk associated with forecasted sales of gas and oil. The Company also enters into futures contracts and swaps to manage the risk associated with forecasted gas purchases, storage of gas, withdrawal of gas from storage to meet customer demand, and the potential decline in the value of gas held in storage. The duration of the 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, 2010 and September 30, 2009 as shown in the table below.
|
Fair Values of Derivative Instruments | |||
|
(Thousands of Dollars) | |||
|
Asset Derivatives |
Liability Derivatives | ||
Derivatives Designated as Hedging Instruments |
Consolidated Balance Sheet Location |
Fair Value |
Consolidated Balance Sheet Location |
Fair Value |
Commodity 2010 |
Fair Value of |
$ 41,897 |
Fair Value of |
|
Commodity |
Fair Value of |
$ 44,817 |
Fair Value of |
$ 2,148 |
The following table discloses the fair value of derivative contracts on a gross-contract basis as opposed to the net-contract basis presentation on the Consolidated Balance Sheets at June 30, 2010 and September 30, 2009.
|
Fair Values of Derivative Instruments | |
|
(Thousands of Dollars) | |
Derivatives Designated as Hedging Instruments |
Gross Asset Derivatives |
Gross Liability Derivatives |
|
Fair Value |
Fair Value |
Commodity Contracts – at June 30, 2010 |
$ 52,984 |
$ 13,863 |
Commodity Contracts – at September 30, 2009 |
$ 63,601 |
$ 20,932 |
Cash flow hedges
For derivative instruments that are designated and qualify as a cash flow hedge, the effective portion of the gain or loss on the derivative is reported as a component of other comprehensive income (loss) and reclassified into earnings in the period or periods during which the hedged transaction affects earnings. Gains and losses on the derivative representing either hedge ineffectiveness or hedge components excluded from the assessment of effectiveness are recognized in current earnings.
At June 30, 2010, the 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 |
41.4 Bcf (all short positions) |
Crude Oil |
2,803,000 Bbls (all short positions) |
At June 30, 2010, the Company's Energy Marketing segment had the following commodity derivative contracts (futures contracts and swaps) outstanding to hedge forecasted sales (where the Company uses short positions to mitigate the risk associated with natural gas price decreases and its impact on decreasing revenues and earnings) and purchases (where the Company uses long positions (i.e. positions that pay-off in the event of commodity price increases) to mitigate the risk of increasing natural gas prices, which would lead to increased purchased gas expense and decreased earnings):
Commodity |
Units |
Natural Gas |
4.8 Bcf (4.5 Bcf short positions (forecasted storage withdrawals) and 0.3 Bcf long positions (forecasted storage injections)) |
At June 30, 2010, the 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, 2010, the Company's Exploration and Production segment had $39.9 million ($23.5 million after tax) of net hedging gains included in the accumulated other comprehensive income (loss) balance. It is expected that $26.1 million ($15.4 million after tax) of those gains will be reclassified into the Consolidated Statement of Income within the next 12 months as the expected sales of the underlying commodities occur. See Note 1, under Accumulated Other Comprehensive Income (Loss), for the after-tax gain pertaining to derivative financial instruments (Net Unrealized Gain (Loss) on Derivative Financial Instruments in Note 1 includes the Exploration and Production, Energy Marketing and Pipeline and Storage segments).
At June 30, 2010, the Company's Energy Marketing segment had $1.4 million ($0.8 million after tax) of net hedging gains included in the accumulated other comprehensive income (loss) balance. It is expected that the full amount will be reclassified into the Consolidated Statement of Income within the next 12 months as the sales and purchases of the underlying commodities occur. See Note 1, under Accumulated Other Comprehensive Income (Loss), for the after-tax gain pertaining to derivative financial instruments (Net Unrealized Gain (Loss) on Derivative Financial Instruments in Note 1 includes the Exploration and Production, Energy Marketing and Pipeline and Storage segments).
At June 30, 2010, the Company's Pipeline and Storage segment had $0.1 million (less than $0.1 million after tax) of net hedging gains included in the accumulated other comprehensive income (loss) balance. It is expected that the full amount will be reclassified into the Consolidated Statement of Income within the next 12 months as the expected sales of the underlying commodities occur. See Note 1, under Accumulated Other Comprehensive Income (Loss), for the after-tax gain pertaining to derivative financial instruments (Net Unrealized Gain (Loss) on Derivative Financial Instruments in Note 1 includes the Exploration and Production, Energy Marketing and Pipeline and Storage segments)
| ||||||||
The Effect of Derivative Financial Instruments on the Statement of Financial Performance for the Three Months Ended June 30, 2010 and 2009 (Thousands of Dollars) | ||||||||
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, | |||
|
2010 |
2009 |
|
2010 |
2009 |
|
2010 |
2009 |
Commodity Contracts – Exploration & Production segment |
$16,445 |
$(23,013) |
Operating Revenue |
$ 11,592 |
$22,940 |
Operating Revenue |
$ - |
$ 158 |
Commodity Contracts – Energy Marketing segment |
$ 519 |
$ (1,433) |
Purchased Gas |
$ 238 |
$ 1,913 |
Operating Revenue |
$ - |
$ - |
Commodity Contracts – Pipeline & Storage segment |
$ (436) |
$ - |
Operating Revenue |
$ - |
$ - |
Operating Revenue |
$ - |
$ - |
Total |
$16,528 |
$(24,446) |
|
$ 11,830 |
$24,853 |
|
$ - |
$ 158 |
| ||||||||
The Effect of Derivative Financial Instruments on the Statement of Financial Performance for the Nine Months Ended June 30, 2010 and 2009 (Thousands of Dollars) | ||||||||
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, | |||
|
2010 |
2009 |
|
2010 |
2009 |
|
2010 |
2009 |
Commodity Contracts – Exploration & Production segment |
$32,910 |
$117,764 |
Operating Revenue |
$29,170 |
$ 71,324 |
Operating Revenue |
$ - |
$ 424 |
Commodity Contracts – Energy Marketing segment |
$ 5,821 |
$ 9,410 |
Purchased Gas |
$ (209) |
$ 21,328 |
Operating Revenue |
$ - |
$ - |
Commodity Contracts – Pipeline & Storage segment |
$ 577 |
$ - |
Operating Revenue |
$ 511 |
$ 1,290 |
Operating Revenue |
$ - |
$ - |
Commodity Contracts – All Other (1) |
$ - |
$ 183 |
Purchased Gas |
$ - |
$ (682) |
Purchased Gas |
$ - |
$ - |
Total |
$39,308 |
$127,357 |
|
$29,472 |
$ 93,260 |
|
$ - |
$ 424 |
(1) There were no open hedging positions at June 30, 2010. As such there is no mention of these positions in the preceeding sections of this footnote. |
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, 2010, the Company's Energy Marketing segment had fair value hedges covering approximately 10.8 Bcf (9.3 Bcf of fixed price sales commitments (all long positions), 1.3 Bcf of fixed price purchase commitments (all short positions) and 0.2 Bcf of storage hedges (all short positions)). For derivative instruments that are designated and qualify as a fair value hedge, the gain or loss on the derivative as well as the offsetting gain or loss on the hedged item attributable to the hedged risk completely offset each other in current earnings, as shown below.
Consolidated
Statement of Income Gain/(Loss) on Derivative Gain/(Loss) on Commitment
Operating Revenues $(892,512) $892,512
Purchased Gas $(502,195) $502,195
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, 2010 (In Thousands) |
Commodity Contracts – Energy Marketing segment (1) |
Operating Revenues |
$(893) |
Commodity Contracts – Energy Marketing segment (2) |
Purchased Gas |
$(456) |
Commodity Contracts – Energy Marketing segment (3) |
Purchased Gas |
$(46) |
|
|
$(1,395) |
(1) Represents hedging of fixed price sales commitments of natural gas. | ||
(2) Represents hedging of fixed price purchase commitments of natural gas. | ||
(3) Represents hedging of natural gas held in storage. |
The Company may be exposed to credit risk on any of the derivative financial instruments that are in a gain position. Credit risk relates to the risk of loss that the Company would incur as a result of nonperformance by counterparties pursuant to the terms of their contractual obligations. To mitigate such credit risk, management performs a credit check, and then on a quarterly basis monitors counterparty credit exposure. The majority of the Company's counterparties are financial institutions and energy traders. The Company has over-the-counter swap positions with eleven counterparties of which ten of the eleven counterparties are in a net gain position. On average, the Company had $4.1 million of credit exposure per counterparty in a gain position at June 30, 2010. BP Energy Company (an affiliate of BP Corporation North America, Inc.) was one of the ten counterparties in a gain position. At June 30, 2010, the Company had a $7.2 million receivable with BP Energy Company. The Company considered the credit quality of BP Energy Company (as it does with all of its counterparties) in determining hedge effectiveness and believes the hedges remain effective. The Company had not received any collateral from these counterparties at June 30, 2010 since the Company's gain position on such derivative financial instruments had not exceeded the established thresholds at which the counterparties would be required to post collateral.
As of June 30, 2010, nine of the eleven counterparties to the Company's outstanding derivative instrument contracts (specifically the over-the-counter swaps) had a common credit-risk related contingency feature. In the event the Company's credit rating increases or falls below a certain threshold (the lower of the S&P or Moody's Debt Rating), the available credit extended to the Company would either increase or decrease. A decline in the Company's credit rating, in and of itself, would not cause the Company to be required to increase the level of its hedging collateral deposits (in the form of cash deposits, letters of credit or treasury debt instruments). If the Company's outstanding derivative instrument contracts were in a liability position and the Company's credit rating declined, then additional hedging collateral deposits would be required. At June 30, 2010, the fair market value of the derivative financial instrument assets with a credit-risk related contingency feature was $27.1 million according to the Company's internal model (discussed in Note 2 - Fair Value Measurements). At June 30, 2010, the fair market value of the derivative financial instrument liability with a credit-risk related contingency feature was $0.3 million according to the Company's internal model (discussed in Note 2 – Fair Value Measurements). The Company's internal model may yield a different fair value than the fair value determined by the Company's counterparties. The Company's requirement to post hedging collateral deposits is based on the fair value determined by the Company's counterparties. For its over-the-counter crude oil swap agreements, which are in a liability position, the Company was required to post $1.8 million in hedging collateral deposits at June 30, 2010. This is discussed in Note 1 under Hedging Collateral Deposits.
For its exchange traded futures contracts which are in a liability position, the Company had posted $5.8 million in hedging collateral, and for its exchange traded futures contracts which are in an asset position, the Company had posted $0.6 million in hedging collateral as of June 30, 2010. As these are exchange traded futures contracts, there are no specific credit-risk related contingency features. The Company posts hedging collateral based on open positions and margin requirements it has with its counterparties.
The 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):
|
June 30, | |
|
2010 |
2009 |
Current Income Taxes |
|
|
Federal |
$42,323 |
$95,526 |
State |
9,914 |
25,528 |
|
|
|
Deferred Income Taxes |
|
|
Federal |
50,079 |
(67,051) |
State |
13,734 |
(18,443) |
116,050 |
35,560 | |
Deferred Investment Tax Credit |
(523) |
(523) |
|
|
|
Total Income Taxes |
$115,527 |
$35,037 |
|
|
|
Presented as Follows: |
|
|
Other Income |
$(523) |
$(523) |
Income Tax Expense |
116,050 |
35,560 |
|
|
|
$115,527 |
$35,037 |
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):
|
June 30, | |
|
2010 |
2009 |
U.S. Income Before Income Taxes |
$303,039 |
$108,747 |
|
|
|
|
| |
Statutory Rate of 35% |
$106,064 |
$38,061 |
|
|
|
Increase (Reduction) in Taxes Resulting From: |
|
|
State Income Taxes |
15,371 |
4,605 |
Domestic Production Activities Deduction |
(711) |
(1,790) |
Miscellaneous |
(5,197) |
(5,839) |
|
|
|
Total Income Taxes |
$115,527 |
$35,037 |
Significant components of the Company's deferred tax liabilities and assets are as follows (in thousands):
|
At June 30, 2010 |
At September 30, 2009 |
Deferred Tax Liabilities: |
|
|
Property, Plant and Equipment |
$781,581 |
$733,581 |
Pension and Other Post-Retirement Benefit Costs |
177,124 |
178,440 |
Other |
55,716 |
54,977 |
Total Deferred Tax Liabilities |
1,014,421 |
966,998 |
|
|
|
Deferred Tax Assets: |
|
|
Pension and Other Post-Retirement Benefit Costs |
(214,161) |
(212,299) |
Other |
(97,595) |
(144,686) |
Total Deferred Tax Assets |
(311,756) |
(356,985) |
Total Net Deferred Income Taxes |
$702,665 |
$610,013 |
|
|
|
|
| |
Net Deferred Tax Liability/(Asset) – Current |
$(32,893) |
$(53,863) |
Net Deferred Tax Liability – Non-Current |
735,558 |
663,876 |
Total Net Deferred Income Taxes |
$702,665 |
$610,013 |
During the quarter ended March 31, 2010, the Company reduced its deferred tax asset relating to the Medicare Part D subsidy by $30 million to reflect changes made by the fundamental health care reform legislation enacted during that quarter. In conjunction with the reduction of the deferred tax asset, the Company reduced its Medicare Part D regulatory liability by $30 million. In the Company's Utility and Pipeline and Storage segments, the Company's post-retirement benefit plans are funded by a component of tariff rates charged to customers. As such, prior to the fundamental health care reform legislation, the $30 million tax benefit had been recorded as a regulatory liability in anticipation of flowing that tax benefit back to customers through adjusted tariff rates.
Regulatory liabilities representing the reduction of previously recorded deferred income taxes associated with rate-regulated activities that are expected to be refundable to customers amounted to $67.1 million and $67.0 million at June 30, 2010 and September 30, 2009, respectively. Also, regulatory assets representing future amounts collectible from customers, corresponding to additional deferred income taxes not previously recorded because of prior ratemaking practices, amounted to $138.4 million at both June 30, 2010 and September 30, 2009.
The Company files federal and various state income tax returns. The Internal Revenue Service (IRS) is currently conducting an examination of the Company for fiscal 2009 and fiscal 2010 in accordance with the Compliance Assurance Process ("CAP"). The CAP audit employs a real time review of the Company's books and tax records by the IRS that is intended to permit issue resolution prior to the filing of the tax return. While the federal statute of limitations remains open for fiscal 2007 and later years, IRS examinations for fiscal 2008 and prior years have been completed and the Company believes such years are effectively settled.
The Company is also subject to various routine state income tax examinations. The Company's operating subsidiaries mainly operate in four states which have statutes of limitations that generally expire between three to four years from the date of filing of the income tax return.
As of June 30, 2010, the Company had a federal net operating loss carryover of $21.2 million. This carryover, which is available as a result of an acquisition, expires in varying amounts between 2023 and 2029. Although this loss carryover is subject to certain annual limitations, no valuation allowance was recorded because of management's determination that the amount will be fully utilized during the carryforward period.
|
|
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 $14.8 million.
At June 30, 2010, the Company has estimated its remaining clean-up costs related to former manufactured gas plant sites and third party waste disposal sites (including the former manufactured gas plant site discussed above) will be in the range of $17.5 million to $21.7 million. The minimum estimated liability of $17.5 million, which includes the $14.8 million discussed above, has been recorded on the Consolidated Balance Sheet at June 30, 2010. The Company expects to recover these environmental clean-up costs through rate recovery.
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 – Business Segment Information
The Company has four reportable segments: Utility, Pipeline and Storage, Exploration and Production and Energy Marketing. The division of the Company's operations into the reported segments is based upon a combination of factors including differences in products and services, regulatory environment and geographic factors.
The data presented in the tables below reflect the reported segments and reconciliations to consolidated amounts. As stated in the 2009 Form 10-K, the Company evaluates segment performance based on income before discontinued operations, extraordinary items and cumulative effects of changes in accounting (when applicable). When these items are not applicable, the Company evaluates performance based on net income. There have been no changes in the basis of segmentation nor in the basis of measuring segment profit or loss from those used in the Company's 2009 Form 10-K. There have been no material changes in the amount of assets for any operating segment from the amounts disclosed in the 2009 Form 10-K.
Quarter Ended June 30, 2010 (Thousands) |
|
|
|
|
| ||||
|
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 |
$ 9,859 |
$ 224 |
$354,127 | |
Intersegment Revenues |
$ 2,653 |
$19,466 |
$ - |
$ - |
$ 22,119 |
$ 1,418 |
$ (23,537) |
$ - | |
Segment Profit: Net Income (Loss) |
$ 5,969 |
$7,234 |
$ 27,883 |
$ 1,411 |
$ 42,497 |
$ 186 |
$ (98) |
$ 42,585 | |
Nine Months Ended June 30, 2010 (Thousands) |
|
|
|
|
|
| |||
|
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 |
$ 35,568 |
$ 652 |
$1,482,518 | |
Intersegment Revenues |
$ 13,315 |
$ 60,289 |
$ - |
$ - |
$ 73,604 |
$ 1,418 |
$ (75,022) |
$ - | |
Segment Profit: Net Income (Loss) |
$ 62,254 |
$ 30,036 |
$ 85,046 |
$ 8,472 |
$ 185,808 |
$ 2,925 |
$ (1,221) |
$ 187,512 |
Quarter Ended June 30, 2009 (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 |
$158,310 |
$30,791 |
$ 97,619 |
$ 71,894 |
$358,614 |
$ 8,269 |
$ 228 |
$367,111 | |
Intersegment Revenues |
$ 2,940 |
$20,033 |
$ - |
$ - |
$ 22,973 |
$ 374 |
$ (23,347) |
$ - | |
Segment Profit: Net Income (Loss) |
$ 5,396 |
$ 9,221 |
$ 27,083 |
$ 1,331 |
$ 43,031 |
$ (1,086) |
$ 959 |
$ 42,904 | |
Nine Months Ended June 30, 2009 (Thousands) |
|
|
|
|
|
| |||
|
Utility |
Pipeline and Storage |
Exploration and Production |
Energy Marketing |
Total Reportable Segments |
All Other |
Corporate and Intersegment Eliminations |
Total Consolidated | |
Revenue from External Customers |
$1,009,962 |
$105,904 |
$281,410 |
$350,445 |
$1,747,721 |
$ 30,523 |
$ 675 |
$1,778,919 | |
Intersegment Revenues |
$ 13,339 |
$ 62,026 |
$ - |
$ - |
$ 75,365 |
$ 3,890 |
$ (79,255) |
$ - | |
Segment Profit: Net Income (Loss) |
$ 60,303 |
$ 41,582 |
$(38,366) |
$ 7,509 |
$ 71,028 |
$ (46) |
$ 2,728 |
$ 73,710 |
|
Note 8 - Intangible Assets
The components of the Company's intangible assets were as follows (in thousands):
|
At June 30, 2010 |
|
At September 30, 2009 | ||
|
Gross Carrying Amount |
Accumulated Amortization |
Net Carrying Amount |
|
Net Carrying Amount |
Intangible Assets Subject to Amortization: |
|
|
|
|
|
Long-Term Transportation Contracts |
$4,701 |
$(2,926) |
$1,775 |
|
$2,071 |
Long-Term Gas Purchase Contracts |
31,864 |
(13,451) |
18,413 |
|
19,465 |
|
$36,565 |
$(16,377) |
$20,188 |
|
$21,536 |
|
|
|
|
|
|
Aggregate Amortization Expense: (Thousands) |
|
|
|
|
|
Three Months Ended June 30,2010 |
$449 |
|
|
|
|
Three Months Ended June 30,2009 |
$497 |
|
|
|
|
Nine Months Ended June 30, 2010 |
$1,348 |
|
|
|
|
Nine Months Ended June 30, 2009 |
$1,547 |
|
|
|
|
The gross carrying amount of intangible assets subject to amortization at June 30, 2010 remained unchanged from September 30, 2009. The only activity with regard to intangible assets subject to amortization was amortization expense as shown in the table above. Amortization expense for the long-term transportation contracts is estimated to be $0.1 million for the remainder of 2010 and $0.4 million annually for 2011, 2012, 2013 and 2014. Amortization expense for the long-term gas purchase contracts is estimated to be $0.4 million for the remainder of 2010 and $1.4 million annually for 2011, 2012, 2013 and 2014.
|
Note 9 – Retirement Plan and Other Post-Retirement Benefits
Components of Net Periodic Benefit Cost (in thousands):
Three months ended June 30, |
|
|
|
|
|
|
Retirement Plan |
|
Other Post-Retirement Benefits | ||
|
|
|
|
|
|
|
2010 |
2009 |
|
2010 |
2009 |
|
|
|
|
|
|
Service Cost |
$3,249 |
$2,728 |
|
$1,075 |
$950 |
Interest Cost |
11,077 |
11,709 |
|
6,254 |
6,875 |
Expected Return on Plan Assets |
(14,585) |
(14,489) |
|
(6,583) |
(7,904) |
Amortization of Prior Service Cost |
164 |
183 |
|
(427) |
(268) |
Amortization of Transition Amount |
- |
- |
|
135 |
566 |
Amortization of Losses |
5,410 |
1,419 |
|
6,470 |
2,318 |
Net Amortization and Deferral for |
|
|
|
|
|
Regulatory Purposes (Including |
|
|
|
|
|
Volumetric Adjustments) (1) |
(920) |
2,255 |
|
(569) |
3,878 |
|
|
|
|
|
|
Net Periodic Benefit Cost |
$4,395 |
$3,805 |
|
$6,355 |
$6,415 |
Nine months ended June 30, |
|
|
|
|
|
|
Retirement Plan |
|
Other Post-Retirement Benefits | ||
|
|
|
|
|
|
|
2010 |
2009 |
|
2010 |
2009 |
|
|
|
|
|
|
Service Cost |
$9,747 |
$8,185 |
|
$3,224 |
$2,851 |
Interest Cost |
33,231 |
35,127 |
|
18,763 |
20,624 |
Expected Return on Plan Assets |
(43,756) |
(43,468) |
|
(19,751) |
(23,711) |
Amortization of Prior Service Cost |
492 |
548 |
|
(1,282) |
(805) |
Amortization of Transition Amount |
- |
- |
|
405 |
1,699 |
Amortization of Losses |
16,230 |
4,257 |
|
19,411 |
6,953 |
Net Amortization and Deferral for |
|
|
|
|
|
Regulatory Purposes (Including |
|
|
|
|
|
Volumetric Adjustments) (1) |
2,896 |
12,853 |
|
2,919 |
16,232 |
|
|
|
|
|
|
Net Periodic Benefit Cost |
$18,840 |
$17,502 |
|
$23,689 |
$23,843 |
(1) The 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.
Prior to the adoption of authoritative guidance related to accounting for defined benefit pension and other postretirement plans, the Company used June 30th as the measurement date for financial reporting purposes. In 2009, in accordance with the current authoritative guidance for defined benefit pension and other postretirement plans, the Company began measuring the Plan's assets and liabilities for its pension and other post-retirement benefit plans as of September 30th, its fiscal year end. In making this change and as permitted by the current authoritative guidance, the Company recorded fifteen months of pension and post-retirement benefits expense during fiscal 2009. As allowed by the authoritative guidance, these costs were calculated using June 30, 2008 measurement date data. Three of those months pertained to the period of July 1, 2008 to September 30, 2008. The pension and other post-retirement benefit costs for that period amounted to $3.8 million and were recorded by the Company during the nine months ended June 30, 2009 as a $3.4 million increase to Other Regulatory Assets in the Company's Utility and Pipeline and Storage segments and a $0.4 million ($0.2 million after tax) adjustment to earnings reinvested in the business. In addition, for the Company's non-qualified benefit plan, benefit costs of $1.3 million were recorded by the Company during the nine months ended June 30, 2009 as a $0.4 million increase to Other Regulatory Assets in the Company's Utility segment and a $0.9 million ($0.6 million after tax) adjustment to earnings reinvested in the business.
Employer Contributions. During the nine months ended June 30, 2010, the Company contributed $20.2 million to its tax-qualified, noncontributory defined-benefit retirement plan (Retirement Plan) and $21.4 million to its VEBA trusts and 401 (h) accounts for its other post-retirement benefits. In the remainder of 2010, the Company does not expect to contribute to the Retirement Plan. It is likely that the Company will have to fund larger amounts to the Retirement Plan subsequent to fiscal 2010 in order to be in compliance with the Pension Protection Act of 2006. In the remainder of 2010, the Company expects to contribute approximately $4.1 million to its VEBA trusts and 401(h) accounts.